EPA

TVA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park, NC 27711
EPA-600/7-81-01
February 1981
Tennessee Valley
Authority
Office of Power
Energy Demonstrations
and Technology
Muscle Shoals, AL 35660
EOT-127
        Technical Review of Dry
        FGD  Systems  and  Economic
        Evaluation of Spray Dryer
        FGD  Systems


        Interagency
        Energy/Environment
        R&D  Program  Report

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                 RESEARCH REPORTING SERIES


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

    1. Environmental Health Effects Research

    2. Environmental Protection Technology

    3. Ecological Research

    4. Environmental Monitoring

    5. Socioeconomic Environmental Studies

    6. Scientific and Technical Assessment Reports  (STAR)

    7. Interagency Energy-Environment Research and Development

    8. "Special" Reports

    9. Miscellaneous Reports

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

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                                EPA-600/7-81-014
                                TV A EOT-127
                                    February  1981
   Technical  Review of Dry
FGD Systems  and  Economic
  Evaluation  of Spray Dryer
           FGD  Systems
                    by

           T.A. Burnett and K.D, Anderson

              TVA, Office of Power
     Division of Energy Demonstrations and Technology
           Muscle Shoals, Alabama 35660


       EPA Interagency Agreement No. D9-E721-BI
           Program Element No. INE827


         EPA Project Officer Theodore G. Brna

        Industrial Environmental Research Laboratory
     Office of Environmental Engineering and Technology
           Research Triangle Park, NC 27711
                 Prepared for


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

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                              DISCLAIMER
     This report was prepared by the Tennessee Valley Authority and has
been reviewed by the Office of Environmental Engineering and Technology,
U.S. Environmental Protection Agency, and approved for publication.
Approval does not signify that the contents necessarily reflect the
views and policies of the Tennessee Valley Authority or the U.S.  Environ-
mental Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
                                  ii

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                               ABSTRACT
     The report gives results of an extensive study of dry flue gas
desulfurization (FGD) systems, involving dry injection of absorbents or
spray drying.  (The study was undertaken because they appear to have
both process and economic advantages over wet FGD.)  Design concepts
(e.g., type of absorbent and atomizer, approach to flue gas saturation
temperature, and particulate collection method) remain to be demonstrated
at full scale.  Most vendors prefer a lime slurry system with rotary
atomizers and fabric filter particulate collection, while all systems
now under contract to utilities apply to low-sulfur coal.  S02 removal
efficiencies sufficient for high-sulfur coal applications at stable
operating conditions and economically feasible absorbent utilization
rates have not yet been demonstrated.  In conceptual design cost com-
parisons based on a new 500-MW utility power generation unit, a lime
spray dryer/fabric filter combination had lower capital investments and
annual revenue requirements for 0.7% sulfur western coal and both 0.7%
and 3.5% sulfur eastern coal than a wet limestone scrubbing process.
With lignite fuel, similar cost advantages were evident for dry (relative
to wet) FGD.  The capital investment advantage of dry over wet FGD
increased with increasing coal sulfur content.
                                  iii

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                               CONTENTS
Abstract ............................    ±±±
Figures  ............................   viii
Tables .............................      x
Abbreviations and Conversion Factors ..............    xiv
Acknowledgements ........................     xv

Executive Summary  .......................   xvii

Introduction ..........................      ^

Conclusions  ..................                      o

Spray Dryer FGD Technology  ...................      /
  Background ..........................      5
    Technical Comparison of Spray Dryer and Wet Scrubbing FGD   .      5
    Process Chemistry   .....................      g
    Fly Ash Composition  ....................      o
    Importance of Coal Characteristics .............      9
    Comparison of Absorbents  ..................     -^Q
    Two-Fluid Nozzle and Rotary Atomization   ..........     -,-,
  Basic Process Design Considerations  .............     •, c
    Flue Gas Temperature ................ ....     1fi
    Stoichiometry and Absorbent Utilization   ..........     ,,
    Particulate Matter Collection   ...............     «..
    Summary  ..........................     22

Dry Absorption Technology   ...................     23
  Background ..........................     23
  Nahcolite  ..........................     24
    Process Chemistry   .....................     2A
    Injection Systems   .....................    26
    Waste Disposal .......................    29
  Trona  ............................     ^
  Past Studies and Current Status
    Past Studies
    Current Status
Development and Current Status of Spray Dryer FGD Processes  .  .    35
  Babcock & Wilcox .......................    4]
    Background and Current Status of Development ........    41
    Conceptual Design  .....................    44
    Technical Considerations ..................    44
  Buell-Envirotech/Anhydro, Inc .................    40
    Background and Current Status of Development ........    40
    Conceptual Design  .....................    c-f,
    Technical Considerations ..................    r
                                    v

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  Carborundum Environmental Systems 	   52
    Background and Current Status of Development  	   52
    Conceptual Design 	   53
    Technical Considerations  	   55
  Combustion Engineering  	   55
    Background and Current Status of Development  	   55
    Conceptual Design 	   57
    Technical Considerations  	   57
  Ecolaire Environmental Corporation  	   61
    Background and Current Status of Development  	   61
    Conceptual Design 	   62
    Technical Considerations  	   62
  Joy Manufacturing/Niro Atomizer, Inc	   63
    Background and Current Status of Development  	   63
    Conceptual Design 	   67
    Technical Considerations  	   67
  Research-Cottrell, Inc	70
    Background and Current Status of Development  	   70
    Conceptual Design 	   71
    Technical Considerations  	   71
  Rockwell International/¥heelabrator-Frye, Inc	73
    Background and Current Status of Development  	   73
    Conceptual Design 	   75
    Technical Considerations  	   76

Design and Economic Premises  	   73
  Design Premises 	   73
    Emission Standards  	   78
    Fuel	79
    Power Plant Design	79
    Power Plant Operation	79
    Flue Gas Composition	79
    FGD System Design	81
    Raw Materials	82
    Waste Disposal	82
  Economic Premises	84
    Capital Costs 	   84
    Capital Investment Estimates  	   87
    Annual Revenue Requirements 	   89

Systems Estimated 	   91
  Lignite Case	91
    Lime Spray Dryer Process  	   92
    Limestone Scrubbing Process 	  101
  Low—Sulfur Western Coal Case	113
    Soda Ash Spray Dryer Process	113
    Lime Spray Dryer Process  	  117
    Limestone Scrubbing Process 	  124
                                   VI

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  Low-Sulfur Eastern Coal Case	124
    Lime Spray Dryer Process 	 124
    Limestone Scrubbing Process  	 140
  High-Sulfur Eastern Coal Case	140
    Lime Spray Dryer Process 	 140
    Limestone Scrubbing Process  	 158

Economic Evaluation and Comparison 	 178
  Accuracy of Estimates  	 178
  Lignite Case—Capital Investment 	 179
    Results	179
    Comparison	179
  Lignite Case—Annual Revenue Requirements  	 184
    Results	184
    Comparison	184
  Lignite Case—Sensitivity Analysis 	 188
    Sensitivity to Absorbent Prices  	 188
    Sensitivity to Raw Material Stoichiometry  	 190
  Low-Sulfur Western Coal Case—Capital Investment 	 193
    Results	193
    Comparison	193
  Low-Sulfur Western Coal Case—Annual Revenue Requirements  . 199
    Results	199
    Comparison	199
  Low-Sulfur Western Coal Case—Sensitivity Analysis 	 205
    Sensitivity to Absorbent Prices  	 205
    Sensitivity to Raw Material Stoichiometry  	 207
  Low-Sulfur Eastern Coal Case—Capital Investment 	 207
    Results	207
    Comparison	207
  Low-Sulfur Eastern Coal Case—Annual Revenue Requirements  . 213
    Results	213
    Comparison	215
  Low-Sulfur Eastern Coal Case—Sensitivity Analysis 	 218
    Sensitivity to Raw Material Prices 	 218
    Sensitivity to Raw Material Stoichiometry  	 220
  High-Sulfur Eastern Coal Case—Capital Investment  	 220
    Results	220
    Comparison	220
  High-Sulfur Eastern Coal Case—Annual Revenue Requirements  . 226
    Results	226
    Comparison	229
  High-Sulfur Eastern Coal Case—Sensitivity Analysis   ....  230
    Sensitivity to Absorbent Prices  	  230
    Sensitivity to Absorbent Stoichiometry  .  	  232
  Discussion of Results  	  235

References	240
                                 Vll

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                                FIGURES
Number                                                             Page

   1    Design of rotary atomizer 	    12
   2    Design of two-fluid nozzle atomizer 	    14
   3    The effects of recycle and degree of approach to flue gas
        saturation temperature on S02 removal efficiency and raw
        material stoichiometry for a lime spray dryer FGD
        system	,	    19
   4    S02 removal efficiency as a function of stoichiometric
        ratio and injection method for nahcolite	    27
   5    S02 removal efficiency as a function of stoichiometric
        ratio for nahcolite injection	    33
   6    Conceptual design for the Babcock & Wilcox spray dryer
        FGD process	    45
   7    Design of two-fluid nozzle atomizer for the Babcock &
        Wilcox spray dryer FGD process  	    46
   8    Spray dryer/reactor design for the Babcock & Wilcox
        FGD process	    47
   9    Conceptual design for the Carborundum spray dryer FGD
        process	    54
  10    Spray dryer design for the Combustion Engineering FGD
        process	    58
  11    Design of two-fluid nozzle atomizer for the Combustion
        Engineering spray dryer FGD process 	    59
  12    Spray dryer design for the Joy/Niro FGD process  	    68
  13    Spray dryer design for the Research-Cottrell FGD
        process	    72
  14    Spray dryer design for the Rockwell International FGD
        process	    77
  15    Lignite case.  Lime spray dryer process.  Flow diagram   .    93
  16    Lignite case.  Lime spray dryer process.  Plot plan  ...    94
  17    Lignite case.  Limestone scrubbing process.  Flow
        diagram	   102
  18    Lignite case.  Limestone scrubbing process.  Plot plan   .   1Q3
  19    Low-sulfur western coal case.  Soda ash spray dryer
        process.  Flow diagram	   114
  20    Low-sulfur western coal case.  Soda ash spray dryer
        process.  Plot plan	   115
  21    Loxv-sulfur western coal case.  Lime spray dryer process.
        Flow diagram	   121
  22    Low-sulfur western coal case.  Lime spray dryer process.
        Plot plan	   122
                                  viii

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                         FIGURES (continued)
Number
  23    Low-sulfur western coal case.  Limestone scrubbing
        process.  Flow diagram	   130
  24    Low-sulfur western coal case.  Limestone scrubbing
        process.  Plot plan	   131
  25    Low-sulfur eastern coal case.  Lime spray dryer process.
        Flow diagram	   141
  26    Low-sulfur eastern coal case.  Lime spray dryer process.
        Plot plan	   142
  27    Low-sulfur eastern coal case.  Limestone scrubbing
        process.  Flow diagram	   148
  28    Low-sulfur eastern coal case.  Limestone scrubbing
        process.  Plot plan	   149
  29    High-sulfur eastern coal case.  Lime spray dryer
        process.  Flow diagram	   159
  30    High-sulfur eastern coal case.  Lime spray dryer
        process.  Plot plan	   160
  31    High-sulfur eastern coal case.  Limestone scrubbing
        process.  Flow diagram	   167
  32    High-sulfur eastern coal case.  Limestone scrubbing
        process.  Plot plan	   168
  33    Lignite case—sensitivity of the first-year annual
        revenue requirements to the delivered raw material
        cost	   189
  34    Lignite case—sensitivity of the first-year annual
        revenue requirements to the raw material stoichiometry
        in the absorber	   192
  35    Low-sulfur western coal case—sensitivity of the first-
        year annual revenue requirements to the delivered raw
        material cost	   206
  36    Law-sulfur western coal case—sensitivity of the first-
        year annual revenue requirements to the raw material
        stoichiometry in  the absorber	   209
  37    Low-sulfur eastern coal case—sensitivity of the first-
        year annual revenue requirements to the delivered raw
        material cost	   219
  38    Low-sulfur eastern coal case—sensitivity of the first-
        year annual revenue requirements to the raw material
        stoichiometry in  the absorber	   222
  39    High-sulfur eastern coal case—sensitivity of the first-
        year annual revenue requirements to the delivered raw
        material cost	   231
  40    High-sulfur eastern coal case—sensitivity of the first-
        year annual revenue requirements to the raw material
        stoichiometry in  the absorber	   234
                                  IX

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                                TABLES
Number                                                             Page

 S-l    Companies Active in Spray Dryer-Based FGD Systems for
        Utility Applications 	       xx
 S-2    Contract Awards for Spray Dryer-Based FGD Systems  .  .      xxi
 S-3    Spray Dryer Pilot Plants and Demonstration Units for
        FGD	     xxii
 S-4    FGD System Design Conditions 	   xxviii
 S-5    Capital Investment Summary 	     xxxi
 S-6    Annual Revenue Requirements Summary  	   xxxiii
  1     Fly Ash Analysis Comparison  	        8
  2     Contract Awards for Spray Dryer-Based FGD Systems  .  .       37
  3     Spray Dryer Pilot Plants and Demonstration Units for
        FGD	       38
  4     Coal Compositions	       80
  5     Base-Case Flue Gas Compositions and Flow Rates ....       80
  6     FGD System Design Conditions 	       83
  7     Levelized Annual Capital Charges for Regulated Utility
        Financing	       86
  8     Projected 1984 Unit Costs for Raw Materials,  Labor,
        and Utilities	       90
  9     Lignite Case Lime Spray Process Material Balance ...       95
 10     Lignite Case Lime Spray Dryer Process Equipment List,
        Description, and Cost	       96
 11     Lignite Case Limestone  Scrubbing Process Material
        Balance	     104
 12     Lignite Case Limestone  Scrubbing Process Equipment
        List, Description, and  Cost	     107
 13     Low-Sulfur Western Coal Case Soda Ash Spray Dryer
        Process Material Balance 	     116
 14     Low-Sulfur Western Coal Case Soda Ash Spray Dryer
        Process Equipment List, Description, and Cost  ....     118
 15     Low-Sulfur Western Coal Case Lime Spray Dryer Process
        Material Balance 	     123
 16     Low-Sulfur Western Coal Case Lime Spray Dryer Process
        Equipment List, Description,  and Cost  	      125
 17     Low-Sulfur Western Coal Case Limestone Scrubbing
        Process Material Balance 	      132
 18     Low-Sulfur Western Coal Case Limestone Scrubbing
        Process Equipment List, Description, and Cost  ....      134

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                          TABLES (continued)
Number
 19    Low-Sulfur Eastern Coal Case Lime Spray Dryer Process
       Material Balance 	      143
 20    Low-Sulfur Eastern Coal Case Lime Spray Dryer Process
       Equipment List, Description, and Cost  	      144
 21    Low-Sulfur Eastern Coal Case Limestone Scrubbing
       Process Material Balance 	      150
 22    Low-Sulfur Eastern Coal Case Limestone Scrubbing
       Process Equipment List, Description, and Cost  ....      152
 23    High-Sulfur Eastern Coal Case Lime Spray Dryer Process
       Material Balance 	      161
 24    High-Sulfur Eastern Coal Case Lime Spray Dryer Process
       Equipment List, Description, and Cost  	      162
 25    High-Sulfur Eastern Coal Case Limestone Scrubbing
       Process Material Balance 	      169
 26    High-Sulfur Eastern Coal Case Limestone Scrubbing
       Process Equipment List, Description, and Cost  ....      171
 27    Lignite Case Capital Investment Lime Spray Dryer
       Process	      180
 28    Lignite Case Capital Investment Limestone Scrubbing
       Process	      181
 29    Lignite Case Direct Investments and Capital
       Investments	      179
 30    Lignite Case Summary of the Capital Investments  .  .   .      182
 31    Lignite Case Capital Investments 	      184
 32    Lignite Case Annual Revenue Requirements Lime Spray
       Dryer Process	      185
 33    Lignite Case Annual Revenue Requirements Limestone
       Scrubbing Process  	      186
 34    Lignite Case First-Year and Levelized Annual Revenue
       Requirements 	      187
 35    Lignite Case Summary of First-Year Annual Revenue
       Requirements 	      188
 36    Lignite Case Delivered Unit Raw Material Costs
       Assumed for the Sensitivity Analysis 	      188
 37    Lignite Case Comparison of Capital Investment and
       First-Year Unit Revenue Requirements for the Lime
       Spray Dryer Process at Various Raw Material
       Stoichiometries  	      191
 38    Low-Sulfur Western Coal Case Capital Investment Soda
       Ash Spray Dryer Process  	      194
 39    Low-Sulfur Western Coal Case Capital Investment Lime
       Spray Dryer Process	      195
 40    Low-Sulfur Western Coal Case Capital Investment
       Limestone Scrubbing Process  	      196
                                   XI

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                          TABLES (continued)
Number
 41    Low-Sulfur Western Coal Case Direct Investments and
       Capital Investments 	     193
 42    Low-Sulfur Western Coal Case Summary of the Capital
       Investments	     197
 43    Low-Sulfur Western Coal Case Capital Investments  . .  .     199
 44    Low-Sulfur Western Coal Case Annual Revenue Require-
       ments Soda Ash Spray Dryer Process	     200
 45    Low-Sulfur Western Coal Case Annual Revenue Require-
       ments Lime Spray Dryer Process  	     201
 46    Low-Sulfur Western Coal Case Annual Revenue Require-
       ments Limestone Scrubbing Process 	     202
 47    Low-Sulfur Western Coal Case First-Year and Levelized
       Annual Revenue Requirements 	     203
 48    Low-Sulfur Western Coal Case Summary of First-Year
       Annual Revenue Requirements 	     204
 49    Low-Sulfur Western Coal Case Delivered Unit Raw
       Material Costs Assumed for the Sensitivity Analysis .  .     205
 50    Low-Sulfur Western Coal Case Comparison of Capital
       Investment and First-Year Unit Revenue Requirements
       for the Lime Spray Dryer Process at Various Raw
       Material Stoichiometries  	     208
 51    Low-Sulfur Eastern Coal Case Capital Investment Lime
       Spray Dryer Process	     210
 52    Low-Sulfur Eastern Coal Case Capital Investment Lime-
       stone Scrubbing Process 	     211
 53    Low-Sulfur Eastern Coal Case Direct Investments and
       Capital Investments   	     212
 54    Low-Sulfur Eastern Coal Case Summary of the Capital
       Investments	     213
 55    Low-Sulfur Eastern Coal Case Capital Investments  . .  .     215
 56    Low-Sulfur Eastern Coal Case Annual Revenue Require-
       ments Lime Spray Dryer Process  	     214
 57    Low-Sulfur Eastern Coal Case Annual Revenue Require-
       ments Limestone Scrubbing Process 	     216
 58    Low-Sulfur Eastern Coal Case First-Year and Levelized
       Annual Revenue Requirements 	     215
 59    Low-Sulfur Eastern Coal Case Summary of First-Year
       Annual Revenue Requirements 	     217
 60    Low-Sulfur Eastern Coal Case Delivered Unit Raw
       Material Costs Assumed for the Sensitivity Analysis .  .     218
 61    Low-Sulfur Eastern Coal Case Comparison of Capital
       Investment and First-Year Unit Revenue Requirements for
       the Lime Spray Dryer Process at Various Raw Material
       Stoichiometries 	     221
                                  xii

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                          TABLES (continued)
Number
 62    High-Sulfur Eastern Coal Case Capital Investment Lime
       Spray Dryer Process	   223
 63    High-Sulfur Eastern Coal Case Capital Investment Lime-
       stone Scrubbing Process 	   224
 64    High-Sulfur Eastern Coal Case Direct Investments and
       Capital Investments 	   225
 65    High-Sulfur Eastern Coal Case Summary of the Capital
       Investments	   225
 66    High-Sulfur Eastern Coal Case Capital Investments ....   226
 67    High-Sulfur Eastern Coal Case Annual Revenue Requirements
       Lime Spray Dryer Process  	   227
 68    High-Sulfur Eastern Coal Case Annual Revenue Requirements
       Limestone Scrubbing Process 	   228
 69    High-Sulfur Eastern Coal Case First-Year and Levelized
       Annual Revenue Requirements 	   229
 70    High-Sulfur Eastern Coal Case Summary of First-Year
       Annual Revenue Requirements 	   230
 71    High-Sulfur Eastern Coal Case Delivered Unit Raw Material
       Costs Assumed for the Sensitivity Analysis  	   232
 72    High-Sulfur Eastern Coal Case Comparison of Capital
       Investment and First-Year Unit Revenue Requirements for
       the Lime Spray Dryer Process at Various Raw Material
       Stoichiometries 	   233
 73    Capital Investment Summary  	   236
 74    Annual Revenue Requirements Summary 	   237
                                 xiii

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                    ABBREVIATIONS AND CONVERSION FACTORS
ABBREVIATIONS
Btu
°C
dia
ESP
°F
FD
FGD
ft
ft/sec
g
gal
gpm
gr
hr
ID
in.
kg
actual cubic feet
British thermal unit
degrees Celsius
diameter
electrostatic precipitator
degrees Fahrenheit
forced draft
flue gas desulfurization
feet
feet per second
gram
gallon
gallons per minute
grain
hour
induced draft
inch
kilogram
                                        kW
                                        kWh
                                        Ib
                                        k
                                        L/G
                                        M
                                        min
                                        mol
                                        MW
                                        ppm
                                        sec
                                        SIP
                                        SOX
                                        vol
                                        wt
                                        yr
kiloliter
kilowatt
kilowatthour
pound
thousand (kilo)
liquid to gas ratio
million (mega)
minute
mole
megawatt (electrical)
parts per million  (volume)
second
standard cubic feet
State Implementation Plan
sulfur oxides
volume
weight
year
CONVERSION FACTORS
To convert from English units
                                To metric units
                                                                    Multiply
                                                                       by
acres
British thermal units
degrees Fahrenheit minus 32
feet
square feet
cubic feet
cubic feet per minute
gallons (U.S.)
gallons per minute
grains per cubic foot
horsepower
inches
pounds (mass)
pounds per cubic foot
pounds (force) per square inch
miles
standard cubic feet per minute
  (60°F)
tons  (short)a
                        hectares                              0.405
                        kilocalories                          0.252
                        degrees Celsius                      0.5556
                        centimeters                           30.48
                        square meters                        0.0929
                        cubic meters                        0.02832
                        cubic meters per second            0.000472
                        liters _                              3.785
                        liters per second                   0.06308
                        grams per cubic meter                 2.288
                        kilowatts                             0.746
                        centimeters                            2.54
                        kilograms                            0.4536
                        kilograms per cubic meter             16.02
                        Pascals (Newton per square meter)      6895
                        meters                                 1609

                        normal cubic meters per hour (0°C)   1.6077
                        metric tons                          0.9072
a.  All tons, including tons of sulfur, are expressed in short tons.
                                    xiv

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                           ACKNOWLEDGEMENTS
     Partial support for this study was provided  by the  Department  of
Energy by means of pass-through funds to the Environmental  Protection
Agency.
                                  xv

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                  TECHNICAL REVIEW OF DRY FGD SYSTEMS

          AND ECONOMIC EVALUATION OF SPRAY DRYER FGD SYSTEMS



                           EXECUTIVE SUMMARY
INTRODUCTION

     Dry scrubbing technology for flue gas desulfurization (FGD),
particularly that phase in which spray dryers are used, is currently
receiving considerable attention in the utility industry.  An alkaline
solution or slurry is atomized in the flue gas and evaporates to dryness
while reacting with the SOX and HC1.  The resulting reaction products
are collected, usually along with fly ash, and disposed of as a dry
waste.  This method has several potential advantages over wet scrubbing
FGD because it eliminates the complexity, operating problems, and liquid
wastes associated with the large volume of scrubbing liquid used in wet
scrubbing.  Conversely, high removal efficiencies are more difficult to
attain and a highly reactive (i.e., nonlimestone) absorbent must be
used.

     In the past few years a number of companies and consortia have
entered the spray dryer FGD field with pilot studies, and several have
contracted to build commercial units.  Most of the pilot studies and all
of the utility units are for lignite or low-sulfur western coal applications,
where removal efficiencies and absorbent consumption are usually lower
than with high-sulfur coals and, in some cases, the high alkalinity of
the fly ash can supplement the absorbent.  The rapid growth of spray
dryer FGD is in part a result of the increasing use of western coal, but
its rapid growth also owes, in some degree, to its derivation from the
proven industrial technologies of spray drying and particulate matter
collection.  The development of fabric filter fly ash collection for
utility use has been particularly advantageous.  In many cases, companies
active in spray dryer FGD have backgrounds in either particulate collection
or spray drying.

     Spray dryer FGD is related, and in some aspects evolved from,
earlier efforts in dry injection of absorbents.  Although many of these
studies were disappointing in terms of S02 removal efficiency, absorbent
utilization, and availability of economical absorbents, interest in such
uncomplicated approaches to FGD has continued.  The development of spray
dryer FGD, its general technical aspects, and its status through mid-
1980 are discussed as a portion of this study.  In addition, the history
and current status of dry injection processes are reviewed.

                                  xvii

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     An important aspect of spray dryer FGD is its economics in relation
to limestone wet scrubbing processes, in which the absorbent is less
expensive.  Although various vendors have made economic comparisons,
there have been no independent economic comparisons applicable to general
utility applications.  As a portion of this study, economic comparisons
of a lime spray dryer process and a limestone scrubbing process are
made for a lignite, a low-sulfur western coal, and a low- and a high-
sulfur eastern coal applications.  A soda ash spray dryer process is
also evaluated for the low-sulfur western coal case.
BACKGROUND

     Dry absorption of S02 received considerable attention during the
early 1970's because it appeared to have several technical advantages
over wet scrubbing.  Of the potential absorbents, only sodium-based
materials were found to be sufficiently reactive and, of these, nahcolite
proved the most effective.  However, due to economic and environmental
considerations, commercial mining of the large nahcolite reserves did
not (and has not) occurred, and questions about the widespread availability
of nahcolite in the future forced a search for other absorbents.  Because
other more readily available raw materials are either too expensive or
not sufficiently reactive, development of dry absorption FGD slowed in
the mid-1970's, and primary emphasis focused on the technology to make
the readily available reactants more reactive without losing the potential
significant advantages of the dry FGD system.  This search (along with
the simultaneous development of the regenerable aqueous carbonate process)
led to the development of the spray dryer FGD process.

     Recently interest in dry absorption has resurfaced with several
pilot-plant programs.  For absorbents, nahcolite is still the primary
focus but trona is also being evaluated.  Trona, unlike nahcolite, has
the advantage that it is already being mined in commercial quantities
for the production of soda ash.  Although early results appear promising,
at least for applications where only 70% S02 removal is required, significant
amounts of development work remain to be completed.

     Most spray dryer designs for FGD are direct adaptations of the
standard designs so widely used in other industries.  Typically in
these uses,  a hot gas passes downward through a cylindrical vessel,
mixing with a solution or slurry atomized by either rotary or nozzle
atomizers.  The liquid is evaporated while the droplets are in suspension,
and the particles are collected in the conical bottom, in external
collection equipment, or both.   Complete evaporation in suspension is
important and is achieved by suitable design and control of operating
conditions.   In FGD applications, the latitude of these controls is
limited.  The flue gas temperature is fixed by boiler efficiency require-
ments and may vary as the boiler load changes and the absorbent rate is
controlled by S02 removal requirements.  In addition, it is economically
important that absorbent consumption is minimized.   These limitations
may complicate applications in which high S0~ removal efficiencies are
required.

                                 xviii

-------
     The reactions of S02 and HC1 with the absorbent proceed rapidly
while surface liquid is present, but more slowly when the absorbent is
dry.  An important design consideration is, therefore, that the saturation
temperature be approached as closely as possible and that the particles
remain in contact with the flue gas as long as possible.  Whatever these
conditions, however, effective reaction rates require a reactive absorbent.
Limestone has not proven satisfactory, leaving soda ash and lime as the
only economically practical absorbents generally available in sufficient
quantities.  Soda ash is more reactive but also more expensive, and the
soluble waste of sodium sulfites and sulfates produced has raised questions
of its practicality for disposal in areas of high rainfall.  Lime is
less reactive and more difficult to handle because it must be slaked and
then handled as a slurry.  It is, however, less expensive and it produces
a relatively insoluble waste of calcium sulfites and sulfates.  At
higher S02 removal efficiencies the absorbent must sometimes be used at
high stoichiometric ratios, particularly if lime is used.  Utilization
can sometimes be increased by reslurrying and recycling the waste.
Also, if a highly alkaline fly ash is produced, as is usual with western
coals, the fly ash alkalinity can supplement the absorbent.  Coal moisture
content is also a factor.  Flue gas produced by low-rank, high-moisture
coals has a higher saturation temperature, limiting the amount of water
that can be added, compared with high-rank coals.  This may place
restrictions on absorbent liquid concentrations that affect the SC>2
removal efficiency.

     The methods by which vendors treat these considerations differ.  In
most cases, a conventional spray dryer design, rotary atomizers, lime
absorbent, and fabric filter baghouse particulate collection are used.
The approach to saturation is regulated by controlling water addition
rates.  Some warm (300°F) flue gas from the air heater may be bypassed
around the spray dryers and recombined with the cleaned gas for reheating
before the flue gas enters the baghouse.  In extreme cases for high S02
removal efficiencies some hot (700 F) flue gas may be bypassed around
both the air heater  (at the expense of boiler thermal efficiency) and
the spray dryers to attain sufficient reheating.

     Important exceptions to the above design exist.  One major vendor
uses two-fluid nozzles and ESP collection and one commercial unit will
use soda ash.  Absorbent utilization is increased in some cases by
recycling the waste, while in other cases it is not.  The degree to
which saturation temperature is approached (and thus the possibility of
wet upsets) varies somewhat between vendors.  In general, the vendor's
approach to design reflects his experience and the requirements of. the
particular application.  The technical and economic advantages of such
design variations as type of atomizer, waste recycle, and ESP or baghouse
collection remain, in large part, to be demonstrated in further investigation
and application.

     In general, based on current practice and trends, soda ash processes
will not use waste recycle, will rarely use hot  (700 F) gas bypass, and
will use warm gas bypass  (bypass around the spray dryer) only  for very
high S02 removal efficiencies under unusual flue gas conditions.  Lime

                                  xviv

-------
processes will use waste recycle, will usually use warm gas bypass, and
will occasionally use hot gas bypass (particularly when high (over 85%)
862 removal efficiencies are required).
DEVELOPMENT AND CURRENT STATUS

     The first concerted spray dryer FGD studies in the United States
were begun in the early 1970's by Rockwell International.  These, however,
were part of a regenerable process study rather than the waste-producing
nonregenerable processes that are the subject of this study.  It was not
until 1977 that extensive spray dryer FGD studies began.  These received
considerable impetus when dry injection studies at the Basin Electric
Power Cooperative's Leland Olds Station were expanded to include spray
dryers.  Four companies subsequently operated spray dryer FGD pilot
plants there and at other Basin Electric power plants as a bid quali-
fication requirement for FGD units on new Basin Electric construction.

     Subsequently, other organizations became active in spray dryer FGD
studies.  In mid-1980 ten companies or consortia (shown in Table S-l)
were active in spray dryer FGD investigations and six had contracted for
units for ten utility and five industrial installations.  These contract
awards are shown in Table S-2.  All of the commercial utility applications
are for low-sulfur lignite or western coal, as has been the preponderance
of pilot-scale studies  (shown in Table S-3).
                TABLE  S-l.  COMPANIES ACTIVE IN SPRAY

                     DRYER-BASED FGD SYSTEMS FOR

                         UTILITY APPLICATIONS
                Babcock  & Wilcox
                Buell-Envirotech/Anhydro, Inc.
                Carborundum Environmental Systems
                Combustion Engineering, Inc.
                Ecolaire Environmental Corporation
                Flakt, Inc.
                Joy Manufacturing/Niro Atomizer, Inc.
                Research-Cottrell
                Rockwell International
                Wheelabrator-Frye, Inc.
     Of the contracted utility units, all will use lime as the alkali
raw material except the Coyote Station in Beulah, North Dakota.  All
vendors except Babcock & Wilcox (B&W) use atomizers in spray dryers of

                                   xx

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                        Table S-2.   CONTRACT AWARDS FOR SPRAY DRYER-BASED FGD SYSTEMS
X
X

Size,
Installation gross
Utility Boiler
Coyote Unit 1 456
Laramie River Unit 3 575
Antelope Valley Unit 1 440
Shiras Unit 3 44
Stanton Unit 2 63
Craig Unit 3 447
Holcomb Unit 1 319
Rawhide Unit 1 260
Springerville Unit 1 350
Springerville Unit 2 350
Industrial Boiler
Strathmore Paper Co. 14e
Celanese Fibers Co. 22e
Calgon 17e
University of Minnesota 83e
Argonne National Lab . 29e

Based on contact with vendors
Fuel
MW type (% S)

Lignite (0.78)
Subbituminous (0.54)
Lignite (0.68)
Subbituminous (1.5)
Lignite (0.77)
Bituminous (0.70)
Subb i tuminous (0.30)
Subbituminous (0.29)
Subbituminous (0.69)
Subbituminous (0.69)

Bituminous (2.0-2.5)
Bituminous (1.0-3.5)
-
Subbituminous (0.6-0.
Bituminous (3.5)

S02
removal , %

70
85
62
80
73
87
80
80
61
61

75
70-80
75
7) 70
80

Alkali raw
material

Soda ash
Lime
Lime
Lime
Lime
Lime
Lime
Lime
Lime
Lime

Lime
Lime
Soda ash
Lime
Lime

Startup
date

4/81
4/82
4/82
9/82
9/82
4/83
6/83
12/83
2/85
9/86

7/79
1/80
6/81
9/81
9/81


Vendor

RI/WFa
B&WC
Joy/Nirob
Buell/Anhydro
R-Cd
B&W
Joy /Niro
Joy /Niro
. Joy /Niro
Joy/Niro

Mikropul
RI/WF
Niro/Joy
Carborundum
Niro/Joy

representing the status of announced contracts through October 1980.
a. Rockwell International/Wheelabrator-Frye.
b. Western Precipitation Division of Joy Manufacturing
c. Babcock & Wilcox.
d. Research-Cottrell.
e. Based on 2,900 aft3/MW.



Company /Niro



Atomizer, Inc












-------
                 TABLE  S-3.   SPRAY DRYER PILOT PLANTS AND DEMONSTRATION UNITS  FOR FGD
H-
H-
                       Company
Babcock & Wilcox

Alliance Research Center
W. J. Neal Station Unit 2
  (Basin Electric)

Jim Bridger Unit 3
  (Pacific Power and Light)

Buell-Envirotech/Anhydro, Inc.

Copenhagen Anhydro Laboratory

Martin Drake Unit 6
  (City of Colorado Springs)
                                      Size,
                                    kaft3/min
   Fuel
type (% S)
   Primary
alkali tested
                                                   1.5     Various coals

                                                   8.0     Lignite (0.4)
                                                   3.0
                  Lime

                  Lime
                                                 120.0     Subbituminous  (0.6)   Lime
                  Lime, soda
                   ash
                                                  20.0     Subbituminous  (0.5)   Lime,  trona
            Carborundum  Environmental  Systems

            Carborundum  Knoxville Laboratory


            Carborundum  Knoxville Laboratory

            Leland Olds  Station Unit 1
             (Basin Electric)
                                        0.1
                                        1.0     Bituminous (0.5)
                                       15.0     Lignite (0.6)
                  Lime, NHo,
                   NaHC03, and
                   nahcolite
                  Lime, Na2C03,
                   and fly ash

                  Lime, NH3,
                   and soda ash
                                                (continued)

-------
                                              TABLE  S-3 (continued)
N
X
H-
                          Company
                                      Size,
                                    kaft3/min
       Fuel
    type (% S)
   Primary
alkali tested
Combustion Engineering

Sherburne County Unit 1
 (Northern States Power)              20.0

Gadsden Unit 1
 (Alabama Power)                      20.0

Ecolaire Environmental Corporation

Gerald Gentleman Unit lb
 (Nebraska Public Power)              10.0

Joy Manufacturing/Niro Atomizer, Inc.

Niro Laboratory Copenhagen             3.0
              Hoot  Lake Unit  2
               (Ottertail  Power)
                                      20.0
Subbituminous (1.0)   Lime


Bituminous (1.8)      Lime




Subbituminous (0.3)   Lime
Lignite
Lime, MgO, and
 soda ash

Lime, soda ash
              Riverside Station Units  6  &  7
               (Northern States Power)
                                     640.0      Subbituminous  (1.0)   Lime
                                                Petroleum coke  (4.0)
                                            (continued)

-------
                                           TABLE S-3 (continued)
                         Company
                                      Size,
                                    kaf t-Vmin
       Fuel
    type  (% S)
   Primary
alkali tested
            Research-Cottrell,  Inc.

            Big Brown Unit  2
              (Texas Utilities)

            Comanche Unit 2
              (Public Service of Colorado)
                                      10.0
                                      10.0
Lignite (1.0)
Lime
Subbituminous (0.5)   Lime
x
x
H-
Rockwell International/Wheelabrator-Frye,  Inc.

                                       5.0

                                      10.0
            Stork-Bowen Engineering Laboratory
            Leland Olds Station
              (Basin Electric)
            Joliet Station
             (Commonwealth Edison)

            Sherburne County Unit 3
             (Northern States Power)

            Jim Bridger
             (Pacific Power and Light)
                                       5.0
                                       5.0
                                       5.0
Lignite (0.6)
Lime, soda ash

Lime
Subbituminous (0.5)   Lime
Subbituminous (0.8)   Lime
Subbituminous (0.6)   Lime
            Based on contacts with vendors and representing information through June 1980.
            a.  Propane burner with S02 spiking.
            b.  Mobile unit.

-------
conventional design and fabric filter baghouse collection.   B&W uses
two-fluid nozzles,  evolved from boiler oil burners,  in horizontal chambers
and prefers ESP's for particulate collection.   B&W manufactures  all  of
its FGD equipment.   The other vendors are either consortia which include
a spray dryer manufacturer or they have an exclusive agreement with  a
spray dryer manufacturer.

     B&W began spray dryer FGD studies in 1977, initially with a commercial
spray dryer/reactor and subsequently with their own two-fluid nozzle
atomizer and horizontal reactor design they call a dry scrubbing reactor.
Steam was first used as the atomizing fluid; more recently air has been
favored.  B&W uses ESP's for particulate collection, believing them  to
be a more developed technology and more amenable to wet upset.  At first
B&W did not generally favor waste recycle, however the results of their
demonstration unit at Jim Bridger Station have pursuaded them that waste
recycle should be used.

     Close approach to the flue gas saturation temperature in the absorber
and particle size reduction to attain efficient absorbent utilization
are also emphasized in their design.  In addition to their two pilot
units, B&W is conducting continuing studies at their Alliance, Ohio,
research center.  B&W has been awarded contracts for two utility applications.

     The Buell Emission Control Division of Envirotech Corporation and
Anhydro, Inc., of Copenhagen, Denmark, are currently developing a spray
dryer FGD system as a joint venture.  Buell is a designer and marketer
of particulate control equipment while Anhydro is a designer and marketer
of spray dryers.  The pilot unit at the Martin Drake Station uses a
single rotary atomizer and baghouse particulate collection.  In addition,
proprietary waste recycle systems are being evaluated.  Buell/Anhydro
has been awarded the contract for one utility system.

     Carborundum Environmental Systems is a subsidiary of Kennecott
Copper Corporation based in Knoxville, Tennessee.  Carborundum has
recently signed a licensing agreement with Kochiwa Kakohki Company,
Inc., a Japanese spray dryer manufacturer.  The spray dryers for the
Carborundum system will be manufactured in the United States, while  the
rotary atomizers may be manufactured in either Japan or the United
States.  Baghouses for the spray dryer FGD system will be designed and
built by Carborundum.  Much of the development work for Carborundum's
spray dryer FGD system was done at a 100 ft-Vmin bench-scale unit at
their test facility at the University of Tennessee in Knoxville.  The
initial pilot studies were made to qualify for bids on Basin Electric
units.  The present design uses a conventional spray dryer with three
rotary atomizers and baghouse particulate collection with no waste
recycle.  Carborundum has been awarded a contract for an industrial
boiler system.

     While Combustion Engineering has been installing limestone-based
FGD systems for several years, they first entered into the development
of spray dryer FGD systems in 1978.  Construction of their first pilot-
plant unit began in February 1979.  During 1979 an exclusive agreement

                                  xxv

-------
was concluded with James Howden Holida BV (The Netherlands) for use of
their baghouse technology.  The current design consists of a conventional
spray dryer with multiple nozzle atomizers and baghouse particulate
collection.  Compressed air is the atomizing fluid.  In addition to
their pilot plant at Gadsden Station, a 30-MW demonstration unit is
currently planned.

     Ecolaire Environmental Corporation is the subsidiary of Ecolaire
Corporation that markets Ecolaire's spray dryer FGD process.  Although
other subsidiaries in the Ecolaire Corporation have been supplying
equipment to the electric utility industry for many years, before the
design and construction of their mobile demonstration unit  (MDU) in
1979, Ecolaire had very little experience in the design and operation of
FGD systems.  The MDU was erected in 1979 at a Nebraska power plant.
The unit has a conventional spray dryer using either a rotary or two-
fluid nozzle atomizer and fabric filters for particulate collection.

     The Western Precipitation Division of The Joy Manufacturing Company,
that markets fabric filter baghouses, and Niro Atomizer, Inc., that markets
spray dryers, have an exclusive agreement to market a spray dryer FGD
system.  Niro began FGD studies in Denmark in 1975.  The first pilot
plant was operated in 1978 to qualify to bid for Basin Electric units.
The Joy/Niro design consists of a spray dryer with one rotary atomizer
and a manifold that introduces flue gas both above and below the atomizer.
The particulate matter is collected both in the bottom of the spray
dryer and in baghouses.  Waste recycle, using the large particles from
the bottom of the spray dryer, is used for most applications.  Current
development work is being conducted in Niro's Copenhagen laboratory.
The demonstration unit at the Riverside Power Station will provide the
facilities for future (at least until 1983 when the agreement expires)
large-scale testing.  Joy/Niro has been awarded five utility contracts
and two industrial contracts.

     The Research-Cottrell system uses Komeline-Sanderson spray dryers
of conventional design with either a single or multiple rotary atomizers.
Part of the particulate matter is collected in the bottom of the spray
dryer and the rest is collected in the baghouse.  Waste recycle is
usually used.  Most details and test results are proprietary and little
published information is available.  The pilot plant at the Comanche
Station is partially funded by EPA, so results of these tests will be
available in 1981.  Research-Cottrell has been awarded one  contract for
a utility boiler.

     Until early 1980 Rockwell International and Wheelabrator-Frye,
Inc., had agreements to market spray dryer FGD systems based on Rockwell
International's experience in spray dryer FGD and Wheelabrator-Frye's
fabric filter technology.  This joint venture was dissolved in 1980 and
each will now market its own system.  The first Rockwell International
and Wheelabrator-Frye spray dryer pilot unit was operated at the Leland
Olds Station in 1977.  This and other pilot studies have provided considerable
data on the system.  The design consists of a conventional  spray dryer


                                  xxvi

-------
with three rotary atomizers and baghouse particulate collection.  Waste
recycle is used if the conditions warrant it.  Rockwell International and
Wheelabrator-Frye have been awarded two commercial contracts, one for a
utility system and one for an industrial application.
DESIGN AND ECONOMIC PREMISES

     The economic evaluations are based on flue gas cleaning (FGD and
fly ash) systems to meet the 1979 NSPS for a new 500-MW pulverized-coal-
fired utility boiler.  The FGD systems are designed with one redundant
scrubber train, a redundant feed preparation area, 50% emergency flue
gas bypass, and are costed as proven technology with no adjustments for
estimated stage of development.  The power plant is assumed to have a
30-year, 165,000-hour life and to operate 5,500 hours the first year.
Flue gas compositions are based on a 0.9% sulfur, 7.2% ash, 6,600 Btu/lb
lignite; a 0.7% sulfur, 9.7% ash, 9,700 Btu/lb western coal; a 0.7%
sulfur, 16% ash, 10,700 Btu/lb eastern coal; and a 3.5% sulfur, 16% ash,
10,700 Btu/lb eastern coal.  A Northern Great Plains location is used
for the lignite and the western coal cases; a midwestern location is
used for the eastern coal cases.  The spray dryer designs are generic
and are based on vendor information.  The limestone scrubbing system is
based on data from the EPA Shawnee test facility and general industry
information.  Design data for the absorbers are shown in Table S-4.

     Raw materials consist of commercial-grade soda ash at $145/ton,
pebble lime at $102/ton in the West and $75/ton in the East, and limestone
at $8.50/ton (all costs are in 1984 dollars).  The waste disposal sites
are one mile from the FGD facility.  They consist of a clay-lined pond
for the soda ash spray dryer process and landfills for the lime spray
dryer and limestone scrubbing wastes.

     The economics consist of study-grade capital investments, first-
year annual revenue requirements, and levelized annual revenue requirements.
The capital investments are based on major equipment costs developed
from flow diagrams and material balances and factored costs for installation
and ancillary equipment. These capital investments are estimated to have
an absolute accuracy of -20% to +40%.  However since the same estimation
methods were used for each evaluation, the accuracy for comparison is
much better, i.e., ±10%.  Capital investment costs are based on mid-1982
costs.

     First-year annual revenue'requirements consist of raw material,
operating, and overhead costs and levelized capital charges.  Revenue
requirements are based on 1984 costs.  The levelized annual revenue
requirements are factored to account for a 10% discount and a 6% inflation
rate over the life of the power plant.
                                 xxvii

-------
                                               TABLE S-4.   FGD  SYSTEM DESIGN CONDITIONS
X


3
H-
Lignite
Lime Limestone
spray dryer scrubbing
Absorbent
Bypass, %
Total FGD
Absorber
Removal
stoichiometrya

AP, in. H20

efficiency, %
Absorbent liquid, % solidsc
AP, in.H
L/G, gal
Exit gas
Effluent
Recombined
Reheat, °F
2° Jb
/kaf t
, wt % liquid
, % solids
gas, °F

1.2
22.5
12

83.5
22.5
2
0.3
0
100
170
—
1.1
28.1
8.6

90
60
2
80
0.1
15
180
—
Low-sulfur western
Soda ash
spray dryer
1.0
0
12

70
0
2
0.13
0
100
170
—
coal
Lime Limestone
spray dryer scrubbing
1.2
22
12

83
22.5
2
0.2
0
100
170
—
1.1
28.1
8.4

90
60
2
80
0.1
15
170
—
Low-sulfur
eastern coal
Lime Limestone
spray dryer scrubbing
1.3
19
12

83
3
2
0.3
0
100
170
—
1.1
25.2
8.5

90
60
2
80
0.1
15
160
10
High-sulfur eastern coal
Lime Limestone
spray dryer scrubbing
1.8
4b
12

89
17
2
0.3
0
100
170
-
1.
0
9.

90
60
2
90
0.
15
127
43
3

5





1



a.  Defined as mol  Ca/mol S02 absorbed for both the spray dryer and the limestone processes.


b.  Hot gas bypass.

c.  Excludes dilution water and recycle loop if used.

-------
SYSTEMS ESTIMATED

     For the lignite case a lime spray dryer process and a limestone
scrubbing process are evaluated.  For the low-sulfur western coal case,
the soda ash and lime spray dryer processes and the limestone scrubbing
process are evaluated.  For the eastern coal cases, only the lime spray
dryer and limestone scrubbing processes are evaluated because of the
economically indefinable problems likely to occur with soluble sodium
wastes in high rainfall regions.  Process designs include all the equipment
and material needed to transfer the flue gas from the boiler to the
stack plenum.  All requirements for both fly ash collection and disposal
and SC>2 removal and disposal are included in the costs.

     The soda ash and lime spray dryer processes consist of four or five
trains of cylindrical spray dryers, each with three rotary atomizers.
One train is included as a nonoperating spare in all cases.  Emergency
hot gas (700 F) bypass of flue gas around the air heater and spray
dryers is provided for the low-sulfur coal cases although under normal
operating conditions it will not be needed.  A continuous 4% hot gas
bypass is used in the lime spray dryer process for the high-sulfur
eastern coal case.  Warm gas (300 F) bypass (i.e., around only the spray
dryer) rates of 22.5%, 22%, and 19% are used in the lime spray dryer
process for the lignite, the low-sulfur western, and the low-sulfur
eastern coal cases respectively.  No flue gas bypass is used for the
soda ash spray dryer process under normal operating conditions.  The
higher reactivity of the soda ash (versus lime) does not require a close
approach to the saturation temperature and flue gas bypass is not necessary
to ensure dry conditions in the baghouse.  In all cases the processes
are designed for a flue gas stack temperature of 175 F (including the
5 F to 10 F provided by adiabatic compression in the ID fan).  A single
baghouse is used for particulate collection.  The waste is pneumatically
conveyed to storage silos and trucked to a disposal site one mile away.
An earthen-diked, clay-lined pond is used for the soda ash spray dryer
process and a landfill is used for the lime spray dryer process.  For
the lime spray dryer process in the lignite, the low-sulfur western coal
case, and the high-sulfur eastern coal case, waste recycle is used to
reduce absorbent consumption.  Waste is not recycled in the other spray
dryer processes.

     The limestone scrubbing process consists of four or five trains of
spray tower absorbers, one of which is a spare, using a 15% solids
slurry of pulverized limestone.  The slurry is oxidized by sparging air
into the recirculation tank to produce CaS04'2H20.  A purge stream is
dewatered by thickening and filtering to 80% solids.  The waste is
trucked one mile to a landfill and disposed of with fly ash collected in
ESP's upstream of the FGD system.  For the lignite and low-sulfur western
and eastern coal cases, 28%, 28%, and 25% warm gas bypass is used,
respectively, and the scrubbing efficiency is 90% to obtain an overall
70% S02 reduction.  Full scrubbing at an 89% S02 reduction efficiency is
used for the high-sulfur eastern coal case.  The flue gas bypass eliminates
the need of flue gas reheat in the lignite and the low-sulfur western
coal case and substantially reduces it in the low-sulfur eastern coal

                                 xxix

-------
case.  Full reheat is used in the high-sulfur eastern coal case.   In all
cases a flue gas stack temperature of 175 F is used.
ECONOMIC EVALUATION

     Capital investments, first-year annual revenue requirements,  and
levelized annual revenue requirements were developed based on the  processes
described in the systems estimated section and the conditions described
in the premises.

Capital Investment

     The capital investments for the soda ash and lime spray dryer
processes and the limestone scrubbing process are shown in Table S-5.

     In comparing the soda ash and lime spray dryer processes for  the
low-sulfur western coal case, the overall capital investments of $158/kW
and $154/kW, respectively, differ only slightly.  The largest cost area,
particulate collection, is the same for both.  Similarly,  the total of
the gas handling and S02 absorption areas differ little, suggesting
little cost difference between partial bypass and full scrubbing.
Material handling, feed preparation, and particulate handling costs are
lower for the soda ash spray dryer process, but this is more than  offset
by the higher disposal site construction and land costs because a  pond
is used for the sodium wastes.  Waste recycle in the lime process
approximately doubles the particulate handling costs, but costs in this
area are small compared with other cost areas.  The comparisons suggest
that neither bypass nor waste recycle is an important capital investment
consideration for low-sulfur coal applications.

     More significant differences emerge in the comparisons of the lime
spray dryer and limestone processes.  In overall capital investment the
limestone scrubbing process is 12% to 23% higher than the lime spray
dryer process, the difference being greatest for the lignite case  and
least for the low-sulfur western coal case.  The major cost area for the
limestone scrubbing process is S02 absorption, representing nearly one-
third of the direct costs.  In addition, this cost increases about 44%
as the coal sulfur content increases from 0.7% to 3.5%.  In contrast,
the S02 absorption area costs for the lime spray dryer process are about
one-half those of the limestone scrubbing process for the low-sulfur
coals, and they increase only 23% in going to the 3.5% sulfur case.
These S02 absorption costs are the major cause of the capital investment
cost differences between the processes.

     In other areas, the two processes have similar costs.  The limestone
scrubbing process has moderately higher gas handling costs, very slightly
higher costs for solids separation  (thickening and filtering) compared
with particulate handling (pneumatic conveying and silo storage) and
slightly lower disposal costs because of the higher bulk density of the
gypsum waste.  Materials handling costs for the limestone scrubbing
                                  xxx

-------
                                     TABLE S-5.   CAPITAL INVESTMENT SUMMARY
Lignite












X
X
M
H-





Direct Costs
Material handling
Feed preparation
Gas handling
S02 absorption
Stack gas reheat
Participate collection
Particulate handling
Solids separation
Total, k$
Other Costs

Solids disposal
Disposal site construction
Land
Other capital costs
Total, k$
Total, $/kW
Lime
spray dryer

1,778
765
10,665
7,336
-
12,091
2,163
-
34,798


867
3,756
960
42,246
82,627
165.25
Limestone
scrubbing

1,291
2,406
13,249
17,357
-
15,076
-
2,268
51,647


790
3,690
920
50,313
107,360
214.72
Low-sulfur western
Soda ash
spray dryer

461
91
9,088
9,208
-
11,523
750
-
31,121


725
7,228
1,146
39,228
. 79,448
158.90
Lime
spray dryer

1,691
680
10,030
7,366
-
11,523
2,057
-
33,347


719
2,520
770
39jJ57
77,113
154.23
coal
Limestone
scrubbing

1,009
1,923
11,646
15,054
-
11,688
-
1,828
43,148


616
2,158
670
41,472
88,064
176.13
Low-sulfur eastern coal
Lime
spray dryer

1,762
909
9,770
7,336
-
11,523
753
-
32,053


855
2,939
905
38,551
75,303
150.61
Limestone
scrubbing

1,011
1,944
11,665
15,597
1,225
11,688
-
1,846
44,976


743
2,625
795
43,478
92,617
185.23
High-sulfur eastern coal
Lime
spray dryer

5,014
2,438
11,456
9,018
-
11,235
2,114
_
41,275


1,443
4,899
1,520
50,959
100,096
200.19
Limestone
scrubbing

2,518
4,618
13,653
21,625
3,325
9,998
-
3,350
59,087


1,007
3,441
1,070
57,148
121,953
243.91
Basis:  TVA Design and Economic Premises

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process are lower because the limestone can be simply stockpiled.
Limestone grinding costs greatly exceed lime slaking costs,  however,
making the sum of costs for handling and preparing absorbents similar.

Annual Revenue Requirements

     First-year and levelized annual revenue requirements are shown in
Table S-6.  Levelized costs are actual first-year costs adjusted by a
factor of 1.886, an adjustment that takes into account inflation and the
cost of money over the 30-year life of the installation.

     The lime spray dryer has lower first-year annual revenue require-
ments than the limestone scrubbing process (7.61 mills/kWh versus 9.57
mills/kWh) in the lignite case.  With the exception of lime costs,
which are significantly higher than the limestone costs, and fuel costs,
where the differences are insignificant, the lime spray dryer process
has lower annual costs in each category, compared with the limestone
scrubbing process.  The much higher costs for maintenance, overheads,
and levelized capital charges for the limestone scrubbing process easily
overcome the absorbent cost advantage of using limestone.

     In the low-sulfur western coal case, the soda ash spray dryer
process has first-year annual revenue requirements of 7.42 mills/kWh,
compared with 6.92 and 7.90 for the lime spray dryer and limestone
scrubbing processes respectively.  For the spray dryer processes the
difference is almost entirely the result of absorbent costs, almost 1
mill/kWh for soda ash and 0.4 mill/kWh for lime.  Other minor differences
account for the remaining cost difference.  For the limestone scrubbing
process, absorbent costs are minor, less than 0.1 mill/kWh, but maintenance
costs are, in general, more than 50% higher than those of the spray
dryer processes.  The indirect costs, overheads, and levelized capital
charges account for the remaining cost difference between the limestone
scrubbing process and the spray dryer processes.

     For the low-sulfur eastern coal case a similar relationship prevails.
Most costs differ insignificantly from those of the low-sulfur western
coal case, in spite of the different flue gas bypass conditions.  The
lime spray dryer costs are slightly lower, primarily because of the
lower lime cost in the East.  The limestone scrubbing process costs are
slightly higher, a result of general cost increases stemming from the
lower flue gas bypass ratio.  The small amount of flue gas reheat
required for the limestone scrubbing process does not significantly
affect process costs.

      Somewhat different  conditions prevail  for  the high-sulfur eastern
coal  case.  The  difference  in  cost between  the  lime  spray dryer process
and the limestone scrubbing process decreases from a  12% to  21% advantage
for the lime spray dryer process in the low-sulfur cases, to only about
2% for the high-sulfur case.  The increase in cost for  the limestone
scrubbing process in going  from the low-sulfur eastern coal  case  to the
high-sulfur eastern coal case is about 42% while the  increase for the
lime  spray dryer process is about 70%.  The salient  cost factor is

                                  xxxii

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                                TABLE S-6.   ANNUAL REVENUE REOUIREMENTS  SUMMARY
Lignite












X
X
H-
H-







Direct Costs
Absorbent
Operating labor and
supervision
Fuel
Electricity
S team
Other utilities
Maintenance
Analysis
Total direct, k$
Indirect Costs
Overheads
Total 0 and M, k$
Capital charges
Total, k$
Total, mills/kWh
Levelized
Total, k$
Total, mills /kWh
Lime
spray dryer

1,663

1,025
335
1,617

20
2,232
88
6,980

1,794
8,774
12,146
20,920
7.61

28,694
10.43
Limestone
scrubbing

227

1,212
297
1,986

20
3,851
70
7,663

2,872
10,535
15,782
26,317
9.57

35,651
12.96
Low-sulfur western
Soda ash
spray dryer

2,661

846
265
1,523

10
1,863
88
7,256

1,475
8,731
11,679
20,410
7.42

28,146
10.23
Lime
spray dryer

1,030

972
262
1,464
_
12
2,136
88
5,964

1,717
7,681
11,336
19,017
6.92

25,822
9.39
coal
Limestone
scrubbing

150

1,140
215
1,508
-
17
3,219
70
6,319

2,467
8,786
12,945
21,731
7.90

29,515
10.73
Low-sulfur eastern coal
Lime
spray dryer

848

1,022
329
1,458
-
21
2,058
88
5,824

1,688
7,512
11,070
18,582
6.76

25,238
9.18
Limestone
scrubbing

156

1,175
242
1,518
234
18
3,355
70
6,768

2,563
9,331
13,615
22,946
8.34

31,213
11.35
High-sulfur eastern coal
Lime
spray dryer

8,430

1,202
653
1,582
456a
20
2,649
89
15,081

2,097
17,178
14,714
31,892
11.60

47,111
17.13
Limestone
scrubbing

1,127

1,341
407
2,428
1,330
26
4,404
105
11,168

3,289
14,457
17,927
32,384
11.78

45,193
16.43
a.  Boiler heat loss in lieu of reheat

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absorbent cost.   Absorbent costs for the limestone process increase by
a factor of seven.   Absorbent costs for the lime spray dryer process
increase about tenfold.   For the lime spray dryer process, however, this
increase results in absorbent costs totaling about 27% of the total
first-year annual revenue requirements; for the limestone scrubbing
process only 3%.  Other costs increase little in comparison and in
general the increases are similar for both processes.   A significant
requirement for flue gas reheat also appears in both processes, one in
the form of steam,  the other in the form of hot flue gas.

     The previously discussed first-year annual revenue requirements do
not include the effects of inflation or the time-value of money on the
annual direct costs (such as raw materials, operating labor, etc.).  The
levelized annual revenue requirements (shown in Table S-6), however, do
take these factors into consideration.  As is apparent from Table S-6,
levelizing the annual revenue requirements results in a significant
increase in the magnitude of the costs.  For the lignite and the low-
sulfur coal cases where annual direct costs are minor relative to the
capital charges, levelizing the revenue requirements does not change the
relative economics of the lime spray dryer and the limestone scrubbing
processes.  However, for the high-sulfur coal case, where the direct
costs for the lime spray dryer process are significantly higher than
those for the limestone scrubbing process, levelizing the annual revenue
requirements results in a reversal whereby the lime spray dryer becomes
4% higher in cost than the limestone scrubbing processes.  In fact using
the results of this study over the 30-year life of the FGD system, the
limestone scrubbing process is $60M less expensive than the lime spray
dryer process.
CONCLUSIONS

     The development of spray dryer FGD has been rapid and several
vendors will soon have full-scale systems in commercial operation.  The
technical and economic feasibility of the vendors' approaches to design
features such as type atomizer, degree of approach to saturation temperature,
the particulate collection method, and waste recycle remain to be demonstrated.
Current trends suggest the majority will use a lime slurry with rotary
atomizers, partial flue gas bypass, waste recycle, and fabric filter
collection.  For the near future utility spray dryer FGD systems will
probably be limited largely to low-sulfur coal applications where sufficient
pilot-plant data have been generated to allow detailed design of full-
scale systems.

     Interest in dry injection continues but development of these processes
is hindered by the lack of an economical absorbent.  Nahcolite, the most
promising candidate, is unlikely to be available in sufficient quantities
for several years.  The development of processes using other absorbents,
including limestone, is only beginning and the practicality o-f such
processes remains to be demonstrated.

     The spray dryer processes are similar in cost and both are substantially
lower in capital investment and annual revenue requirements than the
                                  xxxiv

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limestone scrubbing process at least for low-sulfur applications.   The
lime spray dryer process is more cost effective than the limestone
scrubbing process for all three of the low-sulfur coal cases studied.
For the high-sulfur coal case the lime spray dryer has a lower capital
investment than the limestone scrubbing process but the first-year
annual revenue requirements are essentially equivalent, given the uncertainties
associated with a study-grade estimate.  The differences are largely the
result of lower spray dryer equipment costs, compared with wet scrubbers,
and lower utility and maintenance costs.  Offsetting these advantages,
absorbent costs become substantial for the spray dryer processes at high
coal sulfur levels.  The relationship of equipment costs is unlikely to
change substantially.  Operating and absorbent costs could, however,
require adjustment as more operating experience is gained, particularly
in the high-sulfur coal case where important design considerations
(stoichiometry, etc.,) are not well defined.
                                 xxxv

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                 TECHNICAL REVIEW OF DRY FGD SYSTEMS

          AND ECONOMIC EVALUATION OF SPRAY DRYER FGD SYSTEMS



                             INTRODUCTION
     One of the recent developments in flue gas desulfurization (FGD),
the so-called dry scrubbing technology using a concentrated alkali
solution or slurry in a spray dryer, is currently receiving extensive
attention.  Much of this interest is due to some potentially significant
technical and economic advantages of the spray dryer over conventional
wet scrubbing FGD technology.  In particular, the process design is
relatively simple, operating costs are low, and a dry waste, rather than
a wet sludge, is produced.

     Spray dryer FGD in the U.S. evolved in part from FGD studies begun
in the 1960's in which absorbents were injected into the flue gas as dry
powders and collected in fabric filter baghouses or ESP's.  Although
many of these dry absorption studies were initially disappointing, the
potential benefits of such uncomplicated approaches to FGD have maintained
interest in this technology.  Recently, these studies have been expanded
to include coinjection of limestone with the coal in pulverized coal
boilers.  The evolution and current status of these dry absorption
processes are reviewed as a portion of this study.

     Quite rapidly in the past few years, spray dryer FGD technology has
expanded such that numerous companies and consortia are active in pilot
studies and several commercial-sized units are under contract.  In part
this growth is a result of the potential technical and economic attrac-
tiveness of the method and to the increased use of western coals by
utilities, for which spray drying is particularly suited.  Also important
is the broad base of spray dryer and particulate collection technology
from which these processes can be directly evolved.  Quite frequently a
company experienced in one of these technologies has joined with one
experienced in the other to market a spray dryer FGD process.  The
development of this phase of the FGD industry, its general technical
considerations, and its status in the early months of 1980 are discussed
as a portion of this study.

     These dry scrubbers have one significant disadvantage—the need to
use a highly reactive absorbent to achieve acceptable sulfur removal
rates.  This requires an expensive (relative to limestone) absorbent
such as lime or soda ash.  If the savings in capital charges and operating

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and maintenance costs by using the spray dryer systems are larger than
the raw material cost penalty for lime or soda ash,  however,  the spray
dryer FGD systems will remain economically competitive with the wet
scrubbing systems.

     This is one of the reasons that the first commercial applications
are on utility boilers fired with western coals.  Since these coals are
normally low in sulfur, the amount of sulfur to be removed, and hence
the consumption of absorbent, is low compared with eastern bituminous
coal.  Another advantage for the spray dryer processes for western coals
is the relatively high calcium content of this coal.  Not only does this
alkalinity react with sulfur in the boiler and thus reduce the amount of
sulfur removal required in the FGD system, the alkalinity in the fly ash
can also be used to remove SC>2 from the flue gas in the spray dryer by
recycling the fly ash with the absorbent.  Recycling thereby decreases
consumption of alkali raw material.

     Although capital investments and revenue requirements for these dry
scrubbing processes have been estimated by various process vendors and
compared with a conventional wet limestone scrubbing process, no indepen-
dent economic comparisons have been published.  In addition to carefully
describing the technology, the major purpose of this study is to make an
economic comparison of the spray dryer processes (similar to the majority
of contracted commercial units) with a conventional state-of-the-art wet
limestone scrubbing process using the same design and economic premises
for four alternative coals.  Two of these coals, a lignite and a low-
sulfur (0.7% S) western coal, reflect the current utility market for
these spray dryer systems.  The other two coals are eastern bituminous,
one a low-sulfur  (0.7% S) coal and the other a high-sulfur (3.5% S)
coal.  In addition to these base-case evaluations, a sensitivity analysis
is included for each of the four coal cases.  In this sensitivity analysis
the annual revenue requirements are calculated for various absorbent
costs and stoichiometries.

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                              CONCLUSIONS
     The development of spray dryer FGD has been rapid and processes by
several vendors will soon be in commercial operation.  The technical and
economic feasibility of the vendors' approach to design features such as
type of atomizer, degree of approach to saturation temperature, the
particulate collection method, and waste recycle remain to be demonstrated.
Current trends suggest the majority will use a lime slurry with rotary
atomizers, partial flue gas bypass, and fabric filter collection.  In
addition, most of these spray dryer FGD units will probably be limited
to low-sulfur coal applications, at least for the near future, since
very little development work has been done on high-sulfur coal applications.

     Interest in dry injection continues but development of these processes
is hindered by the lack of an economical absorbent.  Nahcolite, the most
promising candidate, is unlikely to be available in sufficient quantities
for several years.  The development of processes using other absorbents,
including limestone, is only beginning and the practicality of such
processes remains to be proved.

     The spray dryer processes are similar in cost and both are substantially
lower in capital investment and annual revenue requirements than the
limestone scrubbing process, at least for low-sulfur applications.   The
lime spray dryer process is more cost effective than the limestone
scrubbing process for all three of the low-sulfur coal cases studied.
For the high-sulfur coal case the lime spray dryer has a lower capital
investment than the limestone scrubbing process but the first-year
annual revenue requirements are essentially equivalent, given the
uncertainties associated with a study-grade estimate.  The differences
are largely the result of lower spray dryer equipment costs, compared
with wet scrubbers, and lower utility and maintenance costs.  Offsetting
these advantages, absorbent costs become substantial for the spray dryer
processes at high coal sulfur levels.  In fact, significant variations
(i.e., those outside the range selected for the sensitivity analysis) in
raw material costs or raw material stoichiometry could, reverse these
results and make the limestone slurry process more cost effective in
terms of annual revenue requirements for high-sulfur coal cases.   For
low-sulfur applications,  the annual revenue requirements are relatively
insensitive to both the raw material cost and the raw material stoichiometry.
The relationship of equipment costs is unlikely to change substantially.
Operating and absorbent costs could, however, require adjustment as more
operating experience is gained, particularly in the high-sulfur coal
applications where important design considerations (stoichiometry,  etc.)
are not well defined.

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                       SPRAY DRYER FGD TECHNOLOGY
     Spray dryers have been used for years for a wide range of drying,
reaction, and purification processes in the chemical industry.  However,
essentially all of these applications involve smaller scale spray dryers
than those which will be typical in FGD.  The uses and the technology for
industrial applications are amply documented (1,2).  The technique is
most useful for materials difficult to dry by other methods, for heat-
sensitive materials requiring a rapid drying rate, for drying to a
particular particle configuration, and for rapid, intimate mixing of
reactants.  In the most common spray dryer system the heated gas enters
a cylindrical, conical-bottom vessel through a manifold at the top and
leaves through a side or bottom opening.  The atomized liquid is sprayed
into the gas stream from the upper part of the vessel.  Drying occurs
while the liquid is suspended in the gas flow, and the solid material is
collected at the bottom of the dryer or is carried out in the gas stream
and collected in external equipment, or both.  The liquid is atomized by
numerous designs of rotary disk atomizers or high-pressure or two-fluid
nozzles that produce droplets in the size range of one to several hundred
micrometers, depending on the material and conditions.

     In the most common spray dryer operations (i.e., those that produce
solid particles) important requisites are that the particles dry in
suspension without impinging on and sticking to the chamber surfaces and
that the gas does not reach its saturation temperature so that no wet
particles are produced.  In most applications this is achieved by proper
design configurations and control of operating conditions.  For example,
gas temperatures and liquid concentrations and rates can be adjusted to
control drying conditions and exit conditions.  In FGD applications the
latitude of these controls is considerably restricted.  The quantity of
the flue gas is determined by boiler operating requirements.  More
importantly, the flue gas temperature leaving the boiler is fixed by the
necessity of extracting as much heat from it as possible and returning
the heat to the boiler in the combustion air, a necessity dictated by a
high boiler efficiency requirement.   The flue gas leaving the boiler has
been cooled to a temperature just above the saturation point of the
sulfuric acid (i.e.,  formed by reaction of flue gas 863 and H90).
Condensation of sulfuric acid would cause intolerable corrosion in the
air heater and ducts.  This temperature is usually about 300°F, depending
on the sulfur content of the coal and the combustion conditions.  Further-
more, the amount of absorbent added is fixed by SOo removal require-
ments.  Effective spray dryer FGD operation is thus restricted to a
design configuration with little latitude in specification of optimum
operating conditions.

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BACKGROUND

     Although there are several vendors developing spray dryer FGD
systems, the process design and principles of operation for all systems
are generally similar.  Differences that do exist are based to a large
extent on vendor experience and are relatively difficult, from a technical
viewpoint, to compare.  They are based on each vendor's optimization of
the technology, and there is no commercial FGD experience to verify the
results.  A prime example of such process design differences is the type
and number of atomizers used in the spray dryer.  Thus, in the following
sections the spray dryer concept will be discussed in the form of a
broad overview, and the process differences between vendors will be
outlined in later sections where the processes are discussed in more
detail.

     In its general form, a spray dryer FGD system consists of two basic
units, a spray dryer and a particulate collection device.  The spray
dryers most frequently used are of conventional design and use rotary
atomizers.  The collection system is either a utility-type ESP or, more
frequently, a utility-type fabric filter baghouse.  The spray dryer is
typically situated downstream of the boiler air heater and is followed
by a baghouse.  Some flue gas may bypass the spray dryer, depending on
S02 removal requirements and design considerations, but all of the flue
gas must pass through the baghouse.

Technical Comparison of Spray Dryer and Wet Scrubbing FGD

     Spray dryer FGD systems have several potential advantages over wet
scrubbing FGD systems, as well as several technical and economic limita-
tions that could restrict these advantages in some applications.  Spray
dryer FGD does not have the large volume of liquid scrubbing medium
recirculating through the absorber with its high energy requirements for
pumping and the corrosion and scaling problems that have often been a
vexation of wet scrubbing processes.  Only a relatively small stream of
liquid is pumped into the spray dryer, and this liquid does not contact
the spray dryer surfaces.  Expensive corrosion-resistant materials are
unnecessary and the operating expenses associated with high corrosion
rates and plugging are eliminated.  High flue gas pressure drops associated
with wet scrubbing are also reduced.  Since the flue gas does not reach
its saturation temperature, mist eliminators and flue gas reheaters
may not be necessary.  These are a frequent source of plugging and
corrosion problems in wet scrubbing systems, and reheat is also an
important energy requirement.  Collection of a dry waste instead of a
sludge that may require extensive treatment is also a major advantage.
Equally important, the collection of fly ash may be combined with collection
of the dry FGD waste, eliminating the need for the separate fly ash
collection and handling facilities that have been found necessary with
many wet scrubbing systems.

-------
     On the other hand, there are certain disadvantages and limitations
associated with the reaction conditions in spray dryer FGD.  The flue
gas-absorbent contact time and efficiency of this contact are limited by
the mechanics of the process.  Absorbents which are more reactive and
expensive than limestone are required, and these must sometimes be used
at higher stoichiometric ratios than is common in wet scrubbing.  The
cost of these absorbents is a major consideration in spray dryer FGD.
There is also a limit to the quantity of water, and hence the quantity
of absorbent, that can be added to the flue gas.  For some high-sulfur
coals, this could limit S02 removal.

     The overall effects of these advantages and limitations have not
been fully defined, particularly the extent to which spray dryer FGD
will be technically and economically applicable to high-sulfur coal.  It
is obviously most suitable to low-sulfur coal applications, especially
if the fly ash alkalinity can be used to supplement the absorbent.

Process Chemistry

     Although the basic chemistry of SC>2 removal in spray dryer FGD
(i.e., the reaction mechanisms and rate-controlling steps) is not
completely defined, additional work is continuing toward a better under-
standing of the process chemistry.  With additional work it is hoped
that further improvements in spray dryer performance can be achieved.

     The flue gas normally enters the spray dryer at about 300°F.  The
absorbent liquid is sprayed across the direction of gas flow.  Typical L/G
ratios are about 0.3 gal/kaft-^.  The SC>2 and HC1 in the flue gas are
absorbed into the liquid and react as shown below for a lime slurry
process .

                      Ca(OH)2 + S02 •> CaS03 + H20  i                 (1)

                      Ca(OH)2 + SO., -> CaSO, + H20  t                 (2)
                     Ca(OH)2 + 2HC1 •> CaCl2 + 2H20 t                (3)

In addition to these primary reactions, the following secondary reaction
also occurs:

                      CaS03 + 1/202 -> CaS04                         (4)

     All of the water evaporates in the spray dryer, forming particles
composed of the reaction products and, usually, unreacted absorbent.
Any remaining SC>2 continues to react, although at a much slower rate,
with the dry absorbent in the particles during their passage to the
collection device.  If a fabric filter is used, passage of the flue gas
through the built-up particulate cake provides valuable additional
contact time for the reaction of SO^ and any remaining absorbent.  Some
process vendors claim that 10% to 20% of the overall S02 removal may
occur in this manner if a baghouse is used.

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     Spray dryer technology has some inherent advantages over the dry
phase reactions (3).  Since the water in the atomized solution in spray
dryers evaporates from the surface of the droplet inward, the initial
deposition of solids in the droplet occurs at the outer edges when a
soluble absorbent such as soda ash is used.  The rate of diffusion of
the solid back into the solution is slower than the flow of water from
the interior to the surface, and therefore the solids tend to accumulate
at the surface.  The resulting particulate matter is very porous and,
depending on the drying rate, may even be hollow.  Since one of the
requirements for good raw material utilization is high porosity (which
gives a large available surface area for reaction), the particles formed
from solutions in spray dryers have a high reactivity.

     Although a somewhat similar situation prevails in the lime-slurry-
based spray dryer FGD system, the low solubility of lime results in the
formation of a highly porous outer layer surrounding a relatively dense
inner particle.  As the water in the atomized droplets evaporates, lime
particles are compressed until a single particle is formed.  In contrast
to the particles formed in the soda ash system, which are very porous
throughout, the lime particles tend to be porous only in their outer
layers and have a solid inner core.  The evaporation of the remaining
moisture in the particle is controlled by the diffusion of the water
through these pores to the surface.  The final moisture content is a
function of the diffusion rates, vapor pressures, and temperature
differences between the particles and the flue gas, and the residence
time.

     The previous discussion of the drying stage of the particles is
further complicated by reactions with the flue gas.  Previous investi-
gations (4) have indicated that the reaction of SO^ with lime particles
causes the outer layer of the particle to expand as calcium sulfite is
formed.  This expansion constricts the pore openings to the inner regions
of the particle.  Thus, the central regions of the particle remain
relatively unreacted,  and the overall raw material utilization may be
significantly less than the 100% conversion present at the surface of
the particle.  In other words, the reaction tends to seal the core and
prevent additional reaction.  These problems can be minimized by grinding
the makeup lime as small as economically feasible, recycling the collected
FGD waste, or adding an inert material to prevent the pores in the
particles from becoming sealed.

     For sodium- (or other highly soluble alkalis) based systems this
pore closure problem is not as significant since the central core of the
atomized solution has  no solid alkali particles and in fact may even be
hollow due to the drying mechanism.  In terms of S02 absorption, the
highly soluble alkali  metal reagents such as soda ash not only have the
advantage of being more chemically reactive than calcium compounds, but
they also expose more  surface area to the S02~laden flue gas during the
drying stage.  Thus,  these sodium-based alkalis have an inherent advantage
over calcium compounds in terms of raw material utilization.

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     The reactions proceed rapidly as long as there is surface moisture
and absorbent available.  Therefore, an efficient process design is one
in which as much water as possible enters the spray dryer and the exit
flue gas temperature closely approaches the flue gas saturation temperature.
Another important operating requirement for an efficient process using
lime is that the lime is ground as small as economically feasible.  Thus
the lime particles have the highest possible surface area for reaction,
and they retain their surface moisture as long as possible.  This also
minimizes the amount of lime unable to react due to coating with reaction
products.  In actual practice, however, process economics determine the
optimum particle size, and there is also a need for a safety margin
between the actual flue gas temperature and the flue gas saturation
temperature so that condensation or wet operation does not occur.

Fly Ash Composition

     The composition of the fly ash is also important in spray dryer FGD
chemistry.  Coals contain varying amounts of reactive metals, predominately
calcium, that form reactive alkaline ash components (5).  These components
react to some extent with S02 and HC1 in the flue gas and can, in some
cases, supplement the FGD absorbent.  In the past this ash property has
not been generally important.  Historically almost all utility coal was
mined in the Appalachian or Central basins.  These coals are typically
low in these metals.  In contrast, western coals that are coming into
increasing use by utilities are typically higher in these metals.  Fly
ash from western coals and lignites often contains appreciable reactive
alkalinity and is used as an FGD absorbent or absorbent supplement (6).
A comparison of the ash compositions of eastern and western fly ashes is
shown in Table 1.
                TABLE  1.  FLY ASH ANALYSIS COMPARISON



Fly ash component
Si02
A1203
CaO
MgO
Na20
Ti02
so3
Other
Western
fly ash,
wt %
32.2
17.4
6.0
20.0
4.7
1.7
0.5
1.0
15.3
1.2
Eastern
fly ash,
wt %
50.8
20.6
16.9
2.0
1.0
0.4
2.6
2.5
2.4
0.8
Lignite
fly ash.,
wt %
23.0
11.5
8.6
21.6
6.0
5.9
0.5
0.5
19.2
3.2
               Total             100.0       100.0       100.0
           Note:   Based  on published  analyses  that were
                  used to develop the design premises.

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     The use of alkaline fly ash as an absorbent is made somewhat difficult
by the physical and chemical nature of the fly ash particles,  which
renders much of the alkalinity relatively unreactive or physically
inaccessible to the SO-.  During its passage through the spray dryer FGD
system, for example, alkaline fly ash appears to contribute relatively
little, compared with its total alkalinity, to 862 removal.  This is
thought to be due to the difficulty associated with a gas-solid reaction
at these temperatures.  If, however, it can be slurried with water and
recycled through the spray dryer, it will be much more reactive and can
be used as a supplement to reduce absorbent consumption.  Its use is
facilitated in spray dryer FGD by the fact that fly ash is collected
with the FGD particulate waste.  Depending on the fly ash alkalinity and
the amount of unreacted absorbent in the waste it may be economically
desirable to recycle and reuse a portion of the waste.

Importance of Coal Characteristics

     Several factors that are important in the spray dryer FGD technology
depend on the type of coal being burned.  For example, the previously
mentioned fly ash composition can be a major factor in the design of the
FGD system.  With low-sulfur eastern bituminous coal (in this study we
define low-sulfur coal as a coal that when burned requires only 70% S02
removal), which typically contains very little available alkalinity in
the fly ash, recycle of the waste material would probably not be economi-
cally attractive; in addition, absorbent utilization would approach 100%
without recycle.  For high-sulfur coals (defined as all coals requiring
more than 70% S02 removal), recycle could be required regardless of the
coal rank since the process economics would probably dictate a higher
absorbent utilization than could be achieved by a once-through waste-
producing system.

     For low-sulfur western coals and lignites, which typically have a
relatively high amount of available alkalinity in the fly ash, waste
recycle could provide substantial amounts of alkali for SC>2 absorption.
In fact in a recent evaluation for EPA (7), the available alkalinity in
the recylced FGD - fly ash waste accounted for nearly 20% of the total
alkalinity injected into the spray dryer.  Considering the high unit
cost for lime and soda ash, this represents a substantial cost savings
in annual revenue requirements.

     The rank, and hence the heating value, of the coal being burned in
the boiler also affects the spray dryer FGD system in the degree of S02
removal required.  Lignite, because of its low heating value, must have
a sulfur content of less than 0.7% (and for lower quality lignites even
less than 0.5% sulfur) in order to qualify for the 70% S02 removal
emission regulation.  Subbituminous coals, on the other hand, can approach
1.0% sulfur and still only require 70% S02 removal.  Bituminous coal can
approach 1.2% sulfur before needing more than 70% S02 removal.

     Additionally, the rank of the coal being burned affects the design
of the spray dryer system because the lower rank coals typically have
higher moisture contents.  For example, on an as-fired basis, moisture
levels for bituminous coals are normally less than 10%, moisture levels

                                   9

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for subbituminous coals range from 10% to 30%,  while those for lignite
can approach 40%.  These higher moisture levels for lower rank coals
result in higher moisture levels in the flue gas and therefore a higher
flue gas saturation temperature.  The amount of water that can be injected
into the spray dryer decreases as the flue gas  saturation temperature
increases.  Thus for the same inlet S02 concentration and S02 removal
efficiency, the absorbent liquid to the spray dryer must have a higher
solids content for flue gas from a lignite-fired boiler than for a
bituminous-coal-fired boiler.  For 70% S02 removal in a low-sulfur coal
application, this is not significant; however,  for a higher sulfur coal
with a higher SOo removal requirement and waste recycle rate, absorbent
liquid-handling problems could present potential problems.

     Since the spray dryer FGD processes are most cost effective when
sulfur removal efficiencies are as low as possible (i.e., 70% removal)
to minimize consumption of expensive alkali raw materials, the best
possible application would be either a low-sulfur lignite or subbituminous
coal.  In addition, the fly ash should be analyzed for available alkalinity,
since recycle of highly alkaline fly ash could  make a higher sulfur
lignite or subbituminous coal more cost effective than a lower sulfur
fuel with a low-alkalinity ash.

Comparison of Absorbents

     Potential absorbents can be classified depending on their solubility
in aqueous solutions—sodium-based absorbents and calcium-based absorbents.
Economically practical sodium-based absorbents  are soda ash, and the
naturally occurring ores of NaHC03 and NapC^,  nahcolite and trona.
Economically practical calcium-based absorbents are essentially limited
to lime.

     Sodium-based absorbents are extremely soluble in water.  This means
that these absorbents are very reactive in the  spray dryer environment,
giving a high S02 removal efficiency and simultaneously, a high raw
material utilization.  Another advantage due to their high solubility is
a lower maintenance cost and their compatibility with less expensive
materials of construction.  However, this high  solubility also means
that the waste generated in these systems is difficult and expensive to
dispose of in an acceptable manner for most applications.  The other
drawback to sodium-based systems, at least for  eastern locations, is the
high cost of soda ash, the primary sodium-based raw material.  The soda
ash currently being marketed is processed to a  high purity because of
the requirements in other applications; however, for these FGD applications
this high purity is not required.  Therefore, various vendors are considering
other potentially lower cost sodium sources such as nahcolite and trona.
In fact, even wastes from the production of high-purity soda ash are
being considered (8).

     In contrast to the sodium-based compounds, lime has a relatively
low solubility in water and hence is used in the form of an aqueous
slurry.  This results in a lower reactivity in the spray dryer and a
significantly lower utilization rate, particularly at high S02 removal

                                   10

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efficiencies.  These difficulties, however, can be partially overcome by
modifications in the process design.  Since the lime is used as a slurry,
maintenance costs are somewhat higher for the lime-based system and more
expensive materials of construction are required.  A slaker and milling
equipment are required, and the slurry is more abrasive in pumps and
atomizers than a solution.

     These disadvantages of calcium-based systems must be balanced
against the significant advantages associated with the insoluble calcium-
based wastes.  Since the waste material is removed as a dry material and
is relatively insoluble, it can be disposed of in a landfill rather than
a more expensive lined pond required for the sodium-based wastes.  In
fact, due to the unreacted lime available in the waste material, it is
claimed by some vendors that with the addition of the proper amount of
water this waste will form a solid material similar to a low-grade
concrete.  Thus leaching of water soluble salts, such as calcium chloride
and calcium sulfite, and fly ash components would be minimized.

Two-Fluid Nozzle and Rotary Atomization

     A main difference between the various spray dryer FGD processes is
the type of atomizer used.  Most process developers use rotary atomizers
but a few are using two-fluid nozzle, atomizers.  Both have been used in
other types of spray drying, and each has its own particular advantages
and disadvantages.

     A typical rotary atomizer, as shown in Figure 1 uses a rapidly
spinning disk (up to 20,000 rpm) to produce the fine droplet mist in the
spray dryer.  The absorbent liquid flows down through the vertical,
spinning shaft of the rotary atomizer unit to the rotating disk at the
base of the shaft and out into the internal chamber of the disk.  Centrifugal
force moves the liquid out through silicon carbide inserts, which are
abrasion-resistant inserts running from the internal chamber of the disk
to the outer periphery.  As the liquid moves to this outer, rapidly
spinning edge of the disk it forms a thin layer on the face of the disk.
Additional liquid moving out through the inserts thickens this layer
until the centrifugal force acting on the outer layers overcome the
forces holding the liquid on the disk, and the outer layers are sheared
off into the gas stream.  This liquid has a horizontal velocity which
results in the formation of a large umbrella spray pattern characteristic
of a rotary atomizer.

     In spray dryer applications the most important factor is the size
of the droplet.   The smaller the droplet, the larger the surface area
per unit volume and therefore the larger the area that is available for
S02 absorption.   However there are also practical limits on the smallness
of the droplet.   In order to achieve smaller droplets, the energy consumed
in the atomizer must increase, and at some point the increased energy
consumption is not economically justified by the increased S02 removal.
In addition, the close approach to saturation could result in these
smaller droplets remaining entrained in the flue gas to the baghouse
(most vendors provide either warm or hot gas bypass immediately after
the spray dryer to prevent this problem).
                                   11

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                                                   'MOTOR
                                            'DISK
Figure  1.  Design of  rotary atomizer (9)
                               12

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     In the rotary atomizer system, the droplet size is determined by
the velocity of the rotating disk and the liquid characteristics and is
reasonably independent of the feed rate to the atomizer.  The higher the
velocity of the rotating disk, the smaller the resulting droplet size
is.  This factor can be a significant advantage in FGD applications
where the flue gas rate and the inlet 862 levels fluctuate.  Since the
S02 removal efficiency required in the spray dryer remains constant
regardless of inlet SC>2 levels and this removal efficiency is dependent
on the droplet size, it is an advantage to be able to maintain the same
droplet size regardless of the alkali feed rate required.

     The primary disadvantage of rotary atomizers is that they tend to
be mechanically complex in comparison with nozzle atomizers.  Since
rotary atomizers depend on a high velocity rotation, maintenance shutdowns
could be more frequent.  A second potential disadvantage,  particularly
with the lime-based systems, is plugging of the atomizer disk.  Many
developers minimize this problem through the design of the disk, but
plugging may still occur.  Operating experience with the full-scale
utility FGD units will help to quantify the scope of these potential
disadvantages.

     The typical two-fluid nozzle atomizers shown in Figure 2, which are
used by several process developers, depend on impinging an atomizing gas
onto the liquid.  This high pressure gas is typically either steam or
air (although recent demonstration unit tests have persuaded one
vendor  previously using steam to use compressed air instead).  This
compressed air furnishes the energy to break up the liquid into a fine
mist of small droplets.

     The liquid is pumped through a central tube in the atomizer, and
compressed gas is blown around the central tube into annular space.  At
the end of the central tube, there is an orifice that emits the liquid
into the compressed gas stream at a high velocity.  The compressed gas
shears and further breaks up the droplets, which are then blown out of
the nozzle and into the flue gas.  The small diameter nozzles tend to
concentrate the mist into a much narrower spray than the rotary atomizers,
and therefore for large gas volumes (such as utility FGD systems) multiple
nozzle atomizer arrangements are required.

     The droplet size from a nozzle atomizer depends on several factors:
relative gas velocity, gas density, and ratio of gas-to-liquid.  Typically
the relationship between these factors (and of course the geometry of
the gas-liquid interaction) is complex, and actual experimental data
must be used to predict the average droplet size.  The average droplet
size is used since, instead of producing a single, narrow range of
droplet sizes as is the case with rotary atomizers, these two-fluid
atomizers tend to produce a range of droplet sizes.

     Since the design of the spray dryer for a specific SC>2 removal
efficiency and raw material utilization depends on knowing the droplet
size from the nozzle atomizer, initial full-scale testing of the nozzle
atomizer is required.  Even after the nozzle has been tested, the droplet

                                   13

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                                       LIME  SLURRY
COMPRESSED
          AIR
   Figure 2.  Design of two-fluid nozzle atomizer (10)
                         14

-------
size may vary depending on the nozzle operating conditions (gas velocity,
gas density, ratio of gas-to-liquid).  This is not of overriding importance
in most types of spray dryer applications where feed rates and temperature
are generally well controlled.  The utility FGD system, however, is one
in which inlet temperature and SC>2 concentrations change, and therefore
for economical operation the amount of absorbent atomized into the spray
dryer must change.  Changing the absorbent liquid feed rate changes the
droplet size, which in turn can change the SC>2 removal efficiency.  This
potential problem is somewhat minimized by having multiple nozzle
atomizers.

     The primary disadvantage of the nozzle atomizer is that it appears
to be more prone to operating problems.  In fact, the first two demon-
stration units using nozzle atomizers are reported to have had operating
problems with their atomizers.  The advantages of the nozzle atomizers
include the absence of moving parts and the opportunity to use large
liquid passages to minimize plugging.  As with the rotary atomizers,
operating experience at the full-scale utility FGD units is needed to
quantify the scope of the potential advantages and disadvantages.
BASIC PROCESS DESIGN CONSIDERATIONS

     Once the basic conditions of the boiler application have been
specified by the utility (coal and ash composition, flue gas rate and
composition, S02 removal efficiency, etc.), other important design and
operating factors that tend to characterize the current spray dryer FGD
technology are usually specified by the process developer.  These factors
include the type of absorbent used, the design practices by which control
of flue gas temperature is obtained, and the methods by which efficient
use of absorbent is attained.  The manner in which these factors are
employed depends in large part on the type of coal burned, but they also
vary with vendor preferences.

     An important consideration in the design and operation of spray
dryer FGD systems is the overall energy balance around the spray dryer.
The temperature of the flue gas entering the particulate collection
device must be high enough to insure that condensation does not occur in
a fabric filter when used or the downstream flue gas ducts or stack.
Once this flue gas temperature and the flue gas temperature at the
boiler air heater exit have been specified, the AT (flue gas temperature
drop) or "spray down" temperature in the spray dryer, and hence the
amount of water that can be injected into the spray dryer, is fixed.
S0? removal efficiency is controlled by the amount of alkali raw material
injected into the spray dryer.  The more concentrated the alkali solution
or slurry, the higher the SC>2 removal efficiency.  Counterbalancing this
higher SC>2 removal efficiency is a lower raw material utilization, i.e.,
more of the absorbent passes through the spray dryer unreacted.  Three
potential design alternatives are available to increase the raw material
utilization:  waste recycle, warm gas bypass, and hot gas bypass.
                                    15

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Flue Gas Temperature

     Most vendors agree that the following occurs in the spray dryer.
As the alkaline solution or slurry is atomized and sprayed into the flue
gas, the S02 and HC1 dissolve into the alkaline solution or liquid
surrounding the slurry particle and react with the absorbent.   The
reactions proceed at acceptable rates as long as there are surface water
and reactants available.  Therefore, an efficient process design is one
in which as much water as possible enters the spray dryer and the exit
flue gas temperature closely approaches the flue gas saturation temperature.
This close approach to the flue gas saturation temperature maximizes the
time surface water remains on the particles.  Another important operating
requirement for an efficient process using lime is that the lime is
ground as small as economically feasible.  Thus the lime particles have
the highest possible surface area for reaction and they retain their
surface moisture longer.  This also minimizes the amount of lime unable
to react because of coating with reaction products.  In actual practice,
however, process economics determine the optimum particle size and the
need for a safety margin between the actual exit flue gas temperature
and the flue gas saturation temperature so that condensation or wet
operation does not occur.  Wet operation could result in caking on
fabric filters or loss of ESP efficiency.  Caking could result in high
pressure drops and difficulties in dislodging the FGD waste from the
filters.  In addition, a close approach to flue gas saturation without
reheat could also result in sulfuric acid formation and corrosion in the
collection equipment, ducts, and stack.

     The degree of approach to flue gas saturation varies among the
vendors.  Typically, those using an ESP for particulate control recommend
a closer approach to the saturation temperature than vendors using
fabric filters.  Although it is claimed by those using fabric filters
that no significant operating problems occur during upset conditions
when wet material passes through to the filters (i.e., when normal
conditions return the filters simply dry out), these vendors design more
conservatively than ESP-using vendors to minimize this problem.  Those
vendors recommending ESP's believe that ESP's are more moisture-tolerant
collection devices and are not harmed in any way by an occasional wet
upset.  Therefore they typically design for a closer approach to saturation
temperature and have a lower safety margin.

     Although it would seem reasonable to assume that the flue gas
bypass around the spray dryer would contain sufficient heat to evaporate
any liquid carryover from the spray dryer before it reached the collection
device, this may not in fact happen.  The residence time in the ducts
may not be long enough to evaporate the liquid carryover during the
upset conditions (either due to the short residence time or the larger
droplet size that may result from wet operation).

Stoichiometry and Absorbent Utilization

     The raw material Stoichiometry for the dry scrubbing systems can be
misleading, particularly to those most familiar with wet FGD systems,
because of the different meaning of the term Stoichiometry in the dry

                                   16

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and in the wet FGD systems.  The raw material stoichiometry for the dry
scrubbing systems is typically defined as the mols of absorbent/mol of
S02 inlet to the scrubber whereas for the wet scrubbing systems stoichio-
metry is defined as the mols of absorbent/mol of S02 absorbed.  Since
this report compares the relative economics of both a dry and a wet FGD
system, raw material stoichiometry in this report is arbitrarily defined
as mols of absorbent/mol of S02 absorbed in all cases.

     As was previously discussed in the process chemistry section, the
highly soluble sodium-base scrubbing solutions tend to generate particles
that are extremely porous.  This high porosity results in a large
surface area available for reaction and, when combined with the higher
reactivity of the sodium-based compounds, normally results in a more
efficient system.

     For low-sulfur coal applications where only 70% S02 removal is
required, the alkali raw material is sufficiently reactive that close
approach to the flue gas saturation temperature is not required.  Absorbent
stoichiometry (defined as mols of absorbent/mol of S02 absorbed) closely
approaches 1.0 and the absorbent utilization approaches 100%.  Even as
the S02 removal efficiency required increases substantially above 70%,
absorbent stoichiometry remains around the theoretically required 1.0
and the raw material utilization remains high.

     The process chemistry for the calcium- or lime-based systems dictates
a less efficient spray dryer system because of the relatively insoluble
nature of lime in aqueous solution.  Although the outer regions of the
particle are porous, the central core tends to be dense and unreactive,
particularly after the outer regions become blinded with reaction products.
Since the central core tends to remain unreacted, a higher stoichiometry
is required in the lime-based system than in the sodium-based system.

     For low-sulfur coals where only 70% SC>2 removal is required, absorbent
stoichiometry (defined as mols of absorbent/mol of S02 absorbed) can
approach 1.0 and the absorbent utilization can approach 100%.  This is
particularly true if the flue gas approaches its saturation temperature
and waste recycle is employed.  As the required S02 removal efficiency
increases, the absorbent stoichiometry increases significantly above 1.0
and the absorbent utilization decreases for lime-based spray dryer
systems.  For high S02 removal efficiencies, the poor utilization of an
expensive alkali raw material can lead to significant economic penalties
for lime-based processes.

     Two alternatives are available for overcoming this potential problem—
waste recycle or operating closer to the flue gas saturation temperature.
The various process vendors disagree on which method to use as well as
when to use it.   The vendor designs seem to run the gamut from no recycle
at all to recycle for every application.   One vendor apparently does not
believe in recycling at all under most conditions but rather in designing
sufficient flue gas bypass to allow the spray dryer to be operated very
near the flue gas saturation temperature.   In some designs this may even
require bypassing the gas around the boiler air heater (with the associated

                                   17

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energy penalty in the boiler heat rate) to achieve sufficient flue gas
reheat downstream of the spray dryer.  Some vendors believe in recycling
the waste material for all applications, while others recommend recycle
only when a high SC>2 removal efficiency is required or when the fly ash
is highly alkaline.

     Figure 3 illustrates two of the basic tenets of the lime spray
dryer FGD system.  The most important implication is that regardless of
whether FGD waste recycle is used or not, approaching closer to the flue
gas saturation temperature in the spray dryer significantly increases
the 862 removal efficiency at constant raw material stoichiometry.  For
example at a stoichiometric ratio of 2.0 in a once-through system, a
70°F approach to flue gas saturation temperature results in 55% SC>2
removal while a 30°F approach to flue gas saturation temperature gives
80% S02 removal.  The other important implication is that recycling
waste material (which does not count toward the stoichiometric ratio)
increases the S02 removal efficiency at the same approach to the flue
gas saturation temperature.  For example at a 30°F approach to flue gas
saturation temperature and a stoichiometric ratio of 2.0, S02 removal
for a once-through system is 80% while the recycle system approaches 98%
removal.  (This figure is based on one vendor's pilot-plant data and is
not meant to imply these results could be achieved in a full-scale unit
but rather to show the effect of the degree of approach to flue gas
saturation temperatures.)

Waste Recycle—
     The technical reasons for using waste recycle are obvious.  One of
the major annual costs for these spray dryer FGD processes is the cost
of the alkali raw material.  Since this raw material cost is a significant
factor in the process economics, anything that reduces the makeup raw
material requirements deserves serious consideration.

     Waste recycle can reduce this makeup raw material requirement in
two ways.  First, the fly ash from the boiler contains varying amounts
of alkalinity depending on the coal.  Some coals (especially western
coals) produce a fly ash that can have up to 30% wt CaO, although
most of this CaO is not freely available for reaction as lime.  However,
if only 10% of this CaO (or 3% wt of the fly ash) is available for
reaction, this can amount to significant quantities of "free" alkalinity
for the FGD process.  Since the fly ash from the boiler enters the spray
dryer dry, the rate of the reaction between the S0_ in the flue gas and
the available alkalinity in the fly ash is very slow and most of this
alkalinity passes through the system unreacted to end up in the process
waste.  The second way in which waste recyle can reduce makeup raw
material requirements is that lime is added in greater than stoichiometric
amounts (i.e., the amount theoretically needed to achieve the required
S02 removal) to  the spray dryer.  This extra lime is provided both
because the spray dryer  (like any chemical reactor) is not a perfect
system and because a safety margin is needed.  Thus some excess alkalinity
is intentionally added to the system and passes through unreacted to end
up in the process waste.  This total excess lime added as a safety
factor varies depending on the vendor  and the S02 removal efficiency


                                   18

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                                      S02  REMOVAL  EFFICIENCY, %
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required.  However, typically, the higher the S02 removal efficiency the
larger this safety factor will be and thus the more excess alkalinity in
the waste.  Thus there can be two significant sources of alkalinity in
the waste from these spray dryer processes, fly ash alkalinity and
unreacted raw material.

     Since the equipment to recycle the process waste involves an additional
capital expenditure (on the order of $2/kW for a low-sulfur coal case),
initially most of the vendors believed that the only time it would be
economically attractive to recycle the waste was when the fly ash was
highly alkaline or when a high SC>2 removal efficiency was required.
Thus by using waste recycle the makeup raw material stoichiometry in the
spray dryer could be reduced and the overall raw material utilization
could be improved.  There are still several vendors designing their FGD
systems based on this philosophy.

     Recently several of the vendors have turned from this earlier
philosophy to one in which they recycle part of the FGD waste in all
applications.  Pilot-plant data seem to indicate that recycling the
waste, even if it is low in available alkalinity, will increase the raw
material utilization in the spray dryer.  The current theory is that the
larger particles of recycled waste provide a base on which the smaller,
fresh lime particles can expose more of their surface area for reaction.
Thus the makeup lime achieves a higher utilization rate than would be
the case if there was no  recycle.  Reslurrying and recycling the FGD
waste also makes any alkalinity in the waste available for reaction with
SC>2, but this is currently being seen by some vendors as being relatively
minor compared with the increased utilization of the makeup lime.   At the
present time sufficient information about test results is not available
to determine which theory is a better description of this complex inter-
action.

Warm Gas Bypass—
     When optimizing the design of spray dryer FGD systems, the best
process design would involve treating the entire flue gas stream for the
particular 862 emission regulation.  For example, if 70% overall S02
removal efficiency is required, treating all of the flue gas for 70% S02
removal would be the best possible design for minimizing both costs and
operating problems.  For soda ash applications, particularly at low S02
removal efficiencies (about 70%), this is typically the case.  However,
if the desired S02 removal efficiency cannot be achieved at reasonable
raw material utilizations, as is quite often the case with lime-based
systems (even at 70% SOo removal), warm gas bypass is used.  Warm gas
bypass involves bypassing some of the 300°F flue gas from the boiler air
heater exit around the spray dryer and returning it to the flue gas ducts
upstream of the particulate removal device.

     By using warm flue gas bypass and having 300°F flue gas available
for reheat, the spray dryer can be operated so that the treated flue gas
more closely approaches the flue gas saturation temperature.  As the
flue gas approaches saturation temperature, the alkali droplets retain
their moisture longer and the liquid phase residence time for S02

                                   20

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absorption is increased.  This results in a better raw material utilization
(as well as a higher S02 removal efficiency) in the spray dryer.  Although
there is an additional capital investment for the flue gas bypass ductwork,
this is offset by both the lower capital investment for the spray dryers
and the lower annual cost for absorbent.

Hot Gas Bypass—
     When higher 862 removal efficiencies (>85%) are required, most of
the flue gas must be treated in the spray dryer, and there might not be
sufficient heat available using warm gas bypass to reheat the flue gas.
Under these conditions, hot gas bypass may be considered.  Hot gas
bypass involves removing some of the 700 F flue gas upstream of the
boiler air heater, bypassing it around both the boiler air heater and
the spray dryer, and returning it to the flue gas ducts upstream of the
particulate collection device.  The technological reason for using hot
gas is the same as for using warm gas bypass—it allows the spray dryers
to be operated closer to the flue gas saturation temperature and thus
increases raw material utilization and improves S02 removal efficiency.
In addition to the higher capital investment for the required ductwork
as in the case of warm gas bypass, hot gas bypass incurs economic penalties
because it affects the heat rate and operation of the boiler.

Particulate Matter Collection

     The choice of particulate control device usually depends on the
vendor (sometimes the buyers specifv their preference).   Most favor a
fabric filter baghouse but at least one suggests an ESP.  Although
baghouses for utility applications have only been recently demonstrated
on a commercial scale (12) and are more expensive than an ESP in tradi-
tional applications, the recent promulgation of a 0.03 Ib/MBtu particulate
emission standard and increasing use of western coals has increased
their attractiveness.  Not only is the baghouse capable of achieving
high removal efficiency regardless of the coal being burned, but it also
removes a higher proportion of the submicrometer particulate matter in the
fly ash which is difficult to remove in an ESP.  This ability to remove
very fine particulate matter may become more important in the future
because these particles may present more of a respiratory health hazard
than the larger particles which have received the primary emphasis in
the past (13).  This fine particulate matter may also present an opacity
problem for new coal-fired boilers, which are restricted to a 20% opacity
requirement by the 1979 revised NSPS.  In addition, the fly ash from
low-sulfur western coals often have high resistivities,  making collection
by ESP's more difficult.  Increasing use of western coals has thus
increased interest in baghouses for particulate matter collection (14).

     The location of the particulate collection device downstream of the
spray dryer in spray dryer FGD systems has a moderating effect on their
capital costs, as compared with the traditional location of the particulate
control device in other FGD systems.  Since the capital investments for
particulate control devices are proportional to the flue gas volume,
cooling and humidifying the flue gas in the spray dryer decreases the
volume of flue gas to be treated in the particulate collection device.

                                   21

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The capital investment for the particulate collection device is lower
than would be the traditional case (treating the 300 F flue gas from the
boiler air heater).

     A second benefit of having the particulate collection device located
downstream of the spray dryer is particularly advantageous for the ESP.
Cold ESP's have had trouble achieving high particulate collection
efficiencies on low-sulfur coal applications where the resistivity of
the fly ash tends to be very high.  The resistivity versus temperature
curve for the fly ash, however, is bell shaped—from a maximum near
300 F the resistivity of the fly ash tends to fall with decreasing
temperature to more optimum values for fly ash collection.  By locating
the ESP downstream of the spray dryer in the cooler temperature region,
the spray dryer is claimed to make particulate matter collection easier.

Summary

     The specific design of the spray dryer FGD system depends on many
factors.  These include:  S02 emission regulations, the type of coal
being burned, the available alkalinity in the fly ash, and the alkali
raw material selected and its delivered price.  The final design will be
the net result of optimizing all process variables for each specific
application.  Based on the limited amount of information currently
available, the following generalizations can be made.

     For soda ash applications:

     1.  Waste recycle will be used for few if any applications.

     2.  Hot gas bypass will be used for few if any applications.

     3.  Warm gas bypass will be used only for high S02 removal efficiencies
          (about 90%).

     For lime applications:

     1.  Waste recycle will depend on the vendor.  Some vendors will
         always recycle and some only when the available alkalinity in
         the fly ash  is high or when the required S02 removal efficiency
         is high.

     2.  Warm gas bypass will probably be used even for moderate S02
         removal  (70%).

     3.  Hot gas bypass will be used only as a last resort and only for
         high S02 removal  (over 85%).
                                  22

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                       DRY ABSORPTION TECHNOLOGY
BACKGROUND

     Dry absorption, or "dry sorption," has been described as "any
process that directly produces a dry product . .  ." (15).  Included in
this definition are processes using direct injection of dry absorbents
into the boiler or flue gas as well as spray dryer processes.  Dry
absorption processes have several potential economic and operational
advantages over wet FGD processes that have been long recognized by
those concerned with 862 emission control.  These advantages have been
widely discussed (15, 16, 17).  Paramount are the simplicity and opera-
tional flexibility of the process, reduced energy requirements, production
of a dry product, and the opportunity for simultaneous collection of fly
ash and sulfur-salt waste.

     Direct injection of lime was investigated in the early part of this
century (18).  Widespread interest, however, paralleled the development
of practical particulate matter control devices for flue gas in the
1960's, particularly fabric filters.  The use of fabric filters for
collection has the advantage of providing additional contact of flue gas
and unreacted absorbent as it passes through the built-up solids on the
filters.  Bechtel (16) has summarized early electric utility investigations
of direct injection of dry adsorbents and the development of particulate
matter control technology in utility applications.

     The first modern investigations of dry adsorption, beginning with a
320-MW installation at Southern California Edison's Alametos Station in
1965, consisted of dry injection of the adsorbent followed by baghouse
collection.  From 1967 to 1969 Wheelabrator-Frye, Inc., evaluated dry
injection methods at Public Service of Indiana's  Edwardsport Station.
In 1968 and 1969 Air Preheater Company made similar evaluations at the
Mercer Station of the Public Service Electric and Gas Company of New
Jersey.

     During the early 1970's Superior Oil conducted pilot-plant studies
of fixed-bed dry absorption as well as dry injection, using an ESP for
particulate matter collection.  Wheelabrator-Frye conducted further dry
injection - baghouse collection studies at the Nucla Station of the
Colorado Ute Electrical Association in 1974.

     A number of absorbents  were evaluated during these studies, including
dolomite,  limestone, quicklime, hydrated lime,  sodium bicarbonate, soda
ash,  and nahcolite.   Bechtel (16)  in summarizing  these studies concluded
that  only sodium-based absorbents  were sufficiently reactive to warrant

                                   23

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further investigation in dry injection FGD processes.   Of the absorbents
tested, nahcolite (a naturally occurring sodium bicarbonate)  proved most
effective, exceeding both soda ash and manufactured sodium bicarbonate
in removal efficiency (up to 90% at 90% conversion).   Commercial sodium
bicarbonate is prohibitively expensive for use as a nonregenerated
adsorbent.  Soda ash is less expensive although considerably less efficient
than sodium bicarbonate.  Nahcolite has, therefore, attracted much
attention for use in dry absorption FGD processes.
NAHCOLITE

     Nahcolite, a naturally occurring sodium bicarbonate (NaHC03)
mineral, is one of several sodium-based compounds that occur as evaporite
deposits.  Although ore-grade deposits are uncommon, extensive deposits
are found in the Green River formation of Colorado, Wyoming, and Utah.
The Unitas and Green River formations, fluvial and lacushrine basin
deposits of the Eocene Age, constitute the much-discussed oil shale
areas of that region (19).  In the Green River Basin in Wyoming a
flourishing captive mining industry produces trona (Na2C03'NaHC03'21^0)
from underground mines in the Green River formation for soda ash manu-
facture  (20).  Yet another sodium mineral, dawsonite [NaAl(OH)2C03]
also occurs in the Green River formation in greater tonnage and wider
areal extent than nahcolite, although in a more dispersed form.  This
dawsonite has been suggested as a potential alumina source in the future.

     The major nahcolite deposits are located in the portion of the
Green River formation lying in the Piceance Creek Basin of Northwestern
Colorado.  The deposits of most immediate economic interest occur as
horizontal beds up to 20 feet thick at 1500 feet or more beneath the
surface.  These nahcolite deposits are of remarkably high quality, some
containing up to 85% NaHC03.  Other nahcolite occurs as lenses, nodules,
and disseminated particles.  Although proven reserves are sufficient for
many years of high-volume mining, commercial mining of nahcolite has not
developed.  Bechtel (16) and Lutz et al. (21) discuss the status of
nahcolite mining in detail.  The intimate association of nahcolite with
oil shale and dawsonite and the resulting complexities of Federal and
State lease restrictions, problems with overlying incompetent strata,
dusting  and explosive conditions, and uncertain demand (only widespread
power plant FGD use offers a market sufficient to justify mine development
costs) have all acted to delay nahcolite mining development.  Several
mining companies are actively pursuing mine development plans, however
(22, 23).  Lutz et al.  (21) estimate nahcolite suitable for FGD can be
produced for $20 to $30 per ton at the mine.

Process  Chemistry

     One of  the main disadvantages in using a nahcolite injection system
for FGD  is its required operating temperature for high S02 removal
efficiencies.  NaHCO- decomposes to Na 0, E^O, and C02 at about 260 C
(500°F).  Thus, if nahcolite is injected at relatively high flue gas
temperatures,  this decomposition reaction leads to porous particles of

                                    24

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Na 0 as the gases are expelled from the interior of the particles.  This
significantly increases the surface area of .the particles that is available
for reaction with SO- and minimizes pore plugging and the presence of
unreacted Na^O in the core of the particles!
utilization.
     Nahcolite reactions include the follow:

                 2NaHC03'Na2C03-2H20 ->• 2Na2(

                                 S02 -»• Na2S(
                     Na2S03 + 1/2 02 -> Na2S(

     At temperatures less than about 260 C i
NaHC03 decomposes and S02 removal is achieve
absorbed S02 with NaHC03.  Since none of the
occurs at these temperatures, internal pores
small and easily plugged.  This decreased
tends to result in poor raw material utilize
layers are converted by reaction with S0«.
     From the limited pilot-plant data avail
that the SO,, removal efficiency increases as
increases with temperature up to about 500 ]'
SO,, removal efficiency approaches 90% in an
in most boilers this flue gas temperature oc
heater (the flue gas enters the air heater
         At higher temperatures (those at tl
                              Nahcolite rea(
300 F).
removal efficiency declines.
S02 removal at about 550°F.
     Thus, in order to achieve the optimum J
500 F, one of three expensive alternatives i
                                             thus maximizing absorbent


                                            ng:

                                            03 + C02 + 3H20

                                            3 + C02
                                            500 F) very little of the
                                            d only by the reaction of
                                             explosive release of C02
                                             in the particle tend to be
                                          surface area for reaction
                                            tion since only the outer
able, it appears
 the flue gas temperature
   At this temperature the
optimum design.  Unfortunately
curs inside the boiler air
.t about 700 F and leaves at
.e economizer exit) the SO,,
lies a maximum reactivity for
                                            lue gas temperature of
                                            eeds to be selected.  The
boiler design could have twice as many air heaters, each with about half
the surface area of a conventional air heater, so that the first air
heater only cools the flue gas to the range of 500 F to 550 F while the
second (directly after the FGD system) cools the flue gas to the normal
air heater exit temperature of 300 F.  Not only would the capital expense
for the boiler increase because of the increased number of boiler air
heaters, but the thermal efficiency of the boiler would decline since
the FGD system and the second air heater would result in additional heat
losses.  A second alternative would be to simply bypass some of the flue
gas around the boiler air heater to achieve the 500 F flue gas temperature
to the FGD system.
                    Again, however, this could substantially decrease
                                       The third alternative would be to
the thermal efficiency of the boiler.
preheat the incoming 300 F flue gas with an auxilary burner.

     None of the three alternatives is economically attractive.  Thus at
the present time most of the development work concerns those applications
in which significantly less than 90% S02 removal is required (i.e., the
70% standard under the 1979 NSPS).   From the limited pilot-plant data
                                   25

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now available, it appears that nahcolite injection systems may be able
to average the 70% SC>2 removal which is potentially possible at conventional
boiler air heater exit temperatures.  Although this SC>2 removal is
technically feasible, whether the low nahcolite utilization and other
economic factors will allow an economic advantage over these systems is
uncertain.

     The inability to achieve 90% S02 removal may limit the widespread
application of nahcolite injection systems.  Low-sulfur coals that
require only 70% S02 removal (i.e., those coals where the 70% control
would result in an emission rate of less than 0.6 Ib S02/MBtu heat
input) will for the most part be western bituminous and subbituminous
coals that have less than about 1.2% sulfur (based on 11,700 Btu/lb).
Although lignites typically contain less than 1.0% sulfur, they have
such a low heating value that the upper limit on sulfur level is in the
range of 0.76% (based on 9,500 Btu/kWh and 6,500 Btu/lb).  In either
case, since the range of sulfur levels in the coal from a particular
seam may vary, only those applications where the average sulfur levels
are somewhat less than these values could consider nahcolite injection
(barring a technical development which would significantly improve the
S02 removal efficiency at these temperatures).

     The S09 removal efficiency as a function of stoichiometric ratio is
dependent on the nahcolite injection method used, as discussed below.
As shown in Figure 4, in order to maintain the required 70% S0« removal
efficiency required by the 1979 NSPS, the nahcolite:S02 stoichiometric
ratio would range from approximately 1.0:1.0 for the batch injection
system to 1.5:1.0 for the continuous injection system.  For the semibatch
injection method, the S0? removal efficiencies would be expected to be
nearly the same  (although slightly lower) as those of the batch method.

     Dry injection systems will typically involve injection of a finely
powdered absorbent to maximize the surface area available for gas-solid
contact.  Results from a previous study  (24) indicate that under the
same reaction conditions decreasing the particle size from 70% through
200 mesh to 70%  through 400 mesh increases the SC>2 removal efficiency
(at a stoichiometric ratio of 0.8)  from 58% to 75%.  Of course decreasing
the particle  size involves higher capital and operating costs and thus
involves an economic tradeoff between higher annual capital charges
versus increased operating costs for raw materials.

Injection Systems

     As has been noted in previous  studies, there are several methods of
injecting nahcolite  into the  flue gas stream  (21):  continuous, batch,
or semibatch.  In the continuous injection system, the nahcolite is
                                   26

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6-S
Pi

CM
o
C/3
     90
     80
     70
     60
     50
     40
30
     20
     10
                                       Continuous
                    I
                           I
I
I
   Figure 4.
             0.5         1.0          1.5         2.0



            STOICHIOMETRIC  RATIO,  mol Na2/mol S02 in



          S02 removal  efficiency as  a function of stoichiometric

          ratio  and  injection  method for nahcolite (24).
                                    77

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added upstream of the baghouse and travels,  entrained in the flue gas,
to the baghouse where it is captured to form a coating on the fabric
filters.  Advantages of this system include  a longer residence time in
contact with the flue gas, a low initial pressure drop which gradually
increases as the cake builds up, potentially less operating manpower
since the nahcolite can be added by process  equipment, lower capital
investment for the injection equipment since only one injection point
per flue gas duct is required, and less spare baghouse capacity since a
normal cleaning cycle can be used and the baghouse compartment can
theoretically come back on-line immediately.  The primary disadvantages
include the potential loss of S02 removal in the clean compartment until
an alkali cake has been built up and the potential for poor distribution
of the nahcolite resulting in areas of the bags having no cake so that
the S02 passes through unreacted.

     Since most of the S02 removal may occur as the flue gas passes
through the nahcolite cake built up on the fabric filter, a continuous
injection system (where the nahcolite is injected into the flue gas
ducts and is carried to the bags entrained in the flue gas) results in
very little S02 removal immediately after the cleaned compartment comes
back on-line.  As the nahcolite cake builds up the instantaneous  (as
opposed to average) S09 removal efficiency increases until a maximum S0~
removal efficiency occurs immediately before the compartment comes off-
line for cleaning.  Thus, the integrated, or average, S02 removal efficiency
over the entire baghouse  cycle  is significantly lower than this maximum
instantaneous S02 removal efficiency.  For example, during one series of
pilot tests a maximum SC>2 removal efficiency of 67% at a stoichiometric
ratio of 1 was obtained.  However, the average SC>2 removal over the
complete cycle was only 50%.  For an average 70% SC>2 removal over the
complete cycle  (as required by  the 1979 NSPS) the stoichiometric  ratio
had  to  be increased to  1:5  (24).

     The batch injection  system involves precoating the bags with a
layer of nahcolite following  each cleaning cycle.  Advantages of  this
system  include better control over the distribution of the nahcolite on
the  filters and  the presence  of nahcolite on the bags as soon as  the
compartment comes back  on-line.  Disadvantages include the higher capital
investment  for multiple injection points, a higher initial pressure drop
after bag cleaning, additional  off-line  time for each compartment as it
is precoated, and additional  delay time  for high S02  removal  to begin
since  the nahcolite must  achieve  reaction temperatures before efficient
S09  removal begins.

      S02 removal can begin as soon as  the bags come back on-line  since
there.is a  nahcolite  cake already present.   In fact,  to  give  the  same
maximum S02  removal  previously  given for the  continuous  injection (67%)
requires a  stoichiometric ratio of  only  0.9:1, and  furthermore,  the
average S02 removal  over  the  baghouse cycle was  66%  versus  only  50%  for
the  continuous  injection  system.

      Since  high SO-  removal (>90%)  at acceptable raw material utilization
rates is  difficult  to  achieve under  the best  conditions  (even without
 suffering  almost no  S0? removal for  the startup  period),  the compromise

                                     28

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or semibatch system is currently being favored.   Immediately following
compartment cleaning, an initial precoat is added before the compartment
is brought on-line.  Nahcolite is also continuously injected upstream of
the baghouse.  Although requiring more equipment than either the continuous
or the batch system, the semibatch method has the advantage of providing
a continuous supply of nahcolite in the baghouse for SC>2 removal.
Granted that the initial SC>2 removal efficiency (i.e., before the precoat
achieves reaction temperature) may be lower, some S02 removal will occur
as soon as the compartment comes back on-line.  Some will be achieved by
the entrained nahcolite and some by the relatively cool nahcolite precoat.
Thus, there is not a short time period after the compartment cleaning
when essentially no SO- removal occurs as is the case with both the
continuous and the batch injection system.

Waste Disposal

     Waste disposal for nahcolite or trona dry injection FGD systems is
a significant problem due to the water-soluble nature of the sodium
compounds.  Unless treated to reduce their solubility the sodium-based
wastes could easily leach into surface or underground water.  Thus,
unless the FGD system is located near a trona mining operation or a dry
lake bed of sodium salts or some other unique situation where the dumping
of the sodium waste would seem to have very little adverse environmental
effect, the disposal of these wastes could be prohibitively expensive.

     This environmental problem, in fact, is receiving considerable
attention since without a method to acceptably dispose of these FGD
wastes, nahcolite, or any other sodium-based system, may not be commercially
practical.  Three methods, which are described below, are currently
being discussed for these sodium wastes and one, insolubilization, is
being evaluated on a pilot scale by Battelle Columbus Laboratories.

Insolubilization—
     The waste from the baghouse containing both FGD waste and fly ash
is mixed with lime and the resulting mix is sintered at high temperature
to yield what is said to be inert, insoluble material.  The major process
currently being evaluated is the Sinterna® process (24) which was patented
by Industrial Resources, Inc.  Although this process has been claimed to
render the waste inert, no detailed, long-term technical evaluation has
been completed.  In addition the process economics—particularly the
apparent high energy consumption to sinter the waste—need to be independently
estimated.

Clay-Lined Isolation Cells (24)—
     This procedure involves excavating a large pit and lining the floor
and walls with a thick (12-24 inch) layer of impermeable clay.  Within
this protected boundary, individual cells, each probably sized to handle
approximately one days' supply of FGD waste (and fly ash) would be
built.  All of the walls would be made of clay and at the end of each
                                   29

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day a clay cap would be laid on top of each cell.  This method would
minimize the amount of water entering the cell and thus prevent the
waste from leaching into the surrounding area.  The primary unresolved
problem associated with this method is the relative cost of this disposal
system.  Other uncertainties include how long the disposal area needs to
be monitored for leaching and for integrity of the clay cap.

Regeneration of the Sodium Compounds—
     Since calcium-sulfur compounds are relatively insoluble, it would
be technically feasible to regenerate sodium carbonate by the reaction
of the FGD waste with limestone.  This of course is similar to double
alkali FGD systems (25) wherein wet-scrubber sodium salts absorb S02 and
the sodium solution is regenerated with limestone.  Since the sodium
salts will be a mixture of sulfites and sulfates, the FGD waste would
have to be dissolved in aqueous solution and then oxidized to sulfate to
avoid the disposal problems associated with sulfite-sulfate sludges.
The oxidized sodium solution could be reacted with limestone to precipitate
gypsum (CaS04'2H20) which would be filtered from solution and disposed
of in a landfill.

     None of these options appear to be economically attractive alternatives,
No other alternatives appear to exist at the present time, however.
TRONA

     In addition to nahcolite, the other dry injection alkali that is
receiving attention is trona.  Since NaHCOg is more chemically active
than Na?CO.,, it is not unexpected that at the same stoichiometric ratio
nahcolite fabout 80% NaHC03) can achieve a higher S02 removal than trona
(about 30% NaHC03).  Trona, however, has an advantage over nahcolite in
that it is already being commercially mined and is thus potentially
available in large quantities for FGD systems.  Since the active chemical
in trona is the same as that in nahcolite most of the process chemistry
is essentially identical to that given previously for a nahcolite FGD
system.  The primary difference is that much larger quantities of trona
must be used.  These larger trona requirements may be due to its lower
NaHC03 content.  The only major reaction difference between nahcolite
and trona is that trona appears to react rapidly upon injection in the
pilot-plant tests.

     From the limited pilot-plant data currently available (26) , trona
appears to increase in reactivity for S02 removal as the temperature
increases whereas nahcolite reactivity reaches a maximum at about 550 F.
Trona also appears to require a higher stoichiometric ratio to achieve
the same SOo removal efficiency.  S02 removal efficiency for nahcolite
and trona for continuous injection at 250 F is shown below.
                                   30

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                                                         SC>2 removal
                              Moles Na2/moles S02 in   efficiency, %

                 Nahcolite              1.0                 50
                                        1.5                 70

                 Trona                  1.0                 40
                                        3.0                 70

This comparison indicates that to achieve a minimum 70% S02 removal a
substantially higher feed rate is required for trona than for nahcolite.

     Part of the EPA-sponsored pilot-plant work involves upgrading the
raw trona to approximately 92% NaHC03.  This upgraded trona would reduce
the stoichiometric ratio required and, depending on the relative cost of
upgrading, might make trona a more economically practical alternative to
nahcolite for dry injection FGD systems.
PAST STUDIES AND CURRENT STATUS

     Numerous bench-scale and pilot-plant studies were carried out in
the early 1970's as part of efforts to develop a technically feasible
and cost effective dry FGD system for utility boilers.  In these test
programs numerous alkali raw materials for dry injection FGD systems
were evaluated, including limestone, lime, soda ash, sodium bicarbonate,
nahcolite, and trona.  These evaluations came to the same conclusion:
nahcolite was the best alkali for a dry injection FGD system.  Some of
these test programs are summarized below.

Past Studies

Nucla Station—
     In July 1974 Wheelabrator-Frye, Inc., began a pilot-plant program
at the Nucla Station of the Colorado Ute Electric Association.  This
unit is an 11-MW (gross) spreader-stoker-fired boiler burning an 0.8%
sulfur subbituminous coal.  Inlet flue gas typically contained 480 ppm
S02» although when higher sulfur coal (1.1% sulfur) was burned on
occasion, inlet S02 approached 900 ppm.   The nahcolite was supplied by
Superior Oil Company and averaged 60% NaHC03-

     The baghouse used in the test program was originally designed and
installed for fly ash removal only.   Most of the tests involved batch
operation of the nahcolite injection system (i.e.,  precoating the bags).
The flue gas rate was 44,000 aft3/min at 285 F.  S02 removal efficiencies
ranged from 50% to 70% depending on the raw material stoichiometry.  Raw
material utilization was approximately 56% at 70% S02 removal.

Leland Olds Station—
     During the first quarter of 1977, Wheelabrator-Frye operated a
pilot plant at Basin Electric Power Cooperative's Leland Olds Station

                                    31

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Unit 2 to demonstrate a nahcolite injection FGD system.  Leland Olds
Unit 2 is a 440-MW cyclone boiler burning 0.8% sulfur North Dakota
lignite.  The primary purpose of this test facility was to demonstrate
the technical feasibility of using a nahcolite-based FGD system for the
Ottertail Power Company's planned Coyote Station, which would be a
design similar to Leland Olds.  However, Wheelabrator-Frye also wanted
to evaluate the effects of several operating conditions, including
method of injection (continuous, batch, or semibatch), stoichiometric
ratio, and inlet 862 concentration.  An SC>2 spiking system was provided
for the evaluation of the removal versus the inlet S02 concentration.

     Figure 5 shows the SC>2 removal efficiency as a function of stoichio-
metric ratio for optimum operating conditions.  However, for tests
carried out at less than optimum conditions, removal efficiencies were
significantly lower.  Unfortunately, due to the proprietary nature of
the test work, neither were the less-than-optimum conditions identified
nor were the actual removal efficiencies under these less-than-optimum
conditions quantified.  In this pilot-plant system, which was designed
specifically to test nahcolite injection for a utility FGD application,
raw material utilization showed some improvement over the results obtained
at the Nucla test facility.  For example, 77% utilization at 83% S02
removal and 60% utilization at 90% S02 removal were claimed versus 56%
utilization at 69% S02 removal at Nucla.  However, even 60% utilization
means (as noted by the vendors) that significant amounts of excess
nahcolite must be injected to achieve the high S02 removal efficiencies
that may be required at commercial utility boilers.

     Development work on nahcolite injection for FGD at Leland Olds was
terminated in late March 1977 due to nahcolite supply problems.  (In
fact, this is essentially the current status of the nahcolite injection
technology.)  Since there did not appear to be any hope for these supply
problems to abate in the near future, investigations were undertaken for
alternative alkali raw materials.  However, lime, limestone, and soda
ash had been previously demonstrated to be insufficiently reactive for
dry injection at these temperatures, and when commercial NaHC03 was
found to be too expensive for a commercial utility application, the
search for an acceptable dry raw material was terminated and the development
work switched to modifying the process conditions so that commercially
available alkali raw materials (lime, soda ash, and trona) could be
used.  This, of course, led to the development of the spray dryer based
FGD system.

Current Status

     The attraction of a nahcolite injection process for FGD control—
less equipment and a totally dry system—has led to continuing interest
by various groups which continues even today.  Various bench-scale units
and small pilot plants are currently operating.
                                   32

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       90
       80
       70
       60
u
&
w
H
U
H
fe
Fn
W



I
o
Pi

CM
O
CO
       50
   40
   30
       20
       10
Figure 5.
                     I
                              I
I
                    Q.5         1.0         1.5         2.0



                 STOICHIOMETRIC RATIO, mol Na2/mol S02 in



                S02 removal efficiency as a function of stoichiometric

                ratio for nahcolite injection  (24).
                                     33

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KVB, Inc.—
     KVB, Inc. has been carrying out bench-scale tests under contract
with EPRI since late 1977.  The primary purpose of this work is to
evaluate various alternative sodium-based raw materials including
trona, nahcolite, and commercial NaHC03 at different flue gas temperatures,
sorbent residence times, and stoichiometric ratios.  Flue gas is provided
by a coal-fired bench-scale combustor generating 725 sft-Vmin.

     Preliminary results using nahcolite indicate that maximum S02
removal efficiency is achieved at about 290°C (550°F) with removal
efficiency declining as the flue gas temperature increases above or
decreases below 290 C (550 F) .  For example, at a stoichiometric ratio
of 1:0 (mol Na2/mol S02 in), S02 removal was 67% at 150°C (300°F) , 80%
at 290°C (550°F) , and 60% at 425°C (800°F) .  (These are maximum instan-
taneous S09 removal efficiencies — the integrated S0? removal over the
total cycle is significantly less.)

Carborundum (Now Carborundum Environmental Systems) —
     Since 1976 Carborundum has been operating both a small (100 aft /min)
bench-scale unit and later a larger (1000 aft /min) bench-scale unit in
Knoxville, Tennessee.  The primary purpose is to evaluate various raw
materials including commercial NaHCO», nahcolite, and ammonia sorbents.
Due to the in-house nature of this research, essentially no data are
available.

Martin Drake Station —
     Buell has undertaken a pilot-plant study of a nahcolite injection
system for FGD control at the Martin Drake Station owned by the City of
Colorado Springs.  This program is being partially funded by EPA and
hence, perhaps for the first time, the actual pilot-plant data will be
available to the public (27) .

     This pilot plant is  treating a 3000 aft-Vmin slipstream of flue gas
from the Unit 6 boiler.   This unit is an 85-MW boiler burning a mixture
of three Colorado bituminous coals which average 0.5% sulfur and 12,000
Btu/lb.  The particulate  collection device for these nahcolite tests was
the pilot baghouse and an existing baghouse, originally designed for fly
ash control only and built by Buell.  The nahcolite for the test program
is being supplied by the  Bureau of Mines from their existing stockpile.
Other dry sorbents to be  evaluated include raw trona  (about 19% NaHC03)
and an upgraded trona (92%
     The pilot plant was started up in late 1979 and parametric testing
was completed in May 1980.  The various parameters which were evaluated
included stoichiometric ratio, inlet flue gas temperature, and inlet S02
concentration.

     In addition to evaluating these sodium-based dry sorbents, Buell is
also undertaking an EPA-funded waste disposal study based on the Sinterna
process.  This patented process was developed by Industrial Resources,
Inc.,  in which the waste material is sintered to make the material less
soluble.  The actual evaluation is being carried out by Battelle Columbus
Laboratories under a subcontract with Buell.
                                   34

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     DEVELOPMENT AND CURRENT STATUS OF SPRAY DRYER FGD PROCESSES
     Most of the current development on spray dryer FGD has as its basis
the work done during the early 1970's with dry injection of nahcolite
for low-sulfur western coal applications.   Although the use of nahcolite
as a dry absorbent for S02 removal appeared promising from a technical
viewpoint, questions about its future availability in large enough
quantities for widespread FGD application led to the search for other
alkali raw materials (16).

     Other alkaline raw materials which did not have the availability
problems of nahcolite were limestone, lime, and soda ash.  Dry limestone
injection into the flue gas ducts had been previously attempted but with
disappointing results in terms of S02 removal and sorbent utilization.
Although both soda ash and lime are more reactive than limestone, these
raw materials could not simultaneously achieve the necessary high S02
removal efficiencies and the high utilizations required for economical
operation when injected into the flue gas (or precoated on filters) as
a dry powder (16).

     At approximately the same time, the use of a spray dryer as an S02
absorber in the regenerable Rockwell International aqueous carbonate
process (ACP) was underway.  The use of a spray dryer, although more
expensive than simple dry injection, offered many of the same advantages
as dry nahcolite injection, i.e., a relatively simple absorption system
with no need for recirculating large volumes of erosive slurry and the
production of a dry waste material.  Furthermore, by using the soda ash
and lime in the form of an aqueous solution or slurry, respectively,
both high S02 removal efficiencies (70% to 90%) and high absorbent
utilization (70% to 100%) could be achieved.

     The first use of a sodium carbonate solution in a spray dryer was
in 1972 (28) but this pilot-plant work was aimed at developing the spray
dryer as an absorber for the regenerable ACP process.  The first appli-
cations of the spray dryer for a waste-producing FGD system were not
until 1977.  Several upper midwestern electric utilities who had been
involved in the earlier nahcolite testing work had become interested in
the application of spray dryers for FGD.  Several companies built and
operated small pilot plants (about 10,000 aft-Vmin) to prequalify as
bidders for the first commercial installations (9).

     As a result of this and other pilot-plant development work, over a
dozen contracts have been awarded for commercial applications of spray
dryer FGD systems.  Five of these contracts are for industrial boiler

                                   35

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applications and the remainder are for utility boilers, as shown in
Table 2.  Wet lime and limestone FGD systems have been selected over the
spray dryer systems for at least two low-sulfur western coal applications.
These are the particular applications where the spray dryer FGD systems
are claimed to have a significant economic advantage over wet lime and
limestone scrubbing, and the specifics of why the spray dryer FGD systems
were not selected have not yet been revealed.

     In addition to these commercial utility applications, numerous
companies are currently building or operating pilot-plant units (<10,000
aft^/min) to further develop spray dryer technology.  Those on which
data were available through June 1980 are shown in Table 3.  At least
two of these pilot plants are mobile units that are set up on trucks and
can be moved to different utility sites, thereby giving these vendors an
opportunity to evaluate various site-specific conditions before preparing
bids.  These mobile units can also be moved to other sites where they
can be used for more general studies of the technology.

     For the most part, these pilot-plant units have been operated on
low-sulfur, highly alkaline coals (North Dakota lignites and western
subbituminous) in applications for which these processes appear to be
most economically attractive (i.e., only 70% SC>2 removal is required).
In fact most of the initial pilot plants listed for each company in
Table 3 were built in order to qualify as bidders for the utility FGD
systems listed in Table 2.

     The Joy/Niro unit at Riverside Station listed in Table 3 is more
correctly a 100-MW demonstration unit.  This unit will have a single
train consisting of a full-scale spray dryer (for a large plant multiple
spray dryers of this size would be used).  For particulate collection
either an existing ESP or a baghouse can be used.  The boiler is currently
firing a blend of low-sulfur (<1%) Montana subbituminous coal and high-
sulfur  (4%) petroleum coke.  Thus testing a full range of sulfur levels
is potentially available.

     On the following pages the history and current status, through June
1980, is discussed for each organization that is or has been active in
spray dryer FGD technology.  Most of the information was developed by
direct contacts with company representatives and site visits during 1979
and  1980.  It should be pointed out that the determination as to whether
a spray dryer facility is considered a pilot-plant unit, a demonstration
unit, or a commercial unit was based on the following arbitrary rules:
(1) if a utility or company purchased the equipment for the FGD system,
the unit was considered commercial unit regardless of its size; (2)
other units <10 MWe were considered as pilot-plant units; and (3) other
units >10 MWe but <125 MWe were considered as demonstration units.
                                  36

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                       TABLE 2.  CONTRACT AWARDS FOR SPRAY DRYER-BASED FGD SYSTEMS
Size, Fuel
Installation gross MW type (% S)
Utility Boiler
Coyote Unit 1 456 Lignite (0.78)
Laramie River Unit 3 575 Subbituminous (0.54)
Antelope Valley Unit 1 440 Lignite (0.68)
Shiras Unit 3 44 Subbituminous (1.5)
Stanton Unit 2 63 Lignite (0.77)
Craig Unit 3 447 Bituminous (0.70)
Holcomb Unit 1 319 Subbituminous (0.30)
Rawhide Unit 1 260 Subbituminous (0.29)
Springerville Unit 1 350 Subbituminous (0.69)
Springerville Unit 2 350 Subbituminous (0.69)
Industrial Boiler
Strathmore Paper Co. 14e Bituminous (2.0-2.5)
Celanese Fibers Co. 22e Bituminous (1.0-3.5)
Calgon 17e
University of Minnesota 83e Subbituminous (0.6-0.
Argonne National Lab. 29e Bituminous (3.5)
S02 Alkali raw Startup
removal, % material date

70
85
62
80
73
87
80
80
61
61

75
70-80
75
7) 70
80

Soda ash
Lime
Lime
Lime
Lime
Lime
Lime
Lime
Lime
Lime

Lime
Lime
Soda ash
Lime
Lime
Based on contact with vendors representing the status of announced contracts through
a. Rockwell International/Wheelabrator-Frye.
b. Western Precipitation Division of Joy Manufacturing
c. Babcock & Wilcox.
d. Research-Cottrell.

Company /Niro



Atomizer, Inc.



4/81
4/82
4/82
9/82
9/82
4/83
6/83
12/83
2/85
9/86

7/79
1/80
6/81
9/81
9/81
October




Vendor

RI/WFa
B&WC
Joy/Nirob
Buell/Anhydro
R-Cd
B&W
Joy/Niro
Joy/Niro
Joy/Niro
Joy/Niro

Mikropul
RI/WF
Niro/Joy
Carborundum
Niro/Joy
1980.




e.  Based on 2,900 aft3/MW.

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                        TABLE 3.   SPRAY DRYER PILOT PLANTS AND DEMONSTRATION UNITS  FOR FGD
                  Company
                                      Size,
                                    kaf t-Vmin
   Fuel
type (% S)
   Primary
alkali tested  Operating period
CO
Babcock & Wilcox

Alliance Research Center
W. J. Neal Station Unit 2
  (Basin Electric)

Jim Bridger Unit 3
  (Pacific Power and Light)

Buell-Envirotech/Anhydro, Inc.

Copenhagen Anhydro Laboratory

Martin Drake Unit 6
  (City of Colorado Springs)
       Carborundum Environmental  Systems

       Carborundum Knoxville  Laboratory


       Carborundum Knoxville  Laboratory

       Leland Olds Station  Unit 1
        (Basin  Electric)
                                               1.5     Various  coals

                                               8.0     Lignite  (0.4)
                                              3.0
                                             20.0     Subbituminous  (0.5)
                                        0.1
                                        1.0     Bituminous (0.5)
                                       15.0     Lignite (0.6)
                  Lime

                  Lime
                                             120.0     Subbltuminous  (0.6)   Lime
               Ongoing

               June 1978-
                May 1979

               August 1979-?
                  Lime, soda     Ongoing
                   ash

                  Lime, trona    December 1979-
                                  Fall 1980
                  Lime, NH3 ,      1976-1977
                   NaHC03, and
                   nahcolite
                  Lime, Na2C03 ,   Ongoing
                   and fly ash

                  Lime, NH3,     April 1978-
                   and soda ash   October 1978
                                                    (continued)

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                                        TABLE 3.   (continued)
Company
Size,
kaf t-Vmin
Fuel
type (% S)
Primary
alkali tested
Operating period
Combustion Engineering

Sherburne County Unit 1
  (Northern States Power)              20.0

Gadsden Unit  1
  (Alabama Power)                      20.0

Ecolaire Environmental Corporation

Gerald Gentleman Unit lb
  (Nebraska Public Power)              10.0

Joy Manufacturing/Niro Atomizer, Inc.

Niro Laboratory Copenhagen             3.0
Hoot Lake Unit 2
 (Ottertail Power)
Riverside Station Units 6 & 7
 (Northern States Power)
 20.0
640.0
           Subbituminous  (1.0)   Lime
           Bituminous  (1.8)
Lignite
                      Lime
                July  1979-
                 January  1980

                May 1980-?
           Subbituminous (0.3)   Lime
                                      January  1980-?
Lime, MgO, and  Ongoing
 soda ash

Lime, soda ash  February 1978-
                 April 1978
                September 1978-
                 December 1978
Subbituminous (1.0)   Lime
Petroleum coke (4.0)
                September 1980-
                 August 1983
                                        (continued)

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                                        TABLE 3.  (continued)
             Company
  Size,
kaft^/min
       Fuel
    type (% S)
   Primary
alkali tested   Operating period
Research-Cottrell, Inc.

Big Brown Unit 2
 (Texas Utilities)

Comanche Unit 2
 (Public Service of Colorado)
  10.0
  10.0
Lignite (1.0)
Lime
Subbituminous (0.5)   Lime
June 1979-
 Early 1980

May 1980-
 February 1981
Rockwell International/Wheelabrator-Frye,  Inc.

Stork-Bowen Engineering Laboratory     5.0
Leland Olds Station
                                  Lime, soda ash  Ongoing
(Basin Electric)

Joliet Station
(Commonwealth Edison)
b
Sherburne County Unit 3
(Northern States Power)
b
Jim Bridger
(Pacific Power and Light)

10.0 Lignite (0.6) Lime


5.0 Subbituminous (0.5) Lime


5.0 Subbituminous (0.8) Lime


5.0 Subbituminous (0.6) Lime

May 1977-
September

July 1979-
July 1980

May 1979-
July 1979


1978







August 1979-
September
1979

Based on contacts with vendors and representing information through June 1980.
a.  Propane burner with S02 spiking.
b.  Mobile unit.

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BABCOCK & WILCOX (29)

     Babcock & Wilcox (B&W) entered the spray dryer FGD field in early 1977.
The initial test work used a Hitachi, Ltd., (Japan) vertical spray
dryer/reactor that has since been replaced by a horizontal reactor
incorporating a modified B&W Y-jet nozzle atomizer.  This use of a two-
fluid nozzle atomizer is unique among the various spray dryer FGD
vendors who have contracted for commercial units.  Because of its
developmental status, it has created some operating problems at B&W's
pilot and demonstration units.  B&W is also unique among commercial-unit
vendors in recommending the use of an ESP for particulate collection for
spray dryer FGD systems.  B&W is also the only spray dryer vendor that
builds all of the major equipment for their FGD system.

Background and Current Status of Development

Pilot-Plant Units—
     William J. Neal Station—With the realization that spray dryer FGD
systems were becoming an FGD alternative, particularly for western coals
and lignites, B&W built a spray dryer pilot plant in late 1977 and early
1978 at Basin Electric Power Cooperative's William J. Neal Station
Unit 2.  Unit 2 is a 20-MW pulverized coal boiler burning North Dakota
lignite that averages 0.4% sulfur and has a 7,900 Btu/lb heating value.
The flue gas conditions at this boiler were similar to the projected
design conditions for the Antelope Valley Unit 1 boiler (which B&W
subsequently bid) and, in fact, this pilot plant was built primarily to
demonstrate B&W's spray dryer FGD system and thereby qualify to bid on
the FGD system for Antelope Valley.

     Initially the pilot plant used a Hitachi, Ltd., vertical spray
dryer/reactor but the test results did not appear promising.  Instead of
continuing with the Hitachi spray dryer/reactor, B&W modified a Y-jet
nozzle (which B&W had originally designed for use in an oil-fired boiler)
for use as an atomizer for their spray dryer/reactor.  The atomizers
were arranged in a matrix on one wall of a horizontal reactor.  Flue gas
entered through registers (again similar to a boiler design) around each
nozzle.

     This modified spray dryer/reactor, rated at 8,000 aft^/min, was
used for the remainder of the test program.  Flue gas from the spray
dryer/reactor was then passed through an ESP for particulate collection.
An S02 spiking system and lime preparation equipment were also included.
Testing with this system continued from June 1978 until May 1979.
During these tests three different coals were fired in the Unit 2
boiler.  In addition to the North Dakota lignite normally burned, a
Wyoming subbituminous coal from the Powder River Basin (0.5% sulfur) and
a Montana subbituminous coal (1.2% sulfur) were used.  (The Wyoming
subbituminous coal is similar to that which will be burned in the Laramie
River Station Unit 3 where B&W ultimately was awarded a contract for the
spray dryer FGD system.)  Although lime was the chosen absorbent and was
used for most of the tests, other alkalis were also evaluated.  These
                                  41

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included hydrated lime, limestone, soda ash,  magnesia,  and ammonia.
Even though all three coals burned at the Neal Station produce an alkaline
fly ash, B&W apparently did not run tests using waste recycle.  The
pilot plant was dismantled in mid-1979.

     Alliance Research Center—With the closing of the pilot plant at
the William J. Neal Station, B&W constructed  a small pilot plant at
their Alliance Research Center to continue the development and testing
of their process.  This pilot plant uses a small coal-fired combustor
producing 1,500 aft-'/min of flue gas.  In contrast to the large units
using multiple arrays of nozzle atomizers, the spray dryer/reactor at
Alliance has a single nozzle atomizer.  A cyclone is used for particulate
collection.  An ESP and a baghouse may be evaluated in the future.

     This pilot plant is being used to test a range of spray dryer/reactor
operating conditions, initially for the lime-based system but probably
for several alternative absorbents later.  B&W also intends to use the
pilot plant to increase the understanding of  the SC>2 removal reaction
mechanism and therefore determine how they can optimize their reactor
system.  In addition, the performance of the  lime-based FGD system will
be monitored while about five different coals are burned.  These coals
include North Dakota lignite, western subbituminous, as well as eastern
low-sulfur, medium-sulfur, and high-sulfur coals.

Demonstration Units—
     Jim Bridger Station—Early in 1979 B&W,  Pacific Power & Light,  and
Idaho Power & Light reached an agreement under which B&W built a demon-
stration-size reactor for treating 120,000 aft^/min of the flue gas  from
Jim Bridger Station Unit 3.  Unit 3 is a 500-MW boiler burning a Wyoming
subbituminous coal that averages 0.6% sulfur  and has a heating value of
9,500 Btu/lb.  Both B&W and the owners of Jim Bridger were interested in
demonstrating the spray dryer technology.  B&W was interested in demon-
strating (and obtaining the data necessary for proving) their full-scale
spray dryer/reactor design.  The owners of Jim Bridger, on the other
hand, have a power unit that must be retrofitted with an FGD system.
Since this boiler unit burns a low-sulfur coal and has a relatively  high-
alkaline fly ash, a spray dryer FGD system appeared to be an attractive
alternative.

     The demonstration unit treats about 120,000 aft^/min in a single,
spray dryer/reactor containing six nozzle, atomizers.  Most of the flue
gas from the reactor reenters the boiler ductwork and passes through the
existing boiler ESP's.  However, a 5,000 aft^/min slipstream is routed
through a pilot baghouse for particulate collection.  The lime preparation
system uses a closed-loop, wet ball mill slaker.

     Design and construction of this demonstration unit was completed in
July 1979, and it was started up in August.  Although the demonstration
plant has been able to follow boiler load changes without any significant
problems, there have been some operating problems in the spray dryer/reactor.
Troubles with poor atomization and flue gas distribution have led to wet

                                   42

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operation, plugging of the atomizers, and inability to closely approach
flue gas saturation temperatures.   B&W has recently switched from steam
to compressed air for the atomizing fluid to alleviate some of these
operating problems.  Since this demonstration plant was intended to
demonstrate the design for B&W's commercial FGD system at Basin Electric
Power Cooperative's Laramie River Station Unit 3, any significant
design changes at Jim Bridger will probably be incorporated into the
Laramie River design.

     B&W is now testing only lime absorbent although they hope to evaluate
ammonia, soda ash, and a sodium-based waste liquor in the future.  Tests
for the lime-based slurry were originally projected to continue for 4 to
6 months (i.e., until January 1980) however, atomization problems have
delayed the schedule somewhat.

Commercial Units—
     Laramie River Station—In November 1978 B&W was awarded a contract
for a spray dryer FGD system for Basin Electric Power Cooperative's
Laramie River Station Unit 3.  Unit 3, currently scheduled for startup
in April 1982, will be a 575-MW boiler burning a low-sulfur Wyoming subbitu-
minous coal from the Powder River Basin that averages 0.54% sulfur and
has a heating value of 8,000 Btu/lb.  The FGD system is designed to
treat 2,300,000 aft3/min (286°F) containing 530 ppm S02-  The system is
designed and guaranteed for 85% S02 removal under average coal conditions
and 90% S02 removal for the worst-case coal sulfur level (i.e., designed
to meet the stringent Wyoming SIP of 0.20 Ib S02/MBtu heat input to the
boiler).

     The FGD system for the Laramie River Station Unit 3 will consist
of four spray dryer/reactors, each with 12 nozzle atomizers arranged in
a 3 by 4 array.  Although originally designed with steam as the atomizing
fluid, after the recent test work at Jim Bridger the atomizing system
has been modified to use compressed air.  Under full-boiler load only
three of the spray dryer/reactors will be operating with the other as an
in-line spare.  Each reactor will be followed by an ESP (i.e., four
parallel trains of reactors and ESP's) for particulate collection.

     Although this unit was originally designed without provision for
waste recycle, B&W has modified its design philosophy and this installation
will now use waste recycle.  The FGD system is also designed for hot gas
bypass.  Approximately 3% of the total flue gas from the boiler economizer
will be bypassed around the spray dryer/reactor to achieve a 15 F to
20 F reheat.  Waste disposal will be in an existing FGD sludge pond.
(Units 1 and 2 at the Laramie River Station have limestone slurry FGD
systems with pond disposal.)

     Craig Station—In March 1980, B&W was awarded a contract for a lime
spray dryer system for Colorado-Ute Electric Association's Craig Station
Unit 3.  Unit 3 will be a 447-MW boiler burning a Colorado bituminous coal
that averages 0.7% sulfur and has a heating value of 10,000 Btu/lb.  The
FGD system is designed for 87% S02 removal under average coal conditions.
Projected startup date is April 1983.

                                   43

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     The FGD system will be designed essentially the same as the one for
Laramie River Unit 3.  The system will consist of four spray dryer/
reactors, each with 12 nozzle atomizers.  As at Laramie River, three
reactors will be operating and one will be an in-line spare.  At the
utilities request particulate removal will be achieved by using a
baghouse after the reactors.  FGD waste recycle will be used and hot gas
bypass provisions will be incorporated.

Conceptual Design

     The following conceptual design (see Figure 6) for a 500-MW coal-
fired boiler is based on B&W's recent full-scale contract awards.  The
design assumes a lime system for a low-sulfur western coal application
requiring a 70% SC>2 removal efficiency.

     Flue gas from the boiler air heaters at about 300 F enters a common
plenum that distributes the gas to the four trains of spray dryer/
reactors.  During normal full-boiler load operation only, three trains
are operating and the fourth is an in-line spare.  Each reactor has 12
horizontal nozzle atomizers arranged in a 3 by 4 array.  The atomizing
fluid is compressed air.

     B&W's original design philosophy was to operate the spray dryer/
reactor so that the flue gas closely approached its saturation temper-
ature, and thereby maximizing S02 removal efficiency and absorbent
utilization.  However, B&W has changed its design so that the approach
to saturation is now 15 F to 20 F and some type of waste recycle will be
included in their spray dryer FGD systems.

     Each spray dryer/reactor is followed by an ESP which collects the
FGD waste (B&W will provide a baghouse if it is specified).   Although
some additional S02 removal is usually achieved in a baghouse and an ESP
probably would not provide this additional removal, the ESP is claimed
to be more adaptable to upset conditions, and there is also more experience
with operating an ESP than a baghouse.  Flue gas from the ESP passes
through an ID fan and into the stack plenum.  FGD waste from the ESP
hoppers is periodically moved to intermediate storage hoppers before
being trucked to a landfill for disposal.

     Pebble lime is received by rail and stored in concrete silos onsite.
This lime is removed as needed, conveyed to a ball mill slaker, slurried,
and pumped to the spray dryer.

Technical Considerations

     The B&W spray dryer/reactor is based on using their Y-jet slurry
atomizer, shown in Figure 7, which was originally developed for use as
a fuel oil atomizer in oil-fired power units.  Although this nozzle-type
atomizer was to use steam as the atomizing fluid, recent test work has
indicated that compressed air gives better results.  Each of the full-
scale spray dryer/reactors is designed with 12 of these Y-jet slurry
atomizers arranged in a 3 by 4 array.  The atomizers are mounted horizon-
tally in one wall of the spray dryer/reactor (see Figure 8).  Flue gas

                                  44

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          BY-PASS REHEAT
REACTOR-
         w
               A
 PRECIPITATOR
Wlvlvlv
                             ID FAN
STACK
  Figure 6.   Conceptual design for the Babcock & Wilcox spray dryer FGD process (9) .

-------
DISTANCE PIECE
        \
    SLURRY
  /ATOMIZING
      AIR
                        GAS  FLOW
                        GAS FLOW
     Figure 7.  Design of two-fluid nozzle atomizer for the Babcock &
               Wilcox spray  dryer FGD process  (9).
                           46

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                                                                                  CONDITIONED
                                                                                    GAS TO
                                                                                  PART ICULATE
                                                                                   COLLECTOR
 FLUE
 GAS
INLET
   Figure 8.   Spray dryer/reactor design  for the Babcock & Wilcox FGD process (29)

-------
enters a manifold surrounding the atomizer array and passes out around
the barrel of the atomizer.  Intimate mixing of the slurry and flue gas
occurs just inside the spray dryer/reactor wall and continues throughout
the length of the reactor.  The B&W design philosophy is to closely
approach (within 20 F) the flue gas saturation temperature to obtain a
high SC>2 removal efficiency and absorbent utilization in the spray
dryer/reactor.

     B&W is using an ESP for particulate collection in their FGD system
even though baghouses tend to increase SC>2 removal as the flue gas
passes through the absorbent-based waste coating the bags.  ESP's are
not likely to achieve as much additional SC>2 removal since most of the
flue gas passing through the ESP does not come into intimate contact
with the FGD waste.  However, since the amount of S02 removed in the
baghouse is reduced at higher absorbent utilization (which B&W claims
for their spray dryer/reactor), B&W has decided to use an ESP for
particulate collection in most applications.  The other reason for using
the ESP is that it is thought to be more tolerant of upset conditions in
the spray dryer/reactor.

     The ESP can be used even in low-sulfur coal applications where fly
ash resistivity has been a problem because the spray dryer FGD system is
claimed to condition the flue gas.  There are several reasons for believing
that this is the case for most applications. The spray dryer cools and
humidifies the flue gas.  Since the resistivity curve tends to fall off
from its peak at the air heater temperature, cooling the flue gas should
enhance the collection efficiency.  Humidifying the flue gas also tends
to increase precipitator efficiency.  The third reason for better than
expected collection efficiency in the ESP handling fly ash from low-
sulfur coal is that not only does the FGD waste tend to produce larger
diameter particles, they may trap fly ash particles which are captured
by the lime slurry.

     B&W also designs their lime slaking system with a ball mill slaker.
The ball mill slaker is used to grind the pebble lime before the actual
slaking occurs.  This tends to result in very fine lime particles which
indicates the emphasis in the B&W system is on maximizing the absorbent
utilization in the first pass through the spray dryer/reactor.
                                   48

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BUELL-ENVIROTECH/ANHYDRO, INC. (30)

     The Buell Emission Control Division of Envirotech Corporation and
Anhydro, Inc., of Copenhagen, Denmark, are currently developing a spray
dryer FGD system as a joint venture.  Buell is a designer and marketer
of particulate control equipment (fabric filters, ESP's, and cyclones)
while Anhydro is a designer and marketer of spray dryers.  Together
these companies have a background in the two major types of equipment
for spray dryer FGD systems.  Buell will be the actual bidder on any
spray dryer FGD system and will subcontract the spray dryers to Anhydro
under their exclusive agreement.

Background and Current Status of Development

Pilot-Plant Units—
     Copenhagen Laboratory—Initial pilot-plant testing of the spray
dryer as an FGD absorber was completed in Anhydro's Copenhagen laboratory.
This test facility has a 6-1/2-ft-diameter spray dryer treating a simulated
flue gas from a propane burner.  The spray dryer is rated at 3,000
aft-Vmin and has a single, direct-drive, rotary atomizer.

     The first FGD tests consisted of injection of dry lime into the
flue gas ducts and then dry soda ash as a second attempt; neither gave
good SC>2 removal at acceptable raw material utilization rates.  This, of
course, led to the use of the spray dryer.

     Martin Drake Station—During 1979 Buell and Anhydro reached agree-
ment with the City of Colorado Springs to install a pilot plant at
Unit 6 of the Martin Drake Station.   In addition to the Buell/Anhydro
spray dryer work, Buell is also doing some nahcolite injection work for
EPA at Martin Drake at the same time (25).  Unit 6 is an 85-MW pulverized-
coal-fired boiler and burns a mixture of three Colorado bituminous coals
which average about 0.5% sulfur and have heating values of about 12,000
Btu/lb.  It also has an existing baghouse, designed and built by Buell.
Startup of this pilot plant began in December 1979, and the spray dryer
operations are funded for at least six months.

     This test unit has a 12-1/2-ft-diameter spray dryer (rated at
20,000 aftVmin) containing a single, rotary atomizer.  It treats a
slipstream from the boiler and uses a full-size test baghouse (15,000
aft3/min) for particulate collection.  In situ-resistivity tests were
also performed to evaluate an ESP for particulate collection.  An S02
spiking system was installed to allow tests with up to 2,500 ppm S02 in
the inlet flue gas.  Absorbents evaluated in the spray dryer system
include limestone and adipic acid,  trona, lime, and dolomitic lime.
Various recycle schemes are currently being evaluated for commercial
applications.  A detention slaker is used for the lime slurry generation.
The effects of bypass reheat, varied absorber inlet temperatures, and
prequenching before the absorber inlet have been tested.

Demonstration Units—
     No plans have been announced as yet for a demonstration unit.

                                  49

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Commercial Units—
     Shiras Station—In October 1980 Buell-Envirotech/Anhydro,  Inc.,
received a contract to provide a spray dryer FGD system for the City of
Marquette's Shiras Station Unit 3.  This unit is a 44-MW pulverized-
coal-fired boiler burning a western subbituminous coal averaging about
1.5% sulfur and having a heating value of 7,700 Btu/lb.  The FGD system
is designed to treat 226,100 aft^/min (at 265°F) of flue gas containing
1,500 ppm S02-  Design SC>2 removal efficiency is 80%.   The projected
startup date for the FGD system is September 1982.

     The system will contain a single 35-1/2-ft-diameter spray dryer.
The spray dryer will have one rotary atomizer.   A single eight compartment
reverse air baghouse will be used to collect the FGD waste and fly ash.
FGD waste recycle and hot gas bypass will be incorporated into the
system.  A paste-type slaker will be used with lime as the alkali raw
material.  Waste disposal will be handled by the City of Marquette.

Conceptual Design

     The following conceptual design for a 500-MW coal-fired boiler is
based on the pilot-plant data currently available.  As their process
becomes further developed, this process design may undergo some minor
design modifications, but the overall process description equipment, and
operating conditions are not expected to undergo any significant change.
The design is based on a lime system for a low-sulfur western coal
application requiring a 70% SC>2 removal efficiency.

     Flue gas from the boiler air heaters at about 300 F enters a common
plenum that distributes the gas to the six spray dryers.  During normal
full-boiler-load operations all six trains are operating.  Each spray
dryer reactor contains a single rotary atomizer.  The spray dryers are
insulated and enclosed in a simple, shell-type building.  The six spray
dryers feed a single baghouse.  The flue gas from the baghouse passes
through four ID fans and into the stack plenum.

     The compartments in the baghouse are periodically emptied, and the
waste is pneumatically conveyed to storage hoppers.  No data have been
released on the method of waste recycle to be used in the Buell/Anhydro
system (i.e., where the waste will be removed,  or how the waste will be
recycled).

     Pebble lime is received by rail and stored in concrete silos
onsite.  This lime is removed as needed, conveyed to a slaker,  slurried
and pumped to the spray dryer as needed.  In general,  a paste slaker
will be used.

Technical Considerations

     The Anhydro spray dryer contains a single rotary atomizer regardless
of how large the spray dryer is.Although this rotary atomizer is relatively
large and must handle significant quantities of lime slurry, this design


                                   50

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(one atomizer/spray dryer)  is typical of non-FGD applications.   Flue gas
enters the spray dryer through a scroll-type duct and passes in a concentric
ring around the single atomizer.  Flue gas leaves the side of the spray
dryer after making a 90-degree turn.   This design causes a decrease in
the flue gas velocity at the duct and most of the larger particles
entrained in the flue gas drop out in the bottom of the spray dryer.  A
rotary valve at the base of the spray dryer allows the removal of this
fly ash and FGD waste for recycle.  This design also allows for the
rapid cleaning of the spray dryer during any upset conditions when the
particulate matter remains wet at the flue gas exit in the spray dryer.
Since the particulate matter would be heavier when wet than when dry, it
would have a tendency to fall out at the base of the spray dryer rather
than passing on to the baghouse.

     Although the waste collected in the baghouse can be recycled, most
of the waste used in the recycle stream comes from the spray dryer.  The
recycle waste is pneumatically conveyed to the slurry mixing tank where
makeup water is added.  This resulting slurry is pumped through a
classifier (to separate the larger particles) to the spray dryers.

     Although the standard Anyhdro spray dryer for utility applications
has not been specified, each application normally consists of multiples
of a standard size.  The desired gas residence time (10 to 12 seconds)
is obtained by varying the height of the drying chamber.  Each spray
dryer is insulated and the spray dryer area may be enclosed in a simple,
shell-type building.  The design usually includes one baghouse with a
design air-to-cloth ratio (gross) of 2:1.
                                   51

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CARBORUNDUM ENVIRONMENTAL SYSTEMS (31)

     Carborundum Environmental Systems  is a subsidiary of Kennecott
Copper Corporation and is based in Knoxville, Tennessee.   During the
initial development and pilot-plant testing of their spray dryer-based
FGD system, Carborundum had an exclusive agreement with the De Laval
Separator Company to supply the spray dryers.  However, this agreement
has recently been terminated, and Carborundum has recently (1979) signed
a licensing agreement with Kochiwa Kakohki Company, Inc., a Japanese
spray dryer manufacturer.  The spray dryers for the Carborundum system
will be manufactured in the United States, while the rotary atomizers
may be manufactured in either Japan or the United States.  Baghouses for
the spray dryer FGD system will be designed and built by Carborundum.

Background and Current Status of Development

Pilot-Plant Units—
     Much of the development work for Carborundum's spray dryer FGD
system was done at a 100 ft-Vmin bench-scale unit at their test facility,
which was built in 1976, at the University of Tennessee in Knoxville.
Although initially designed to evaluate ammonia, sodium bicarbonate, and
nahcolite injection for FGD, it was later used to develop the lime spray
dryer FGD system in late 1977.

     Leland Olds Station—Initial pilot-plant work was done at Unit 1 of
Basin Electric Power Cooperative's Leland Olds Station.  Unit 1 is a
215-MW cyclone boiler burning a North Dakota lignite which typically
averages 0.6% sulfur and has a 7,000 Btu/lb heating value.  This pilot
plant started up in the spring of 1978 and operated approximately six
months.

     The test unit typically treated a slipstream of about 7,000 to
9,000 aft^/min in an 8-ft-diameter spray dryer, although both the spray
dryer and the baghouse were sized to handle  15,000 aft3/min.  The pilot
unit also contained an S02 spiking system.  Primary absorbents evaluated
during the test program were lime and soda ash.

     The goals of this test program were twofold.  The initial goal was
to complete tests to optimize the spray dryer system.  Parameters
evaluated included inlet S02 concentration (600 to 2,500 ppm), inlet
flue gas temperature  (275 F to 350 F), degree of approach to flue gas
saturation temperature, and raw material stoichiometric ratio.  Tests
with recycled waste were also made.  The other goal for the pilot-plant
tests at the Leland Olds Station was to qualify to bid on the FGD system
for Basin Electric's Antelope Valley Station.

     University of Tennessee—Additional pilot-plant work of the spray
dryer FGD system will be completed with a 1,000 aft-Vmin unit at a
University of Tennessee laboratory facility  in Knoxville.  This pilot
plant will treat a slipstream from a spreader stoker boiler burning an
eastern bituminous coal that averages 0.5% sulfur and has a 10,000
Btu/lb heating value.  Startup date for this pilot unit was June 1980,
and the test program will continue at least  through 1980.
                                   52

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     Primary absorbents to be evaluated include lime, soda ash, and fly
 ash.  Additional testing is also expected, but since this development
 work is being internally funded, the actual test program and any results
 are considered proprietary information.

 Demonstration Unit—
     No plans for a demonstration unit have been announced by Carborundum.

 Commercial Unit—
     University of Minnesota—During the first quarter of 1980 Carborundum
 Environmental Systems received a contract to provide the FGD system for
 two coal-fired boilers at the University of Minnesota.  This will be a
 retrofit installation on existing boilers that are being reactivated as
 part of a cogeneration system to provide both steam and electricity for
 the University.  These boilers burn a western coal averaging 0.6% to
 0.7% sulfur (maximum sulfur is 0.73%) and having a heating value of
 about 9,500 Btu/lb.  Each boiler generates 120,000 aft3/min (at 375°F)
 of flue gas containing 630 ppm S02-  The FGD system is designed to meet
 the NSPS (i.e., 70% overall SC>2 removal and 0.03 Ib of particulate
 matter/MBtu heat input) and is currently scheduled for startup in September
 1981.

     Each of the boilers will have a separate, but similar, FGD system.
 One FGD system will have a 24-1/2-ft-diameter spray dryer containing a
 single rotary atomizer.  The other will have a 27-1/2-ft-diameter spray
 dryer containing 3 rotary atomizers.  Flue gas from these spray dryers
 will not be reheated before entering the baghouses.  No provisions have
 been included for waste recycle.  Pebble lime will be prepared in a
 single lime preparation area (serving both FGD systems).  A paste-type
 slaker will be used.  Waste disposal will be handled by the University
 of Minnesota.

 Conceptual Design

     Although Carborundum has not been awarded any contracts for a full-
 scale commercial utility FGD system, the following process description
 for a 500-MW coal-fired power unit is based on their conceptual design
 (Figure 9)  and early pilot-plant experience.   Additional pilot-plant
 experience in the future may therefore cause some minor design modifi-
 cations, but the overall process description,  equipment, and operating
 conditions are not expected to undergo any significant change.

     Flue gas from the boiler air heater at approximately 300°F enters a
 common plenum which distributes the gas to the four trains of spray
 dryers (three operating and one spare).  The flue gas enters the spray
 dryer from the top and passes downward around each of the rotary atomizers.
 (Each spray dryer has three rotary atomizers.)   As the flue gas passes
 the rotating atomizer, the lime slurry is sprayed as a fine mist into
 the hot gas.  The atomized slurry and flue gas remain intimately mixed
 throughout their residence time in the spray dryer, where the SC>2 and
HC1 are absorbed in the droplets and react with the lime slurry.  The
water present in the spray dryer evaporates and the mixed calcium-sulfur


                                  53

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Ul
-O
             SPRAY  \
             DRYER—*
            REACTOR
    FEED
l—SLURRY
    TANK
D.  FAN
             Figure 9.  Conceptual design for the Carborundum spray dryer FGD process (31)

-------
salts and the fly ash flow to the bottom of the spray dryer.  At the
bottom of the spray dryer, the flue gas makes a 180-degree turn.  As the
superficial gas velocity decreases, the larger particles of entrained
particulate matter drop into a hopper from which they are periodically
removed.  The flue gas passes to the baghouse where the remaining solids
are removed and then through an ID fan to the stack.  The fly ash and
FGD waste from the spray dryer and the baghouse are pneumatically conveyed
to a temporary storage silo from which it is trucked to a disposal area.

     Pebble lime is received by truck or rail and is stored onsite in a
silo.  Lime is removed daily to fill the intermediate feed bin which in
turn feeds the ball mill slakers.  The pebble lime is slaked and pumped
first to the mills product tank and then to the slurry feed tank.  The
makeup lime slurry is pumped continuously from the slurry feed tank to
the rotary atomizers in the spray dryer.  Dilution water is also provided
continuously to the rotary atomizers.

Technical Considerations

     The Kochiwa Kakohki spray dryer is designed with three rotary
atomizers for full-scale utility applications.  The use of three rotary
atomizers decreases the size of each atomizer since each must atomize
only one-third of the total absorbent fed to the spray dryer.  This
design is claimed to result in a better mix of flue gas and atomized
absorbent and thus lead to better raw material utilization and a better
temperature profile through the spray dryer.  However, this use of
multiple atomizers also complicates the flue gas distribution to the
atomizers.

     Another claimed advantage for using multiple atomizers is that when
they are designed properly and have sufficient excess capacity, a spare
spray dryer is not necessary.   The vendors believe that if one of the
rotary atomizers fails,  the other two can maintain sufficient feed to,
and mixing in, the spray dryer so that SC>2 removal will not be seriously
affected for short periods of time (i.e., until the boiler load declines
and the spray dryer can be taken off-line).   They also believe that the
rotary atomizer can be changed while the spray dryer is on-line and
operating, if necessary.   Unfortunately (since the cost of the spare
spray dryer and its associated equipment is  a fairly significant com-
ponent of the total capital investment), design of an FGD system without
a spare in-line absorber is not a totally accepted practice in the
utility industry.
                                  55

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COMBUSTION ENGINEERING (32)

     Although Combustion Engineering has been installing limestone-based
FGD systems for several years,  they first entered into the development
of spray dryer FGD systems in June 1978 with their first conceptual
design.  Engineering design and planning continued throughout the remainder
of 1978 and construction of their first pilot-plant unit began in February
1979. During 1979 an exclusive agreement was reached with James Howden
Holima BV (The Netherlands)  for the use of their baghouse technology.
Combustion Engineering will use their own spray dryer technology.

Background and Current Status of Development

Pilot-Plant Units—
     Sherburne County Station—Initial pilot-plant work on Combustion
Engineering's spray dryer FGD system was begun in June 1979 with the
construction of a 20,000 aft^/min test unit at the Sherburne County
Station of Northern States Power Company.  This pilot plant was started
up in July 1979 and treated a slipstream from Unit 1.  This unit is a
700-MW pulverized-coal-fired boiler burning a Montana subbituminous coal
averaging about 1.0% sulfur and having a heating value of 8,500 Btu/lb.
The pilot plant was shut down in January 1980.

     This pilot plant consisted of a 9-ft-diameter spray dryer followed
by a small (about 1,500 aft3/min) baghouse and ESP (about 7,000 aft3/min)
operating in parallel.  (Thus, the pilot unit was effectively limited to
8,500 aft3/min.)  The spray dryer contained a single two-fluid nozzle
atomizer with air as the atomizing fluid.  An S02 spiking system and
lime preparation equipment were also included in the pilot plant.  The
major purposes of this pilot plant were to evaluate operating conditions
and to evaluate the two types of particulate control devices.  Parameters
evaluated include stoichiometric ratio, inlet S02 concentration, flue
gas temperature, and waste recycle.  The primary absorbent tested was
lime.

     Gadsden Station—A second pilot plant was recently built at Alabama
Power Company's Gadsden Station.  This pilot plant, which started up
during August 1980, treats a slipstream of about 20,000 aft3/min from
Unit 1 of the Gadsden Station.  This unit is a 69-MW boiler burning an
Alabama bituminous coal averaging about 1.8% sulfur and having a heating
value of 12,500 Btu/lb.  No shutdown date has been announced.  This
pilot unit has the same 9-ft-diameter spray dryer used at Sherburne
County followed by a baghouse for particulate collection.  The primary
absorbent being evaluated is lime.  Tests at higher S02 levels
(<2,000 ppm) will be used to confirm the results achieved at Sherburne
County.  Additional test work will evaluate solids recirculation and
nearness of the approach to flue gas saturation.

Demonstration Units—
     Although no startup date has been established and no detailed
design work has been completed, Combustion Engineering plans to build a
100,000 aft3/min (about 30-MW) demonstration unit early in 1981.  The

                                  56

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specific site for this demonstration unit has not been announced.  The
demonstration unit will contain a 20-ft-diameter spray dryer.  Particulate
collection will be provided by an existing boiler baghouse.  Other
equipment will include a lime preparation system (silos, ball mill
slaker, tanks, and pumps).  The primary purpose of this demonstration
unit is to test equipment components and to confirm the operation of the
system on a larger scale.  This demonstration unit will be a module
about one-third the size that would be used in a full-scale utility
application.

Commercial Units—
     No contracts have been awarded to Combustion Engineering for a
commercial, full-scale utility spray dryer FGD system at the present
time.  Combustion Engineering has, however, qualified and submitted bids
on three full-scale utility systems.

Conceptual Design

     The following conceptual design for a 500-MW coal-fired boiler is
extrapolated from data recently published by Combustion Engineering for
a 250-MW unit.  The design is based on a lime system for a low-sulfur
western coal application requiring a 70% SC^ removal efficiency.

     Flue gas from the boiler air heater enters a common plenum which
distributes the gas to the four trains of spray dryers (three of which
are operating and the other is a spare).   The flue gas enters the top of
the spray dryer and passes through the swirl vanes surrounding the
nozzle atomizers in a concentric ring.  Each spray dryer contains four
nozzle atomizers.  The atomizing fluid is compressed air.  The spray
dryers are insulated and enclosed in a simple, shell-type building.  The
spray dryers feed a single baghouse designed for an air-to-cloth ratio
(gross) of 1.8:1.  The flue gas from the baghouse passes through four ID
fans and into the stack.

     The compartments in the baghouse are periodically emptied and the
waste is pneumatically conveyed to storage hoppers.  The spray dryers
are designed such that the larger particles drop out of the flue gas in
the spray dryer.  This material from the spray dryer and part of the
material collected in the baghouse are available for recycle if recycle
is economically justified.

     Pebble lime is received by rail and stored in concrete silos onsite.
This lime is removed as needed, conveyed to a ball mill slaker, slurried,
and pumped to the spray dryer as needed.

Technical Considerations

     The Combustion Engineering spray dryer (Figure 10) typically has
four nozzle-type atomizers (Figure 11) and uses compressed air as the
atomizing fluid.  These atomizers are mounted in the top of the spray
dryer.   Flue gas enters the top of the spray dryer and passes down
around the atomizer through a concentric  swirl ring.   The swirl ring
provides more intimate mixing of the flue gas and slurry in the spray
drying chamber.
                                    57

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       FLUE  GAS
       FLUE  GAS
                           ^
                           i1

                           M
           ¥
v
            11
            11
            (?i
                                                         ATOMIZERS
                                      v  /r\  i
                                      V , NX
                                                                       FLUE GAS  (
                               SOLIDS

                                OUT
Figure ]fl. Spray dryer design for the Combustion Engineering FGD process  (10)
                                 58

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                               I
LIME  SLURRY
COMPRESSED
           AIR
  Figure  11.   Design of two-fluid nozzle atomizer for  the Combustion
              Engineering spray dryer FGD process (10).
                           59

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     An advantage claimed for using multiple atomizers is that when they
are designed properly and have sufficient excess capacity, a spare spray
dryer is not necessary.  The vendors believe that if one of the nozzle
atomizers fails, the others can maintain sufficient feed to and mixing
in the spray dryer so that S02 removal will not be seriously affected
for short periods of time (i.e., until the boiler load declines and the
spray dryer can be taken off-line).  They also believe that the nozzle
atomizer can be changed while the spray dryer is on-line and operating,
if necessary.

     Flue gas leaving the spray dryer must make a 180-degree turn near
the base of the spray dryer to enter the outlet duct.   This design
causes a decrease in flue gas velocity at the duct and most of the
larger particles entrained in the flue gas drop out in the bottom of the
spray dryer.  A rotary valve at the base of the spray dryer allows the
removal of this fly ash and FGD waste for recycle.  This design also
allows for the rapid cleaning of the spray dryer during any upset condi-
tions when the particulate matter remains wet at the flue gas exit in
the spray dryer.  Since the particulate matter would be heavier when wet
than when dry, it would have a tendency to fall out at the base of the
spray dryer rather than passing on to the baghouse.

     Although the waste collected in the baghouse can be recycled, most
of the waste used in the recycle stream comes from the spray dryer.  The
recycle waste is pneumatically conveyed to the slurry mixing tank where
it is added to the makeup lime slurry from the slaker.  The resulting
combined slurry is pumped to the spray dryers.
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ECOLAIRE ENVIRONMENTAL CORPORATION  (33)

     Ecolaire Environmental Corporation is the subsidiary of Ecolaire
Incorporated which markets Ecolaire's spray dryer FGD process.  Other
Ecolaire companies have been supplying equipment to the electric utility
industry for many years.  One is Ecolaire Environmental Company (EEC),
formerly Industrial Clean Air, which designs and builds baghouses for the
electric utility industry.  This in-house baghouse experience could be
an  advantage for the Ecolaire spray dryer FGD system.

Background and Current Status of Development

Pilot-Plant Units—
     Although Ecolaire's EEC subsidiary has been designing and installing
baghouses for the utility industry  for several years, prior to the
design and construction of their mobile demonstration unit (MDU) in
1979, Ecolaire had very little experience in FGD systems.  The MDU is a
pilot plant consisting of mobile semitrailer modules, a spray dryer, and
a baghouse, all of which can be trucked from site to site.  It is
essentially a self-contained unit requiring only foundations to be built
at  the site and access to flue gas, electricity, steam, and water.

     Gerald Gentleman Station—Fabrication of the MDU was completed
during late summer of 1979, and the unit was erected during November
1979 at Nebraska Public Power District's (NPPD) Gerald Gentleman Unit 1.
This 650-MW pulverized-coal-fired boiler burns a Powder River subbitu-
minous coal containing 0.31% sulfur and having a heating value of 8,900
Btu/lb.  Uncontrolled S02 emissions are approximately 0.70 Ib/MBtu and
the S02 concentration in the flue gas is about 300 ppm.  (An S02 spiking
system has been installed to allow testing in the 300 to 1,800 ppm S02
range.)  Completion of this initial test phase is scheduled for September
1980.

     The MDU consists of four semitrailers, one containing the lime
slurry preparation area (hoppers, slaker, tanks, and pumps), a second
containing the analysis laboratory, a third containing the process
control board, and a fourth containing the ID fan, stack, and storage
area.  The spray dryer (originally built by Niro Atomizer) is rated at
10,000 aft /min (about 3 MW) and has a drying chamber measuring 10 feet
in diameter and 15 feet high.  It is equipped with either one rotary
atomizer or one two-fluid nozzle atomizer.   The rotary atomizer is rated
at 150 hp and can be operated at 1,000 to 23,000 rpm.   The flue gas
leaves the spray dryer through a down-turned vent forcing the gas to
turn 180 degrees.  This allows some of the particulate matter to drop
out at the base of the spray dryer and be removed through a valved
opening.

     The flue gas from the spray dryer passes through a four-compartment
baghouse before entering the ID fan and the stack.  The bags in three of
these compartments are the standard utility size (12 inches in diameter
by 35 feet long)  while the fourth compartment contains experimental bags
(16 inches in diameter by 35 feet long).

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     Since this is the initial installation, a four- to five-month test
program was scheduled in which changes in various operating parameters
were to be evaluated.  Although data acquisition and analysis are con-
tinuing, much of these data are proprietary in nature.  However, parameters
which are being evaluated include:  inlet flue gas temperature, approach
to flue gas, saturation temperature, stoichiometric ratio, inlet 862
concentration, and alkali raw material.  Raw materials being tested
include hydrated lime, pebble lime, high-calcium lime, and dolomitic
lime.  The applicability of waste recycle is also being tested.

Demonstration Units—
     No plans have been announced as yet for a demonstration unit.

Commercial Units—
     No contracts have been awarded to Ecolaire for a commercial, full-scale
utility spray dryer FGD system at the present time.  Ecolaire, however,
has qualified and submitted at least one bid on a utility system.

Conceptual Design

     Although Ecolaire has not been awarded any contracts for a full-
scale, commercial utility FGD system, the following process description
for a 500-MW coal-fired power unit is based on their conceptual designs
and early pilot-plant experience.  Additional pilot-plant experience in
the future may result in some minor design modifications, but the overall
process description, equipment, and operations are not expected to
undergo any significant change.

     Flue gas from the boiler air heater at approximately 300 F enters a
common plenum which distributes the gas to the five trains of spray
dryers  (four operating and one spare).  Most of the flue gas enters the
spray dryer from the top and passes downward around the rotary atomizers.
As the flue gas passes the atomizer, the lime slurry is sprayed as a
fine mist into the hot gas.  The atomized slurry and flue gas remain
intimately mixed throughout the spray dryer where SC>2 and HC1 are
absorbed and react with the lime slurry.  The water present in the spray
dryer evaporates and the mixed calcium-sulfur salts and the fly ash
entrained in the gas pass into the flue  gas  ducts upstream of  the
baghouse.

     The remaining flue gas, which bypasses  the spray dryer, may  reenter
the flue gas ducts to reheat the flue gas from the spray dryer before  it
enters the baghouse.  The fly ash-FGD waste mixture is removed in the
baghouse and temporarily stored before being recycled and/or trucked  to
an onsite landfill for disposal.   The clean  flue gas passes through an
ID fan before entering the stack.

Technical Considerations

     Due to the lack of published  information concerning  their process,
it would not be appropriate to discuss any  potential  advantages or
disadvantages of the Ecolaire spray dryer  FGD process.
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JOY MANUFACTURING/NIRO ATOMIZER, INC. (34)

     The Western Precipitation Division of Joy Manufacturing Company,
which designs and builds dust collection equipment, and Niro Atomizer,
Inc., which designs and builds spray dryers and spray absorption systems,
have an exclusive agreement to market a spray dryer FGD system.  The
initial two-year agreement was recently extended to November 1984 (with
provisions for future extension of the agreement).   In this partnership
arrangement Joy Manufacturing will market the FGD system to the utility
industry while Niro Atomizer will supply the industrial market.

Background and Current Status of Development^

Pilot-Plant Units—
     Hoot Lake Station—Although the original spray dryer FGD work was
begun by Niro Atomizer, Inc., in Denmark in early 1975, it was not until
Joy/Niro signed their exclusive agreement in late 1977 that actual
pilot-plant operations of the spray dryer FGD system began.  This first
pilot plant was built at Ottertail Power Company's Hoot Lake Station,
Unit 2 during January and February 1978.  The primary reason for building
this 20,000 aft /min plant was to prequalify to bid on Basin Electric
Power Cooperative's Antelope Valley Unit 1 (for which Joy/Niro eventually
was awarded the contract), but it was also built to gain additional
operating experience on the flue gas from North Dakota lignite-fired
boilers (as well as from other fuels which were burned at this boiler).
Hoot Lake Unit 2 is a 53-MW cyclone-fired boiler burning lignite and
emitting approximately 800 ppm S02 and 2 gr/aft3 of particulate matter.
Both the boiler and the resulting flue gas are somewhat similar to what
will be encountered at Antelope Valley Unit  1.

     This initial pilot plant consisted of an 11-ft-diameter spray dryer
(rated at 20,000 aft-Vmin) and a four-compartment baghouse containing
utility-size bags (12 inches in diameter by  30 feet long).  Both acrylic-
and teflon-coated fiberglass bags were tested.  This baghouse was designed
for 15,000 aft /min.  A small ESP (rated at  5,000 aft3/min) was also
used as a particulate collection device in some of the tests to evaluate
its potential use in the spray dryer FGD system.  In addition  to the
major equipment items and their associated equipment such as slakers,
tanks, and pumps, a particulate recirculation loop was installed and
operated to evaluate the effects on raw material utilization and stoichi-
ometry.  The pilot plant also contained S02  spiking equipment  capable of
maintaining 4,000 ppm S02 in the flue gas.

     The initial operation of the pilot plant from mid-February"1978  to
May 1978 was used for parametric tests, longer verification tests, and
two 100-hour endurance tests.  Both soda ash and lime were evaluated  as
absorbents and 90% S02 removal was demonstrated with each. In  addition,
recirculation tests with the lime waste were performed.   (Niro Atomizer
has a patent pending on this recirculation process.)  When Joy/Niro had
been awarded the contract for the full-scale Antelope Valley Unit 1 FGD
system, the Hoot Lake pilot plant was reactivated for a series of
verification tests from September through December 1978.  This pilot
plant has since been dismantled and removed.

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      Copenhagen Laboratory—The only active pilot plant now in the
 Joy/Niro  organization is a recently completed  (January 1979) 5,000
 aft^/min  unit in Copenhagen, Denmark.  This unit uses a propane burner,
 shipped in  fly ash, and bottled SO.? gas to simulate the flue gas at any
 potential site.  The initial test work includes evaluation of a pulse
 jet and a reverse air baghouse as well as an ESP.  Rather than being a
 research  facility this pilot plant is used primarily to evaluate the
 actual fly  ash prior to offering proposals for specific projects.

 Demonstration Unit—
      Riverside Station—Joy/Niro and Northern States Power Company have
 recently  concluded an agreement in which Joy/Niro will build a 650,000
 aft3/min  (about 100-MW) spray dryer FGD demonstration unit at Units 6
 and 7 of  Northern States Power's Riverside Station.  This demonstration
 unit  will duplicate one of the modules to be built at Antelope Valley
 Unit  1.   Joy/Niro projects that this unit will be on-line by late fall
 of 1980.  It is expected that the FGD system will operate for about three
 years.  Since the baghouse will not be completed until December 1980 the
 existing  ESP's will be used initially to collect the FGD waste.

      Units  6 and 7 at Riverside were designed to burn high-sulfur (>3.0%)
 Illinois  coal and were equipped with ESP's for particulate control.
 However,  the plant was converted to low-sulfur (<1.0%) Montana coal.
 Because of  the low-sulfur coal, the ESP's did not perform well and the
 plant did not meet its opacity standard.   To increase the particulate
 removal efficiency and bring the plant back into compliance, these
 boilers are now burning a mixture of 85% to 90% low-sulfur Montana coal
 and 10% to  15% high-sulfur (4%) petroleum coke.  Since Joy/Niro will be
 installing  a baghouse designed for the flue gas from Units 6 and 7,
 these boilers are expected to meet the opacity standard without using
 high-sulfur fuel.

      The  single spray dryer will be 46 feet in diameter and contain a
 single rotary atomizer.   Flue gas from the spray dryer will pass to one
 of two baghouses—each rated at 50% of total capacity.  Design air-to-
 cloth ratio (gross) is 2:1.   FGD waste from the spray dryer will be
 recycled.   Pebble lime will be prepared in a ball mill slaker and pumped
 to the spray dryer.

 Commercial Units—
     Calgon—Niro/Joy was awarded a contract by Calgon Corporation in
 December  1979 for an FGD system at their plant at Big Sandy, Kentucky.
 The FGD system will treat 56,900 aft3/min (at 1,700°F) of off-gas from a
 Herreshoff multiple hearth furnace (a tray-type tower typically fired
with natural gas that is used for calcining solids).   This high inlet
 temperature is not expected to cause significant problems for the spray
 dryer system.   Additional water will be added in the  spray dryer to  cool
 and humidify this  gas before it reaches the baghouse.   The off-gas from
 the furnace will average 1,100  ppm SC>2 and 4,000 ppm  HC1.   Design S02
 removal efficiency is 75%.   HC1 removal will be 99%.   Startup is currently
 scheduled for June 1981.
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     This FGD system will use soda ash at Calgon's request.  Waste
recycle is not being considered and waste disposal will be handled by
Calgon.  A single 22.5-ft-diameter spray dryer containing one rotary
atomizer will treat the total gas stream (there will be no spare spray
dryer and no gas bypass).  Flue gas from the spray dryer will pass to a
single pulse-jet baghouse containing 360 bags in four compartments.

     Antelope Valley Station—Joy/Niro has been awarded a turnkey contract
for a full-scale spray dryer FGD system for Basin Electric Power Coop-
erative's Antelope Valley Station Unit 1.  This FGD system will treat
2,055,000 aft3/min of flue gas from the 440-MW lignite-fired cyclone
boiler.  The sulfur content in the North Dakota lignite is expected to
range from 0.3% to 1.2%.  Process design for the FGD system on Unit 1 is
complicated since the required S02 removal efficiency will increase when
Antelope Valley Unit 2 comes on-line.  Although the FGD system will only
be required to remove up to 78% of the SC>2 initially, it will be designed
for the 89% (maximum) SC>2 removal that will be required when Unit 2 is
on-line.  (The contract for the FGD system for Unit 2 has not yet been
awarded.)  Commercial operation for Unit 1 is currently scheduled for
April 1982.

     The Antelope Valley FGD system will use lime as the absorbent and
will use waste recycle to improve the lime utilization.  It will also
use hot gas bypass to maximize lime utilization.  Five 46-ft-diameter
spray dryers will be used, each containing a single rotary atomizer.
During normal operation all five spray dryers will be operating although
the FGD system can operate at full capacity with only four in use.  The
spray dryers will be insulated and enclosed in a simple shell-type
building.  Flue gas from the spray dryers will feed two baghouses, each
rated at 50% of capacity.  The design air-to-cloth ratio (gross) is
2.19:1 and there will be 28 compartments in the two baghouses.  Since
this is a mine-mouth plant, waste disposal will be in the mine.   Pebble
lime will be prepared in a ball mill slaker.

     Springerville Station—Joy/Niro has also been awarded a materials-
only contract for the full-scale spray dryer FGD systems for Tucson
Electric Company's Springerville Station Units 1 and 2.  Each of these
units is a 350-MW boiler burning a New Mexico subbituminous coal averaging
about 0.69% sulfur and having a heating value of 10,500 Btu/lb.  The FGD
system for each unit will treat 1,664,000 aft^/min of flue gas containing
1,400 ppm S02-   Although both FGD systems will be designed to achieve
61.3% S02 removal (these units are grandfathered under the NSPS) for the
average coal,  up to 82% S02 removal may be required if higher sulfur
coals are burned.   Unit 1 is scheduled to be on-line in February 1985
with Unit 2 following about 18 months later.

     The Springerville FGD system will be lime-based and will use waste
recycle to improve the lime utilization.   Since the S02 removal  require-
ment is only 61.3% these units will be designed for warm gas bypass
rather than the hot gas bypass in the Antelope Valley system.   Three 46-
ft-diameter spray dryers, each with a single rotary atomizer,  will be
used for each  boiler (six in all).

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     During normal operation all three spray dryers on each unit will be
operating although the FGD system can operate at full capacity with only
two spray dryers per unit.  (Excess capacity in both the spray dryer and
the bypass ductwork can accommodate the higher flue gas flow rate when
one dryer is off-line although the lime feed rate to the spray dryers
will have to be increased to maintain the SC>2 removal efficiency.)  The
spray dryers will be insulated and enclosed in a simple shell-type
building.  Flue gas from the spray dryers of each unit will feed two
baghouses, each rated at 50% capacity.  The design air-to-cloth ratio
(gross) is 1.91:1, and there will be 28 compartments in the two baghouses
for each unit.

     Rawhide Station—The third commercial-scale spray dryer FGD system
awarded to Joy/Niro was by the Platte River Authority for its Rawhide
Station Unit 1.  This boiler is a 250-MW unit burning a Wyoming subbitu-
minous coal averaging 0.29% S (0.44% S maximum) and having a heating
value of about 8,500 Btu/lb.  The FGD system will treat 1,352,000 aft3/min
of flue gas containing 875 ppm S02 (based on 0.44% S).  The design S02
removal efficiency will be 80%.  Startup for this unit is currently
scheduled for December 1983.

     The Rawhide FGD system will be lime-based and will use waste recycle
to improve the lime utilization.  Since the S02 removal requirement is
only 80%, this unit will be designed for warm gas bypass.  Three 46-
ft-diameter spray dryers will be used, each with a single rotary atomizer.
In keeping with Joy/Niro's standard design, all three spray dryers' will
be on-line during normal operations with the higher sulfur coal.  When
the coal sulfur level remains near the design average of 0.29% S, only
two of the spray dryers will be operating.   The spray dryers will be
insulated and enclosed in a simple shell-type building.  Flue gas from
the spray dryers will feed two baghouses, each rated at 50%  capacity.
The design air-to-cloth ratio (gross) is 2:1, and there will be 24
compartments in the two baghouses.

     Hoicomb Station—In April 1980 Joy/Niro was awarded a turnkey
contract for the FGD system at Sunflower Electric Cooperative's Holcomb
Station Unit 1.  This is a 319-MW unit burning a Wyoming subbituminous
coal averaging 0.3% sulfur and having a heating value of about 8,200
Btu/lb.  The FGD system will treat 1,306,000 aft3/min of flue gas
containing 1,000 ppm SC^.  The design S02 removal efficiency will be
80%.  Startup for this unit is currently scheduled for June 1983.

     The Holcomb FGD system will be lime-based and will use waste recycle.
In contrast to the typical lime spray dryer design, no flue gas bypass
will be used.  Three 50-ft-diameter spray dryers will be used, each with
a single rotary atomizer.  During normal full-load operation, all three
spray dryers will be operating although the FGD system can operate at
full capacity with only two spray dryers.  The spray dryers will be
insulated and enclosed in a simple shell-type building.  Flue gas from
the spray dryers will feed two baghouses, each rated at 50% capacity.
The design air-to-cloth ratio (gross) is 1.85:1, and there will be 28
compartments in the two baghouses.
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     Argonne National Laboratory—Argonne National Laboratory awarded a
 turnkey  contract to Niro/Joy in November 1980 for a lime-based spray
 dryer FGD  system at their onsite boiler.  The renovated spreader-stoker-
 fired boiler burns a 12,000 Btu/lb Illinois bituminous coal averaging
 3.5% sulfur.  The flue gas rate to the FGD system will be about 85,000
 aft^/min (at 355 F).  This boiler which was originally designed for
 coal, was  converted to oil in the early 1970's and is now being reconverted
 to  coal.   Therefore the FGD system will be a retrofit.  The applicable
 S02 emission limit is 1.2 Ib of S02 MBtu and cherefore approximately
 78.5%.   SC>2 removal will be required for the average coal.  This FGD
 system is  currently projected to start up in September 1981.

     The FGD system will be lime-based and will use waste recycle.
 One 27-i/2-ft-spray dryer will be used to treat the entire flue gas
 stream (there will be no spare).  Particulate removal will be by a
 pulse-jet  baghouse which has four compartments.  Design air-to-cloth
 ratio will be 3:1.  There will be no flue gas bypass.  Waste disposal
 will be  Argonne's obligation and various methods and possible test
 programs are currently being evaluated.

 Conceptual Design

     The following conceptual design for a 500-MW coal-fired boiler is a
 generalized version of Joy/Niro's recent full-scale contract awards.
 This design is based on a lime system for a low-sulfur western coal
 application requiring a 70% SC>2 removal efficiency.

     Flue  gas from the boiler air heater at about 300 F enters a common
 plenum which distributes the gas to five operating spray dryers (the
 ductwork and spray dryers are designed with excess capacity such that
 four of  the dryers can handle the full boiler load).   Each spray dryer
 is  46 feet in diameter and contains a single rotary atomizer.   The spray
 dryers are insulated and may be enclosed in a simple, shell-type building.
 The five spray dryers feed two baghouses,  each rated at 50% of full-
 load capacity.   The baghouses are designed for an air-to-cloth ratio
 (gross) of 2:1.   The flue gas from the baghouse passes through ID fans
 and into the stack plenum.

     The hoppers in the baghouse are periodically emptied, and the waste
 is pneumatically conveyed to storage silos.   The Niro spray dryers are
 designed so that the larger particles of FGD waste drop out of the flue
 gas and fall to the bottom of the spray dryer.   Some of the material
 from the spray dryer and part of the material collected in the baghouse
 are reslurried and recycled through the spray dryer.

     Pebble lime is received by rail and stored in concrete silos onsite.
This lime is discharged as  needed,  conveyed  to  ball mill  slakers,
 slurried, and pumped to the spray dryer as needed.

Technical Considerations

     The  Niro spray dryer (as shown in Figure 12)  has several  readily
apparent  differences  from those offered by most other vendors.   The
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                                                   FLUE  GAS
                                                        IN
     FLUE
      GAS
      OUT
                          SOLIDS
                            OUT

Figure 12.  Spray dryer design for the Joy/Niro FGD process (11)

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spray dryer contains only one rotary atomizer regardless of how large
the spray dryer is (up to the maximum 50-ft-diameter size available).
Although this rotary atomizer is relatively large (about 700 hp) and
must handle significant quantities of lime slurry, this has been the
standard spray dryer design in past non-FGD applications and has worked
satisfactorily.  Normally in the Joy/Niro design, all of the spray
dryers, including the in-line spare, operate at full boiler load.  Using
the in-line spare tends to decrease the total system pressure drop and
allows for better operation of the FGD system.

     Another feature in the Niro spray dryer design is that the flue gas
not only enters the top of the spray dryer in a concentric ring around
the single atomizer, but it also enters from below the atomizer with an
upward flow.  This design is to assure more intimate mixing of the
atomized mist and the flue gas and also to prevent possible distortion
of the mist pattern at high flue gas velocities.

     Flue gas leaving the spray dryer must make two turns near the base
of the spray dryer, first to enter the outlet duct and then again inside
the outlet duct.  This design causes a decrease in flue gas velocity at
the duct and most of the larger particles entrained in the flue gas drop
out in the bottom of the spray dryer.  A rotary valve at the base of the
spray dryer allows the removal of this fly ash and FGD waste for recycle.
This design also allows for the rapid cleaning of the spray dryer during
any upset conditions when the particulate matter remains wet at the flue
gas exit in the spray dryer.  Since the particulate matter would be
heavier when wet than when dry, it would have a tendency to fall out at
the base of the spray dryer rather than passing on to the baghouse.

     Although the waste collected in the baghouse can be recycled, most
of the waste used in the recycle stream comes from the spray dryer.  The
recycle waste is pneumatically conveyed to the slurry mixing tank where
it is added to the makeup lime slurry from the slaker.  The resulting
combined slurry is pumped to the spray dryers.

     The standard Niro spray dryer for utility applications is 46 feet
in diameter, and each application normally consists of multiples of this
standard size.   The desired gas residence time (10 to 12 seconds) is
obtained by varying the height of the drying chamber.  Each spray dryer
is insulated and the spray dryer area may be enclosed in a simple,
shell-type building.  The Joy/Niro design usually includes two baghouses,
each rated at 50% capacity.  The design air-to-cloth ratio (gross) is
normally 2:1.
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RESEARCH-COTTRELL,  INC. (35)

     Research-Cottrell, Inc.,  which has an extensive background in
conventional wet limestone scrubbing, entered the spray dryer FGD field
in 1979.  Research-Cottrell has an agreement with Komline-Sanderson
Engineering Corporation, a spray dryer designer and manufacturer since
1946, for the exclusive use of their spray dryer technology.   Since
Research-Cottrell also designs and markets ESPs and baghouses the
agreement with Komline-Sanderson enables Research-Cottrell to provide a
complete spray dryer FGD system.

Background and Current Status  of Development

Pilot Plant Units—
     Big Brown Station—During the summer of 1979 Research-Cottrell and
Texas Utilities reached agreement to locate a 10,000 aft^/min spray
dryer pilot plant at Unit 2 of the Big Brown Station of Texas Utilities.
Unit 2 at Big Brown burns Texas lignite averaging 1.0% sulfur and 7,500
Btu/lb to produce about 593 MW of power.  Pilot-plant testing began in
June 1979.  The primary purpose of this pilot unit was to demonstrate
the technical feasibility of the process and to initiate tests to optimize
the process.

     This pilot plant had a single, 8-ft-diameter Komline-Sanderson
spray dryer rated at about 10,000 aft^/min and a Research-Cottrell
baghouse.  This two-compartment baghouse contained commercial-size bags
(12 inches diameter by 30 feet long) and was designed to treat 5,000
aft-Vmin.  The potential for FGD waste recycle was evaluated.  Absorbents
included were slaked lime and  fly ash.  Due to the propriety  nature of
the development work, specific test results are not available.

     Comanche Station—Research-Cottrell has recently transferred their
10,000 aftj/min pilot plant to Unit 2 of Public Service Company of
Colorado's Comanche Station.  This is a 385-MW (gross) unit burning a
low-sulfur western subbituminous coal averaging 0.5% sulfur and having a
heating value of about 9,000 Btu/lb.  Pilot-plant testing began in May
1980 and is scheduled to continue through 1980.  The primary  purposes of
this pilot unit are twofold:  to demonstrate this process on  a subbituminous
coal and to run tests to optimize the process for similar applications.
In addition, waste disposal studies will be made.  Partial funding for
this pilot plant is being provided by the EPA, and therefore  at least
some of the data and results are expected to be available later this
year.

Demonstration Units—
     No plans for a demonstration unit have been announced by Research-
Cottrell.

Commercial Units—
     S t ant on S t a t i on—Research-Cottrell has been awarded a contract for
a lime spray dryer FGD system for United Power Associations's Stanton
Station Unit 2.  This 63-MW cyclone unit will burn a North Dakota

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lignite which is expected to average 0.77% sulfur and have a heating
value of about 7,000 Btu/lb.  Design S02 removal efficiency ranges from
73% for the average lignite (0.77% sulfur) to 90% for the worst-case
lignite.  Guaranteed S02 removal efficiency for worst-case lignite
(1.94% sulfur) is nearly 91%.  Tfris FGD system is currently projected to
startup during September 1982.  The FGD system will be lime-based and
will use waste recycle to improve the lime utilization.  One Komline-
Sanderson spray dryer containing a single rotary atomizer will be used
to treat the entire flue gas stream.  There will be no spare spray
dryer.  A Research-Cottrell baghouse will be used for particulate col-
lection.

Conceptual Design

     Although Research-Cottrell has not received any contracts for a
full-scale utility FGD system, a conceptual design for this system has
been prepared.  For a typical 500-MW coal-fired boiler, the flue gas
from the boiler air heater passes through a common plenum to six spray
dryers connected in parallel (although all six would be operating, five
can handle the full boiler load).  Each spray dryer has three rotary
atomizers.  The flue gas leaves the spray dryer through an upward
turning duct (as shown in Figure 13).   This design forces the flue gas
to make a 180-degree turn, thereby slowing the gas velocity and allowing
some of the larger particles to drop to the bottom of the spray dryer.

     The flue gas passes through the duct to the baghouse where the
remaining entrained particulate matter is removed.  The clean flue gas
from the baghouse passes through an ID fan to the stack.  Through proper
design, the flue gas does not need further stack gas reheat before
entering the stack.

     Makeup pebble lime is received by rail or truck and stored in
onsite storage silos.   Lime is removed as needed, slaked with makeup
water, and pumped to the spray dryers.  For most applications now
envisioned (low-sulfur western subbituminous coal or lignite appli-
cations) , waste recycle will be used to achieve acceptable raw material
utilization.  FGD waste can be removed both from the spray dryer and the
baghouse and pneumatically conveyed to a reslurrying tank for recycle
through the spray dryers.

Technical Considerations

     Due to the lack of published information concerning their process,
it would not be appropriate to discuss any potential advantages or
disadvantages of the Research-Cottrell spray dryer FGD process.
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 FLUE GAS  IN
                                                      FLUE  GAS
                                                         OUT
                                                          I
                          SOLIDS
                            OUT

Figure 13.  Spray dryer design for the Research-Cottrell FGD process.
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ROCKWELL INTERNATIONAL/WHEELABRATOR-FRYE, INC. (36)

     Until early 1980 Rockwell International/Wheelabrator-Frye, Inc.,
and Stork-Bowen Engineering, Inc., had exclusive agreements to design
and build spray dryer FGD systems called the two-stage open-loop process.
Rockwell International brought its previous pilot-plant experience in
spray dryer FGD work from the development of the regenerable aqueous
carbonate process, while Stork-Bowen and Wheelabrator-Frye provided
the necessary experience in designing and marketing spray dryers and
baghouses, respectively.  In the past Wheelabrator-Frye has also been
deeply involved in the conceptual design and pilot-plant testing of dry
injection of nahcolite into flue gas ducts and baghouses.

     However, the joint venture of Rockwell International and Wheel-
abrator-Frye was recently dissolved, with both Rockwell International
and Wheelabrator-Frye continuing to design and market their own spray
dryer FGD system.  Stork-Bowen Engineering will continue to provide the
spray dryers for the Rockwell system, but the baghouse will now be
subcontracted on a competitive bid basis.

Background and Current Status of Development

Pilot-Plant Units—
     The original spray drying work was done by Rockwell International
and Stork-Bowen in the early 1970's and was related to the development
of the regenerable, closed-loop aqueous carbonate process (while
Wheelabrator-Frye was involved in dry nahcolite injection pilot-plant
work), it was not until 1977 that these three companies came together to
develop the dry waste-producing, open-loop aqueous carbonate process,
which is now called the two-stage open-loop process.

     Leland Olds Station—Initial pilot-plant work on the two-stage
open-loop process was done in 1977 and early 1978 in an existing 4,000
to 5,000 aft3/min pilot-plant unit at the Leland Olds Station of Basin
Electric Power Cooperative.  The baghouse section of this pilot unit was
built in late 1976 to test and demonstrate an FGD system using dry
nahcolite as the S02 absorbent for the Coyote Unit 1 to be operated by
Ottertail Power Company.  Leland Olds is a cyclone boiler similar to the
Coyote unit and burns a similar North Dakota lignite.  However, questions
about the availability of nahcolite in commercial quantities led to the
search for other raw materials.  Based on spray dryer tests conducted at
Stork-Bowen Engineering's test facility in early 1977, a spray dryer was
added and the test program at Leland Olds was extended to include the
use of a spray dryer/baghouse FGD system as an alternative to nahcolite
injection.

     The modified pilot plant consisted of a 7-ft-diameter spray dryer
followed by the original two-compartment baghouse containing 11-1/2-
inch-diameter by 30-ft-long filter bags.  A variety of raw materials was
evaluated including soda ash, trona, lime, limestone, and fly ash at
various inlet S02 concentrations from 400 to 2,300 ppm.  The test
program was completed in August 1978 and the pilot plant was dismantled
in September 1978.
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     Joliet Station—Early in 1978 Rockwell International/Wheelabrator-
Frye reached agreement with Commonwealth Edison Power Company to reassemble
their pilot plant at the Joliet Station in Illinois.   The Joliet Station
currently burns a mixture of four western subbituminous coals ranging
from 0.4% to 1.0% sulfur and 9,000 to 10,000 Btu/lb in heating value.
Testing began in July 1979 and is expected to last approximately two
years.  The test unit has a single, -7-ft-diameter spray dryer (4,000 to
5,000 aft^/min) with the option of testing two types  of baghouses as
well as an ESP.  In addition three types of slakers will be evaluated.

     This pilot unit is currently being operated on a time-sharing
basis.  Both Rockwell International and Wheelabrator-Frye conduct
separate test work for discrete time periods.

Mobile Pilot Plant—
     In late 1978 and early 1979 Rockwell International/Wheelabrator-
Frye designed and built a mobile pilot plant capable  of being moved on
flatbed trucks.  Not only can this mobile unit be used to evaluate the
effects of various flue gases from a wide variety of  both coals and
boiler types on the spray dryer FGD system design, but it can also be
used for determining operating conditions for a specific boiler and coal
in preparing a bid.  This unit has a single 7-ft-diameter spray dryer
(4,000 to 5,000 aft-Vmin) and a pulse-jet baghouse.  The mobile pilot
plant was initially moved to Northern States Power Company's Sherburne
County 700-MW Unit 1.  This unit burns a Montana subbituminous coal
containing 0.8% sulfur and having a heating value of  8,600 Btu/lb.
Testing lasted through June 1979.

     During July 1979 the mobile pilot plant was moved to Pacific Power
and Light's and Idaho Power and Light's Jim Bridger Station.  The Jim
Bridger Station has four units, three of which are currently operating.
Each of these three units are rated at 500 MW, and each must have a
retrofitted FGD system capable of 75% S02 removal on-line by 1988.  The
test program at Jim Bridger lasted through August and September 1979.

     During late 1979 the unit was moved again to the Celanese industrial
boiler site in Cumberland, Maryland, for additional test work to verify
the FGD system design.  The mobile pilot plant is currently at Rockwell
International's Santa Susanna field laboratories with the testing schedule
to resume in September 1980.  The system still includes a pulse-jet
collector but not the same collector used in previous testing.

Demonstration Units—
     No plans have been announced as yet for a demonstration unit.

Commercial Units—
     Celanese—The Rockwell International/Wheelabrator-Frye joint
venture received a turnkey contract in January 1979 from Celanese Corpo-
ration for a lime-based spray dryer FGD system for a coal-fired boiler
at their Amcclle plant in Cumberland, Maryland.  This renovated stoker-
fired boiler burns an eastern bituminous coal ranging from 1.0% to 3.5%
sulfur.  A pulse-jet baghouse is used for particulate collection.  The
FGD system also incorporates warm gas bypass to increase lime utilization.
                                  74

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     Although  the spray dryer FGD system is designed  to  treat up  to a
maximum of  87,000 aft^/min  (at 420 F), under average  boiler loads, the
flue gas  rate  is typically  65,000 aft3/min  (at 380°F).   The current
emission  regulations  for  the boiler are 70 Ibs/hr  for SC>2 and 0.01
grains/aft3 for particulate matter in the flue gas  from  the stack.  This
S02 standard corresponds  to about 70% S02 removal  for a  1.0% sulfur coal
and 86% S02 removal for a 2.0% sulfur coal.

     The  FGD system contains a single 20-ft-diameter  spray dryer  followed
by a four-compartment, pulse-jet baghouse.  In contrast  to the large
spray dryers for utility  applications, which have  three  rotary atomizers,
this smaller 20-ft-diameter model has only one.  The  pulse-jet baghouse
used in this application  is typical of smaller installations rather than
the reverse-air type  usually used in large utility  applications.  The
boiler and  the FGD system was put in operation in January 1980 and
acceptance  testing for the  FGD system was completed in February.

     Coyote Station—A turnkey contract was awarded to Rockwell Inter-
national/Wheelabrator-Frye  in April 1977 by the consortium headed by
Ottertail Power Company for the Coyote Unit 1 FGD system.  Unit 1
(originally scheduled for startup in April 1981 but currently ahead of
this timetable) is a  456-MW (gross) cyclone-fired boiler burning North
Dakota lignite averaging  0.78% sulfur and having a. heating value of
7,000 Btu/lb.  This spray dryer FGD application is  currently the only
utility system using  a sodium-based absorbent (all others are lime).
This system was chosen because disposal of the fly ash, which contains
about 25% sodium salts, already presented a solubility problem.  Final
disposal of the FGD waste and the fly ash will be in  an adjacent mined-
out area  (this is a mine-mouth power plant).

     The FGD system will  consist of four 46-ft-diameter spray dryers
each containing three rotary atomizers and will treat about 1,890,000
aft^/min.   During normal  operation all four spray dryers will be operating
although the FGD system can operate at full capacity with only three in
use.  The spray dryers will be insulated and enclosed in a simple,
shell-type  building.  Particulate collection will be  in a baghouse.
Neither waste recycle nor flue gas bypass for reheat will be used.
Guarantees  for the worst-case coal include 70% S02 removal (for <1.4%
sulfur lignite) and 80% utilization of sodium carbonate.

Conceptual  Design

     The two-stage open-loop FGD system for a full-scale, commercial,
utility boiler (about 500 MW)  typically has four spray dryers in parallel.
Three of these are operating at full boiler load and one is an in-line
spare.

     The spray dryer is designed such that all of the inlet flue gas
enters a common open chamber directly above the rotary atomizers.   One-
third of the total inlet  flue gas enters the vanes which form a concentric
ring surrounding each rotary atomizer in the spray drying chamber.
There are no internals within the spray dryer.   The flue gas leaves at

                                  75

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the bottom of the spray dryer through a downward sloping duct.    The
ductwork to the baghouse has this downward slope so that during low
boiler loads (and the resulting decrease in flue gas velocity)  the
particulate matter that falls out will be swept forward into the baghouse
hoppers.  In addition, during upset conditions any wet waste will flow
into hoppers in the baghouse inlet manifold rather than remaining in the
spray dryer or the ductwork.  When recycle of waste is required to
achieve acceptable raw material utilization rates, FGD waste will be
removed from the baghouse, reslurried in a separate tank, and combined
with the makeup slurry at the spray dryer.

Technical Considerations

     The Stork-Bowen spray dryer (as shown in Figure 14) is different
from most others in that each spray dryer has three rotary atomizers.
The use of three rotary atomizers decreases the size of each atomizer
since each must atomize only one-third of the total absorbent fed to the
spray dryer.  This design (which uses state-of-the-art atomizers and
vane rings) is claimed to result in a better mix of flue gas and atomized
absorbent and thus lead to better raw material utilization.  Conversely
the use of multiple atomizers complicates the flue gas distribution to
the atomizers.
                                   76

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             FLUE GAS
                OUT
Figure 14.   Spray dryer design for the Rockwell International FGD process  (36)
                               77

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                        DESIGN AND ECONOMIC PREMISES
     In this study the economics of three FGD systems (two spray dryer
processes—one sodium-based,  the other lime-based—and a limestone
scrubbing process) are compared on an equitable basis using conditions
that are representative of projected industry conditions and that provide
a clearly definable breakdown of costs into significant and useful
divisions.  The premises used in this study have been developed by TVA,
EPA, and others during similar economic evaluations made since 1967.
The design premises are formulated to establish efficiencies,  process
flow rates, and other operating and design conditions.  The economic
premises are designed to represent the many factors affecting  costs.
DESIGN PREMISES

     The utility plant design and operation is based on Federal Energy
Regulatory Commission (FERC) historical data (37) and TVA experience.
The conditions used are representative of a typical modern boiler for
which FGD systems would most likely be considered.  An Upper Great
Plains and Rocky Mountain location (Wyoming, Colorado, Nebraska, and
North and South Dakota) is used for the lignite and the low-sulfur
western coal cases because the concentration of these low-sulfur coal
supplies in this area make it representative of the segment of the power
industry most active in spray dryer FGD.  A midwestern location (Illinois,
Indiana, and Kentucky) was selected for the low-sulfur and high-sulfur
eastern coal cases for similar reasons.

     In keeping with current industry practice, a redundant absorber
train is provided to maintain acceptable boiler availability.  In the
integration of the absorber system with the boiler systems, provision
for turndown and maintenance are limited to provision of a common plenum
between the systems with dampers to allow individual trains to be shut
down.

Emission Standards

     New source performance standards  (NSPS) established by EPA in 1979
(38) specify a maximum emission, based on heat input, of 0.03 Ib/MBtu
for particulate matter, 1.2 Ib/MBtu for S02, and 0.6 Ib/MBtu for NOX.
In addition to meeting this maximum emission limit of 1.2 Ib/MBtu for
S02, the 1979 NSPS also require that new plants must reduce the uncontrolled'
S02 emissions from 70% to 90%, depending on the uncontrolled S02
emission level.  For the lignite and for both low-sulfur coals chosen in
this study, this percentage S02 reduction is 70%.  For the high-sulfur

                                   78

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eastern coals the percentage SC>2 reduction is 89.6%.  In addition it is
assumed that the boilers in this study are designed to meet the 0.6
Ib/MBtu NOX standard.  The FGD system includes all the process equipment
assumed to be needed to meet both the particulate matter and the S02
removal standards.

Fuel

     The  coal premises are composites of many samples representing major
coal production areas.  The lignite  coal'is assumed to have a heating
value of  6,600 Btu/lb and an ash content of 7.2% as fired and a sulfur
content of 0.9%, on a dry basis.  The western coal has a heating value
of  9,700  Btu/lb and an ash content of 9.7% (both as fired) and a sulfur
content of 0.7% (dry basis).  This coal is based on coals from various
western coal fields (39).  The eastern bituminous coals are both assumed
to  have a heating value of 11,700 Btu/lb and an ash content of 15.1% as
fired.  The sulfur content of the low-sulfur and high-sulfur coals are
0.7% and  3.5%, respectively, on a dry basis.  The composition for all
four coals are shown in Table 4.

Power Plant Design

     A single boiler with a 500-MW net electrical output is used.  This
net output does not include the power requirements for the FGD system.
In  contrast to some previous FGD studies by TVA, particulate matter
removal and disposal are included as part of the FGD unit rather than as
part of the boiler because of the nature of the spray dryer FGD processes,
which collect fly ash and sulfur salts simultaneously.

Power Plant Operation

     A total operating lifetime of 165,000 hours over a 30-year period
is used.  The boiler capacity factor is 62.8% (equivalent to full load
for 5,500 hr/yr).  A boiler heat rate of 11,000 Btu/kWh is assumed for
the lignite unit.  The boiler heat rate for the other three coal cases
is 9,500  Btu/kWh.

Flue Gas  Composition

     Flue gas compositions are the result of boiler design, fuel, and
operating conditions.   Combustion and emission conditions used to determine
flue gas  composition are based on boiler design and average values for
the sulfur content of coal.   Flue gas compositions are based on combustion
of pulverized coal using a total air rate equivalent to 139% of the
stoichiometric requirement.   This includes  20% excess air to the boiler
and 19% air inleakage in the ducts and boiler air heater,  which reflect
operating experience with horizontal, frontal-fired,  coal-burning units.
It is assumed that 80% of the ash present in the coal is emitted as fly
ash.  It  is also assumed that 85% of the sulfur in the coal is emitted
as SOX for the lignite and the western coals while 92% sulfur is emitted
as SOX for the eastern coals.   In all four  cases 3% of the SOX emitted
is assumed to be 803 and the remainder S02-   The base-case flue gas
composition and flow rates calculated for these conditions are shown in
Table 5.                            7g

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                              TABLE 4.   COAL COMPOSITIONS

Component
C
H
0
N
S
Cl
Ash
Moisture

Lignite
40.1
2.8
12.4
0.6
0.57
0.01
7.2
36.3
wt
Low-sulfur
western
57.0
3.9
11.5
1.2
0.59
0.1
9.7
16.0
% as fired
Low-sulfur
eastern
68.8
3.6
6.3
1.4
0.67
0.1
15.1
4.0

High-sulfur
eastern
66.7
3.8
5.6
1.3
3.36
0.1
15.1
4.0
            Basis:   TVA design  and economic premises
                       TABLE 5.  BASE-CASE FLUE GAS COMPOSITIONS AND FLOW RATES
Flue gas component
N
°2
CO 2
S02
so3
NOX
HC1
H20
Ash
Total
Lignite
Volume ,
68.95
5.08
11.92
0.05
-
0.03
-
13.97
-
100.00
coal, 0.9% S
% Ib/hr
4,509,000
379,500
1,225,000
7,825
302
2,210
86
587,200
48,130
6,759,000
Western
Volume,
73.09
5.39
12.24
0.04
-
0.03
0.01
9.20
-
100.00
coal, 0.7% S
% Ib/hr
3,887,000
327,200
1,023,000
4,760
184
1,590
504
314,600
38,000
5,597,000
Eastern
Volume ,
75.67
5.03
12.76
0.04
-
0.03
0.01
6.46
-
100.00
coal, 0.7% S
% Ib/hr
3,867,000
325,400
1,024,000
4,850
187
1,908
418
212,100
49,000
5,485,000
Eastern
Volume,
75.21
5.54
12.34
0.20
0.01
0.03
0.01
6.66
_
100.00
coal, 3.5% S
% Ib/hr
3,851,000
323,900
992,300
24,330
940
1,980
418
219,100
49,000
5,463,000
Basis:  TVA design and economic premises
                                             80

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FGD System Design

     The design of the spray dryer processes are based on current industry
practices developed from vendor information and published data representing
the most prevalent and more fully developed systems.  The processes are
generic and do not simulate a particular vendor design.  The limestone
process is based on experience at the Shawnee EPA Alkali Test Demonstration
Facility, extensive power industry experience with these processes, and
vendor information.  The soda ash spray dryer process is evaluated only
for the western coal case because it is assumed that the highly soluble
waste would present economically unpredictable disposal practices in
areas of high net precipitation.

     The spray dryers contain three rotary atomizers and have neither
presaturators nor mist eliminators.  Flue gas leaves the spray dryer at
about 20 F above its saturation temperature and contains no entrained
liquid.  Flue gas from the spray dryers and the bypass ducts is mixed and
sent to the baghouse where the dry particulate matter (both fly ash and
FGD waste) is removed.  This waste is either recycled or trucked to the
landfill.

     The limestone slurry process absorbers consist of spray towers with
spray presaturators to saturate the flue gas before entering the spray
tower and mist eliminators to reduce the entrained flue gas moisture to
0.1% in the exiting flue gas.  The slurry is oxidized to over 99% CaS04
(gypsum) by air sparged into the slurry recirculation tank.  The waste
effluent withdrawn from the absorber circulation system is thickened
from 15% to 40% solids, filtered to 80% solids, and trucked to the
landfill.

     In the low-sulfur coal cases, four absorber trains are used for the
lime spray dryer and the limestone scrubbing process.  For the soda ash
spray dryer process, five trains are used.  The capacities are based on
one train serving as a spare at full-load boiler operation.  Partial
scrubbing and warm gas bypass are used for the lime spray dryer and
limestone scrubbing processes.  The lime spray dryers are designed for
83% SC>2 removal and the limestone scrubbers are designed for 90% 862
removal so that the overall 70% S02 removal efficiency is achieved.
This is the prevalent design practice for lime spray dryer FGD and has
also been found more economical for wet scrubbing (40).  Full scrubbing
at 70% SOo removal is used for the soda ash spray dryer process because
the high reactivity makes a close approach to flue gas saturation
temperature unnecessary.  For the high-sulfur eastern coal case, the
bypass for the lime spray dryer process is limited to 4% of the flue gas
and it is hot gas bypass.  No bypass is used for the limestone scrubbing
process.  In addition each of the FGD systems is designed for emergency
bypass around the scrubbers.  This emergency bypass duct is sized to
handle 50% of the scrubbed flue gas in addition to the normal bypass
gas.

     No flue gas reheat is provided for the spray dryer processes, and
the systems are designed for a minimum flue gas temperature of 165 F to

                                    81

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 175°F in  the baghouse.  To represent typical conservative design practice,
 a partial flue gas bypass around the boiler air heater is provided for
 emergency use to maintain this temperature during abnormal periods of
 operation.  Indirect steam flue gas reheat to 175°F is provided as
 necessary in the limestone scrubbing process.

     Because of the temperature sensitivity of the spray dryer processes,
 4 inches  of insulation are provided on all the ductwork from the boiler
 wall to the baghouse, whereas the limestone slurry process, which is
 less temperature sensitive, has only 2 inches of insulation.  In addition,
 a simple  shell building houses the spray dryers, while the absorbers for
 the limestone slurry process are not enclosed.  Induced-draft (ID) fans
 located upstream of the stack plenum are provided to compensate for the
 pressure  drop through the FGD system.

     Operating conditions are shown in Table 6.  These conditions are
 used for  both the base-case and case variation studies.  Cost scaling
 factors based on gas and product rates are used to calculate values at
 conditions other than the base case.

 Raw Materials

     The  raw materials used for each process are listed below.   Limestone
 is crushed and wet ground as part of the scrubbing operation.  The lime
 is not processed, only slaked before use.
      Property
Soda ash spray
 dryer process
                                           Lime spray
Limestone
Size as received
Ground size
Analysis
Bulk density, lb/ft3
<100 mesh
99.5% Na2C03
35
3/4
90%
55
- 1-1/4 in.
CaO
0 - 1-1/2 in.
90% <325 mesh
90% CaC03
95
Waste Disposal

     The waste is trucked in on-road type trucks to a disposal area one
mile from the plant site.  An area-fill type landfill is used for both
the lime spray dryer and the limestone slurry processes.  The landfill
size is based on a dry waste bulk density of 50 Ib/ft3,  a gypsum wet
bulk density of 120 lb/ft3, and a 30-ft fill depth.  The landfill
design includes dikes, clay lining, drainage ditches, top soil storage,
perimeter fencing and lighting, and runoff neutralization.  An earthen-
diked, clay-lined pond, designed to minimize the sum of  land and construc-
tion costs, is used for the soda ash spray dryer process.  Pond evaporation
is assumed equal to rainfall.  Provisions for normal site maintenance of
the pond and for normal landfill operations, including compacting,
covering the waste, contouring to control runoff, and revegetation,
are included.  No costs are provided for monitoring or post-operation
maintenance.
                                   82

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TABLE 6.  FGD SYSTEM DESIGN CONDITIONS
Lignite


Absorbent stoichiometry3
Bypass, %
Total FGD AP, in. H20
Absorber
Removal efficiency, %
Absorbent liquid, % solidsc
AP, in.HgO ,t>
L/G, gal/kaft
Exit gas, wt % liquid
Effluent, % solids
Recombined gas , °F
Reheat, °F
a. Defined as mol Ca/mol S02
b. Hot gas bypass.
Lime
spray dryer
1.2
22.5
12

83.5
22.5
2
0.3
0
100
170
-
Limestone
scrubbing
1
28
8

90
60
2
80
0
15
180
-
absorbed for both

c. Excludes dilution water and recycle loop

if
.1
.1
.6





.1



Low-sulfur western coal
Soda ash
spray dryer
1.0
0
12

70
0
2
0.13
0
100
170
-
the spray dryer and

used.


Lime
spray dryer
1.2
22
12

83
22.5
2
0.2
0
100
170
-
the limestone


Limestone
scrubbing
1.1
28.1
8.4

90
60
2
80
0.1
15
170
—
processes


Low-sulfur
Lime
spray dryer
1.3
19
12

83
3
2
0.3
0
100
170
—
.


eastern coal
Limes tone
scrubbing
1.1
25.2
8.5

90
60
2
80
0.1
15
160
10



High-sulfur
Lime
spray dryer
1.8
4b
12

89
17
2
0.3
0
100
170
~



eastern
coal
Limestone
scrubbing
1.3
0
9.5

90
60
2
90
0.1
15
127
43



















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ECONOMIC PREMISES

     The economic premises are divided into criteria for capital costs
for construction of the FGD system and annual revenue requirements for
its operation.  The premises are based on regulated utility economics
using the design premises as a costing basis.  The estimates use cost
information obtained from engineering-contracting, processing, and
equipment companies; raw material suppliers; and published cost indexes.
Spray dryer costs were obtained by scaling vendor-supplied information.
Raw material costs are based on those prevailing in the Upper Great
Plains - Rocky Mountain region for the lignite and the low-sulfur western
coal cases and the Midwest region for the low- and high-sulfur eastern
coal cases.  Labor costs are assumed equivalent to those in the Midwest
for all coal cases.

Capital Costs

     The capital structure for the electric utility company is assumed
to be:

                            Common stock     35%
                            Preferred stock  15%
                            Long-term debt   50%

The cost of capital is assumed to be:

                     Common stock               11.4%
                     Preferred stock            10.0%
                     Long-term debt              9.0%
                     Weighted cost of capital
                      (based on capital costs
                      above)                    10.0%

The discount rate is 10%, the same as the weighted cost of capital.

     For other economic factors needed in financial calculations, the
following values are assumed:

                    Investment tax credit           10%
                    Federal and State income tax    50%
                    Property tax and insurance     2.5%
                    Annual inflation rate            6%

The levelized annual capital charge approach used in these premises is
similar to that used by the Electric Power Research Institute (EPRI)  (41),

Depreciation—
     A 30-yr economic life and a 30-yr tax life are assumed for the
utility plant.  Salvage value is less than 10% and is equal to removal
costs.  The annual sinking fund factor for a 30-yr economic life and
10.0% weighted cost of capital is:
                                  84

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               Sinking fund factor =
       where:
               n = economic life
               WCC = weighted cqst
                            factor
The use of the sinking fund
utilities commonly use sinking
factor is used since it is equivalent
levelized for the economic life
of capital.
                 does not indicate that regulated
             fjund depreciation.  The sinking fund
                    to straight-line depreciation
              of the facility using the weighted cost
     An annual interim replacement
as an adjustment to the depr
investment will be recovered witjhin
life of the facility.  Since
ages, an average service life is
dispersion patterns occur.  The
pattern is used (42) .  This S-l
the average-life axis, and the
low rate over many years.  The
cover replacement of individual
covered by the maintenance charg
                                   allowance of 0.56% is also included
                                   n account to ensure that the initial
                                    the actual rather than the forecasted
                             pow,er plant retirements occur at different
                                 estimated.  Many different retirement
                                type S-l Iowa State Retirement Dispersion
                                pattern is symmetrical with respect to
                               retirements are represented to occur at a
                               interim replacement allowance does not
                                items of equipment since these are
                                e.
     The sum of the years digits
used for tax purposes.  On a
this results in a credit in the
             Accelerated tax depreciation =
     where:  CRF  =
             CRF  =
                            recovery
  Capital
   plus sinkinjg
   (as a
                           decimlal
  Capital
   sinking
   fraction)
               n
= Tax life (in
Levelized accelerated depreciation credit = (ATD - SLD) x
     where:  ATD = Accelerated
             SLD = Straight-line
             ITR = Income tax
For a 50% tax rate, 30-yr tax
of capital, and 0.61% sinking
depreciation credit is 1.36%
                              rate
                              life
                              fund
                             using
                                          WCC
                                              n
                                                    = 0.61%
                                                      (1)
                                     (1 + WCC)  - 1
               (in years)
                 of capital (as a decimal fraction)
                                 method of accelerated depreciation is
                             levelized basis (using flow-through accounting),
                                fixed charge rate as follows:
                                            2CRF
                                                B
                                                        CRFT
                                                      (2)
                                                        (WCC)
                                     factor (weighted cost of capital
                                  fund factor)  for the economic life
                                   fraction)
                                     factor (weight cost of capital plus
                             fun|d factor)  for the tax life (as a decimal
                            recovery
                                 years)
                                                            ITR
                                                          1 - ITR
             tax depreciation (as a decimal fraction)
               depreciation (as a decimal fraction)
                 (as a decimal fraction)
                ,  30-yr book life, 10.0% weighted cost
                 factor, the annual levelized accelerated
                 flow-through accounting.
                                   85

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Investment Tax Credit—
     The levelized investment tax credit is calculated as follows:

                                    (CRF ) (Investment tax credit rate)
  Levelized investment tax credit = 	7^	:—,        	 ^ ^
                                            (1 + WCC)  (1 - ITR)

  where CRF , WCC, and ITR are the same factors previously defined in
  equations (1) and (2).

Using a 10.0% weighted cost of capital, 0.61% sinking  fund factor, 10%
investment tax credit rate, 50% income tax rate, the levelized investment
tax credit is 1.92% annually.

Income Tax—
     The levelized income tax is calculated as follows:

T    T •   j •       ,-     r^nr,  ,  ATT,   OT i  n   Debt Ratio x Debt Costn  r  ITR  n
Levelized income tax = [CRFg + AIR - SLD]  [1  - 	      yc~	       ]  [^ _  ITR]

                                                                        (4)
     where:   AIR = Allowance for interim replacement

Using a 10.61% capital recovery factor (weighted cost of capital plus
sinking fund factor), 0.56% allowance for interim replacements, 3.3%
straight-line depreciation, 50% debt ratio, 9.0% debt cost, and a 50%
income tax rate, the levelized income tax rate is 4.31%.

Annual Capital Charge—
     The levelized annual capital charges for a publicly owned electric
utility, as shown in Table 7, are 14.7% of the total investment.  The
annual capital charge includes charges for the capital recovery factor,
interim replacements, insurance, and property taxes, State and Federal
income taxes, and credits for investment credits and accelerated deprecia-
tion.
              TABLE 7.  LEVELIZED ANNUAL CAPITAL CHARGES

                   FOR REGULATED UTILITY FINANCING
                                         Capital charge, %

           Capital recovery factor             10.61
           Interim replacements                 0.56
           Insurance and property taxes         2.50
           Levelized income tax                 4.31
           Investment credit                   (1.92)
           Accelerated depreciation            (1.36)

                Total                          14.70
                                    86

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                               is
                               VfO
     The annual capital charge
It is recognized that land and
not depreciable and that provis
economic life of the facility to
investment credit and accelerated
for land and working capital
effect of these factors makes
capital charge rate and is
                              an
                           therefore
    applied to the total capital investment.
   rking capital (except spare parts)  are
  ons must be made at the end of the
   recover their capital value.  In addition,
    depreciation credit cannot be taken
  :cept spare parts).   The cumulative
   insignificant change in the annual
       ignored.
Capital Investment Estimates

     Capital investment estimates
beginning in early 1981 and end
a standard project are assumed
year, and 25% the third year of
fixed assets are projected to m:
midpoint of the construction
this study are based on a
balance, and equipment list.
to have a -20% to +40% range of
                          process
    for this study represent projects
  ng in late 1983.  Capital cash flows for
 1:o be 25% the first year, 50% the second
  the project life.   Capital costs for
  .d-1982, which represents the approximate
           schedule.  The estimates in
    description, flowsheet, material
      study-level estimates are considered
  accuracy.
                             expenditure
                              These
     The total fixed capital in
for equipment, building, utilit
byproduct storage, waste disposal
supervision, construction
The total capital investment
ment plus allowances for startup
of funds during construction, p
                          expense
Direct Capital Investment Process
     Direct capital costs cover
transport lines, foundations, s
mentation, raw material and byp
excavation, buildings, roads anefl
equipment.  Direct investment
annual Chemical Engineering (43
below:
      Year
      Plant
      Material11
      Labor0
                  1978    1979a
                 218.8   240.2
                 240.6   262.5
                 185.9   209.7
 restment consists of direct capital costs
  es, service facilities, raw material and
    facilities, engineering design and
     contractor fees, and contingency.
        of the total fixed capital invest-
   and modifications, royalties, the cost
  us the cost of land and working capital.
                             consists
                                process equipment, piping, insulation,
                                ructures, electrical equipment, instru-
                                oduct storage, site preparation and
                                 railroads, trucks, and earthmoving
                                    are prepared using the average
                                 cost indexes and projections as shown
costs
  1980a   1981a   1982a   1983a   1984a
  259.4
  286.1
  226.5
278.9
309.0
244.6
299.8
333.7
264.2
322.3
360.4
285.3
344.9
385.6
305.3
                           Chemical Engineering  (43) for "Equipment,
      a.  TVA projections.
      b.  Same as index in 	
          machinery,  supports,
      c.  Same as index in Chemtlcal Engineering  (43)  for  "Construction
          labor."
                                  87

-------
     The overtime premium for 7% overtime is included in the construction
labor.  Appropriate amounts for sales tax and for freight are included
in the process capital costs.

Direct Capital Investment - Utilities, Services and Miscellaneous—
     Necessary electrical substations and conduit, steam, process water,
fire and service water, instrument air, chilled water, inert gas, and
compressed air distribution facilities are included in the utilities
investment.  These facilities are costed as increments to the facilities
already required by the power plant.  Service facilities such as maintenance
shops, stores, communications, security, offices, and road and railroad
facilities are estimated on the basis of process requirements.  Services,
non-power plant utilities, and miscellaneous costs will normally be in
the range of 4% to 8% of the total process capital depending on the type
of process.  A 6% rate is used in this evaluation for both processes.

Indirect Capital Investment—
     Indirect capital investment covers engineering design and supervision,
architect and engineering contractor costs, construction costs, contractor
fees, and contingency.  Construction facilities (which include costs for
mobile equipment, temporary lighting, construction roads, raw water
supply, construction safety and sanitary facilities) and other similar
expenses incurred during construction are considered as part of construc-
tion expenses and are charged to indirect capital investment.

     Listed below are the indirect costs used:

                                                % of direct investment
                                               Process  Landfill  Pond

       Engineering design and supervision         7         22
       Architect and engineering contractor       2         11
       Construction expense                      16         88
       Contractor fees                            5         5       5

            Total                                30        16      16

A contingency of 20% is included for the spray dryer processes because
projects such as costed in this report have a higher likelihood of
exceeding rather than underrunning the capital estimate particularly
at their current status of development.  The contingency for the limestone
scrubbing process itself (i.e., excluding the landfill) is 10% because
there is more experience with these FGD systems and fewer uncertainties
in their design.  A contingency of 20% is assumed for the landfill in
the limestone scrubbing process.  These contingencies are calculated as
a percentage of the sum of the direct and the indirect investments.

Other Capital Investment—
     Startup and modification allowances are estimated at 8% to 12% of
the total fixed investment depending upon the complexities of the process
being studied.  For the spray dryer processes, a midpoint value of 10%
of the total fixed investment is assumed.  For the limestone scrubbing
process 8% is used.

-------
     Cost of funds during construction is  15.6% of the total fixed
 investment  for each process.  This factor  is equivalent to the  10%
 weighted cost of capital with 25% of the construction expenditures of
 the  first year, 50% the second year, and 25% the third year of  the
 project construction schedule.  Expenditures are assumed uniform over
 each year.  Startup costs are assumed to occur late enough in the project
 schedule that there are no charges for the use of money used to pay
 startup costs.

     For both spray dryer processes, royalty fees of 1% of the  total
 process capital (excluding pond or landfill) are charged.  No royalty
 fee  is assessed for the limestone scrubbing process.  Land cost is
 assumed to  be $5,000 per acre.

     Working capital is the total amount of money invested in raw materials,
 supplies, finished and semifinished products, accounts receivable, and
 monies on deposit for payment of operating expenses such as salaries,
 wages, raw  materials, purchases, taxes, and accounts payable.  For these
 premises, working capital is defined as the equivalent cost of  1 month's
 raw  material, 1.5 months' conversion cost, and 1.5 months' plant and
 administrative overhead costs.  In addition, it includes an amount equal
 to 3% of the total direct investment to cover spare parts, accounts
 receivable, and monies on deposit to pay taxes and accounts payable.

 Annual Revenue Requirements

     Annual revenue requirements use 1984  costs and are based on 5,500
 hours of operation per year at full load.  Annual revenue requirements
 are  divided into direct costs and indirect costs.  Both first-year and
 levelized annual revenue requirements are  determined.  Levelized annual
 revenue requirements are based on a 10% discount factor and a 6% inflation
 rate over the 30-yr life of the power unit.  Direct costs consist of raw
 materials,  labor,  utilities, maintenance,  and analytical costs.   Indirect
 costs consist of levelized annual capital  charges and overheads.

 Direct- Costs—
     Projected raw material, labor,  and utility costs are listed in
 Table 8.   Unit costs for lime and soda ash are different for the western
 and the eastern coal applications reflecting the actual differences in
 delivered cost to  specific areas.  These differences are primarily due
 to the delivery charges rather than the cost of the raw material itself.
Unit costs for steam and electricity are based on the assumption that
 the required energy is purchased from another source.   Unit costs
 ($/kW,  mills/kWh)  are calculated on the basis of net power output of the
unit excluding the electricity consumed by the pollution control systems.
Actually,  electrical use by the pollution control equipment will result
 in a derating of the utility plant for either a new or a retrofitted
unit.  To  minimize iterative calculations,  the pollution control equipment
is charged with purchased electricity instead of derating the utility plant.
                                    89

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              TABLE 8.  PROJECTED 1984 UNIT COSTS FOR RAW

                   MATERIALS, LABOR, AND UTILITIES


                                  	$/unit	
                                Lignite and
                                western coal
                  Eastern coals
       Raw materials
         Limestone
         Lime
         Soda ash
       Labor
         Operating labor
         Analyses
         Mobile equipment
       Utilities
         Process water
         Electricity
         Steam
8.50/ton
102.00/ton
145.00/ton

15.00/man-hr
21.00/man-hr
21.00/man-hr

0.14/kgal
0.037/kWh
8.50/ton
75.00/ton
160.00/ton

15.00/man-hr
21.00/man-hr
21.00/man-hr

0.14/kgal
0.037/kWh
2.50/klb
     Maintenance costs are estimated as a percentage of the direct
investment, based on unit size and process complexity.  For the limestone
slurry process, non-landfill maintenance is 7% and landfill maintenance
is 3%.  For the lime spray dryer process, non-landfill maintenance is 6%
and landfill maintenance is 3%.  For the soda ash spray dryer process,
non-landfill maintenance is 5% and pond maintenance is 3%.

Indirect Costs—
     The levelized annual capital charges consist of a sinking fund
factor, an allowance for interim replacement, property taxes, insurance,
weighted cost of capital, income tax, credits for accelerated depreciation,
and investment credit.  The levelized annual capital charge for a
regulated utility, as was shown in Table 7, is 14.7%.

     Plant and administrative overhead is 60% of conversion costs less
utilities.  The plant and administrative overheads include plant services
such as safety, cafeteria, medical, plant protection, janitor, purchasing
personnel, general engineering (excluding maintenance), interplant
communications and transportation, recreational facilities, and the
expenses connected with management activities.  Fringe benefits such as
retirement, vacation, dental and medical plans are included in the base
wage rates.
                                   90

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                           SYSTEMS ESTIMATED
     This section describes the design of the FGD processes evaluated in
this report.  For the lignite case only the lime spray dryer and
limestone scrubbing process are evaluated.  For the low-sulfur western
coal case all three processes, the soda ash spray dryer, the lime spray
dryer, and the limestone scrubbing processes, are evaluated.  For the
low-sulfur eastern coal and the high-sulfur eastern coal, again only
the lime spray dryer and limestone scrubbing processes are evaluated.
The lime spray dryer and limestone scrubbing processes are essentially
the same design for all four coal cases.  Equipment sizes, flow rates,
waste recycling, and bypass and reheat requirements differ, depending on
the ash compositions and removal efficiencies required, as described in
the design premises.

     The simple, basic chemistry of these FGD processes has been described
elsewhere (3,4).  In essence, the S02» 803, and HC1 in the gas react
with the absorbent to form a mixture of hydrated sulfites and sulfates
and chlorides.  In the soda ash spray dryer process, these are the
highly soluble Na^CL-nl^O, Na2S04'nH20, and NaCl.  In the lime spray
dryer and limestone scrubbing processes, these are the relatively
insoluble CaS03'l/2H20 and CaS04'2H20 and CaCl^.  In all three processes
the sulfite species predominates.  In the air-oxidation limestone process
used in this study, the waste is further oxidized by sparging air through
the slurry to aid dewatering.  This produces a waste composed almost
entirely (about 95%) of Ca2S04'2H20 (gypsum), with the original quantity
of CaCl2.


LIGNITE CASE

     The 0.9% sulfur lignite, with a heating value of 6,600 Btu/lb
and 7.2% ash, is lower in both heating value and ash and higher in
moisture content than the eastern and the western coals used in this
study.  Equally important are the characteristics of the ash, which has
a high calcium content and a high resistivity.  Both of these factors
are important determinants of flue gas cleaning costs, particularly in
economic comparisons of systems using spray dryers and those using wet
scrubbing with separate fly ash collection.  The alkalinity of the ash
can serve to supplement expensive (i.e., nonlimestone) absorbents.
Separate fly ash collection using ESP's requires higher SCA's than would
be used for high-sulfur eastern coals and, hence, more expensive ESP's.
The designs of FGD systems prescribed by these factors thus differ from
designs of the same process for higher sulfur eastern coals.


                                  91

-------
Lime Spray Dryer Process

     The process uses four trains of spray dryers, each with warm-gas
bypass and one fabric filter baghouse.  Each spray dryer is equipped
with emergency hot-gas bypass ducts.  Four ducts, each with an ID booster
fan, connect the baghouse to the stack plenum.  Because of the alkalinity
of the fly ash, provision is made for recycling some of the collected
waste.  The flow diagram and layout are shown in Figures 15 and 16, and
the material balance is shown in Table 9.

     Pebble lime (CaO) is received by rail and stored in a silo.  The
lime is removed from the silo and slaked to an absorbent slurry of about
22% solids which is pumped to the spray dryers.  Three top-mounted
rotary atomizers are used, each with separate recycled waste and water
additions.  The S02 content of the cleaned flue gas controls the absorbent
addition rate, and the temperature of the cleaned flue gas (after recom-
bination with the bypassed flue gas) controls the water addition rate.
These provide both S02 emission and flue gas temperature controls.
About 22% of the flue gas bypasses the spray dryers and enters the ducts
to the baghouse.  The remaining flue gas enters the three operating
spray dryers at 300 F through manifolds around each atomizer and mixes
with the atomized absorbent.  The particle-laden flue gas leaves the
bottom of the spray dryer and passes down an inclined duct where it
mixes with the bypassed flue gas.  The recombined flue gas enters the
baghouse at 165 F.  The SOX in the flue gas continues to react with the
absorbent particles until it passes through the cake on the fabric
filters.  The cake is periodically dislodged by reverse air flow and
falls into hoppers from which it is periodically removed and pneumatically
conveyed to storage and recycle silos.  The recycle waste is mixed with
water to form a 40% solids slurry and pumped to the spray dryers.  About
65% of the material collected is recycled.  The waste from the storage
silo is trucked to the landfill site.

     To facilitate cost determinations and comparisons, the lime spray
dryer process is divided into six sections.  The equipment list, giving
the description and cost of each equipment item by section, is shown in
Table 10.  These costs do not include the investment required for
foundations, structures, electrical components, piping, instruments and
controls, etc.  Each of these processing sections is described below.

Material Handling—
     This and the following section,  feed preparation, compose the raw
material receiving and preparation section.  The material handling
section includes all of the equipment to receive pebble lime by rail and
to maintain a supply of lime to the weigh feeders.  It includes a lime
storage silo with a 30-day capacity and  two lime feed bins each having a
12-hour capacity.

Feed Preparation—
     The feed preparation section includes the equipment necessary to
convert the lime into a 22% solids slurry for  S02 absorption.  Two
trains of lime preparation equipment  (feeders, slakers, tanks, and

                                   92

-------

BL
1 F


<

CKET
VATOR



\






LIME
STORAGE
SILO
i



E

                      BUCKET
                     ELEVATOR
           Q
                                                                  AIR -
                                                                  13
                                                                  17
                                                                              I    I   I.
I




1
II
1


1




1
• 9
SLURRY
FEED
TANK





                                                                                      PARTICULATE
                                                                                       RECYCLE
                                                                                        SILO
Figure  15.   Lignite  case.   Lime spray dryer process.   Flow  diagram.

-------
 H-
CJQ
CTQ
 O
 93
 CO
 CD
 g
 (T)
 O.
 H
v;
 ro
i-i
O
n
ro
en
en
                                          ROAD
                                             SWITCHYARD  -
                                          ROAD
                                     OFFICES
                      •{•TRANSFORMER*
                      ?    YARD
                                   -n
                                   c
..._  L...
                                                a) c
                                                O31
                                                05
                                                Si
                                                is
                                                              PARKING
                                       r-ai
                                       o<
                                         ROAD
                                                                                     DOCK
                                               RIVER

-------
                       TABLE 9.   LIGNITE CASE




                      LIME  SPRAY DRYER PROCESS




                          MATERIAL BALANCE

Description
1

1
A
r
6

H
9
ii.
Total stream, Ib/hr

Flow rate, sft3/min @60°I
Temperature , °F
Pressure, psig 	

Specific gravity
pH 	 ,__
Undissolved solids. %

1
Coal to boiler
833,300









2
Combustion air
to air heater
5,958.000

1,315,000
80






3
Combustion air
to boiler
5.124.000

1^131,000
535






4
Gas to
economizer
5.925.000

1.290.000
890






5
Gas to
air heater
Sr
-------
                         TABLE 10.   LIGNITE CASE

                        LIME SPRAY  DRYER PROCESS

                  EQUIPMENT LIST, DESCRIPTION,  AND COST

Area

1.
2.
3.
1 — Materials
Item
Car shaker
Car puller
Hopper,
Handling
No.
1
1
1

Description
Top mounted with crane,
20 hp
25 hp with 5 hp return
12 ft x 12 ft x 2 ft

Total
material
cost,
1982 $
74,700
64,600
3,700

Total
labor
cost,
1982 $
11,300
24,200
2,600
    unloading
4.   Pump, pit
    sump
    Conveyor, lime
    unloading
    (enclosed)

    Elevator, storage
    silo
7.  Silo, lime
    storage
    Vibrators
 5.  Conveyor, live
    lime feed
9.  Elevator, live
    lime feed
bottom, 20 ft deep,
carbon steel

Centrifugal, 60 gpm, 70     10,600      3,300
ft head, 5 hp, carbon
steel, neoprene lined

Belt, 24 in. wide, 200      14,600      1,000
ft long, 2 hp, 100 tons/
hr

Continuous bucket, 16 in.   33,600      3,400
x 8 in. x 11-3/4 in., 75
ft lift, 15 hp, 100 tons/hr,
160 ft/min

45 ft dia x 50 ft straight 109,600     99,200
side, 79,500 ft3, 45°
slope, carbon steel

Bin activator, 10 ft        14,500      2,400
dia

Belt, 14 in. x 100 ft       11,400      1,000
long, 2 hp, 16 tons/hr,
100 ft/min

Continuous bucket, 8 in.    16,800      2,700
x 5-1/2 in. x 7-3/4 in.,
35 ft lift, 2 hp, 16 tons/hr,
150 ft/min

   (continued)
                                    96

-------
                          TABLE  10  (continued)

Area



10.
11.
Area



1.
1 — ( continued)


Item No.
Bin, lime 2
feed
Dust collecting 1
system
Subtotal
2 — Feed Preparation


Item No.
Feeder, lime 2



Description
12 ft dia x 12 ft
straight side, 1,360
ft3, 60° slope,
w/ cover, carbon
steel
Bag filter, polypro-
pylene bag, 2,200 ft
7-1/2 hp



Description
Vibrating, 3-1/2 hp,

Total
material
cost ,
1982 $
13,400
8,000
/min,
375,500

Total
material
cost,
1982 $
8,300

Total
labor
cost ,
1982 $
11,500
1,600
164,200

Total
labor
cost,
1982 $
600
2.
bin discharge

Feeder, lime
feed
3.  Slaker
4.  Tank, slaker
    product
carbon steel

Screw, 6 in. dia x           4,000      3,300
12 ft long, 1 hp,
3 tons/hr

Ball-mill type, 37.5       213,000     29,300
hp s laker, 1 hp clas-
sifier, 3 tons/hr

7 ft dia x 9 ft high,        5,800      4,300
2,600 gal, open top,
four 7 in. baffles,
agitator supports,
carbon steel, neoprene
lined
5.  Agitator, slaker    2
    product tank
2 turbines, 28 in.  dia,
3 hp, neoprene coated

   (continued)
                            15,400
                                                                1,600
                                    97

-------
                           TABLE 10 (continued)

Area 2

6. Pt
(continued)
Item No.
imp, s laker 3 Ce

Total
material
cost,
Description 1982 $
ntrifugal, 43 gpm, 6,700

Total
labor
cost,
1982 $
2,500
     product tank
 7.   Tank,  slurry
     feed tank
     Agitator,  slurry
     feed tank

     Pump, slurry
     feed tank
10.   Dust collecting
     system
12
50 ft head, 1-1/2 hp,
carbon steel, neoprene
lined
(2 operating, 1 spare)

11 ft dia x 15 ft high,
10,670 gal, open top,
four 11 in. baffles,
agitator supports,
carbon steel, neoprene
lined

2 turbines, 44 in. dia,
7-1/2 hp, neoprene coated

Centrifugal, 43 gpm, 100
ft head, 5 hp, carbon
steel, neoprene lined
(6 operating, 6 spare)

Bag filter, polypro-
pylene bag, 2,200 ft3/
min, 7-1/2 hp (1/2 cost
in materials handling
area)
                                 11,500
14,900


30,000
                                  3,900
     Subtotal
                                313,500
 1.   Fan
     Induced draft,  473,000
     aft^/min, 12 in,  static
     head,  1,500 hp, fluid
     drive,  double width,
     double  inlet
     (4 operating)
                         2,895,500
     Subtotal
                              2,895,500
            8,600
1,100


9,000
              600
                                       60,900
Area 3 — Gas Handling
Total
material
cost ,
Item No. Description 1982 $
Total
labor
cost?
1982 $
           56,100
                                       56,100
                                (continued)

                                     98

-------
                         TABLE 10 (continued)
Area 4 — S02 Absorption
Item No. Description
1. Spray dryer 4 48 ft dia x 54 ft
high, with 3 rotary
atomizers, carbon
steel
(3 operating, 1 spare)
Subtotal

Total
material
cost,
1982 $
4,324,000
4,324,000

Total
labor
cost ,
1982 $
567,200
567,200
Area 5 — Particulate Removal
Item No. Description
1. Baghouse 1 Automatic fabric
filter, 28 compart-
ments, 2.5 air-to-
cloth ratio
Subtotal
Area 6 — Particulate Handling and Recycle
Item No. Description
1. Conveyor, parti- 1 Pneumatic, pressure
Total
material
cost,
1982 $
8,973,000
8,973,000

Total
material
cost ,
1982 $
243,100
Total
labor
cost,
1982 $
3,227,000
3,227,000

Total
labor
cost,
1982 $
78,200
    culate feed to
    bin

2.   Bin, parti-
    culate storage
    Vibrators
vacuum, 250 hp
25 ft dia x 30 ft
straight side, 14,800
ft3, 60° slope,
w/cover, carbon steel

Bin activator, 10 ft
dia

   (continued)
                            56,500     51; 100
28,900
                                        4,800
                                    99

-------
                           TABLE 10  (continued)

Area

3.
6 — (continued)
Item No. Description
Silo, parti- 2 28 ft dia x 44 ft

Total
material
cost,
1982 $
85,000

Total
labor
cost,
1982 $
72,400
4.
5.
    culate storage
Feeder,
particulate

Feeder, recycle
slurry tank
6.  Tank, recycle
    slurry
7.  Agitator, recycle   1
    slurry tank

8.  Pump, recycle      12
    slurry tank
    Subtotal
straight side,
27,100 ft3, 60°
slope, w/cover,
carbon steel

Vibrating, 3-1/2 hp,
carbon steel

Screw, 14 in. dia x
12 ft long, 5 hp, 60
tons/hr

26 ft dia x 28 ft high,
110,200 gal, open top,
four 26 in. baffles,
agitator supports,
carbon steel, neoprene
lined

104 in. dia, 40 hp,
neoprene lined

Centrifugal, 153 gpm,
100 ft head, 20 hp,
carbon steel, neoprene
lined
(6 operating, 6 spare)
 8,400
30,800
                                                    50,100
                                                    71,200


                                                    53,300
  800
4,500
           39,000
            3,400


           12,500
                                                   627.300    266.700
                                    100

-------
agitators) are used.  Each train is sized to handle 100% of the full
load capacity.  A slurry feed tank with a 4-hour capacity is provided.

Gas Handling—
     Included in this area is an inlet plenum that supplies the flue gas
ducts to the scrubber trains.  This area also includes the ductwork from the
boiler to the inlet plenum, the bypass ducting around the spray dryers,
the emergency bypass ductwork around the boiler air heaters and spray
dryers, the ductwork from the spray dryers to the baghouse, and the
ductwork from the baghouse to the stack plenum.  It also includes the
four ID booster fans between the baghouse and the stack plenum.

SC>2 Absorption—
     Four spray dryers are provided (three operating and one spare);
each is sized to handle one-third of the total flue gas volume
being scrubbed.

Particulate Removal—
     A single baghouse containing 28 compartments and the associated
equipment is provided.

Particulate Handling and Recycle—
     A single train of equipment to store, reslurry, and recycle the
waste material is provided.  Two particulate storage bins are included
to provide a 24-hr capacity for waste material to be landfilled.

Limestone Scrubbing Process

     The process uses four trains of flue gas process equipment (three
operating and one spare).  Each train consists of a cold-side ESP, the
spray tower absorber system with warm-gas bypass, and an ID booster fan.
The purge streams from the absorbers are dewatered in a single train
consisting of a thickener and a rotary filter.  The flow diagram and
layout are shown in Figures 17 and 18 and the material balance is shown
in Table 11.

     Fly ash is collected in 99.8% efficient cold-side ESP's located
upstream of the boiler ID fans.   Because of the high resistivity of
lignite fly  ash,  the ESP's  are sized for  a SCA of 700  ft2/kaft3.
Standard pressure pneumatic conveying equipment is used to convey the
fly ash to storage silos from which it is trucked to the landfill.

     Flue gas from the ESP's enters the inlet plenum and is distributed
to the three absorber trains and the bypass ductwork.   About 28% of the
flue gas in the plenum is bypassed around the absorbers to the stack
plenum for reheat purposes.   The remaining flue gas enters one of the
three absorber trains and is cooled to about 140°F in a presaturator
using sprays of absorbent liquid and passes upward through the absorber
and mist eliminator, emerging at about 130°F with an entrained moisture
content of 0.1%.   This scrubbed  flue gas  passes through the booster
ID fan to the stack plenum,  where it is mixed with the bypassed flue
gas.   The resulting mixture,  at  175°F and with an overall S02  reduction
of 70%,  enters the stack.
                                 101

-------
                                             SCRUBBER AREA

                                               SPRAY TOWER
                                             FORCED OXIDATION
               IECONOMIZER!  ELECTROSTATIC
                         PRECIPITATOR
              COMBUSTION
                AIR
                         wv








J±k
'„.///,'////////////&












fi
1 D FAN
	 MAKE-UP
" • WATER




        HOPPERS, FEEDERS AND CONVEYORS
Figure 17.   Lignite case.   Limestone scrubbing process.   Flow diagram.

-------
                                                              £01
OQ
 00
 H-
cw
 O
 (B
 CD
 fD
 fD
 CO
 rt
 O
 p
 (D

 CO
 O
 l-i

 g-
 cr
 H-
 3
OP
 O
 O
 ft)
 en
 CD
 O
 rf
                                                                                                    DOCK

-------
  TABLE 11.  LIGNITE CASE
LIMESTONE SCURBBING PROCESS
     MATERIAL BALANCE



1
2
i
4
5
ft
1
8
9
J°
Stream No.


Total stream, Ib/h*-

Flow ratej sft^/min @60°I
Temperature . °F
Pressure, psig
Flow rate , gpm
Specific gravity
pH
Undissolved solids , %

1


833,300









2
Combustion air

5.958.000

1,315,000
80






3
Combustion air

5.124.000

1,131,000
535






4
Gas to

5.925.000

1.290.000
890






5
Gas to

5 ,92^, 000

1.290.000
705






Stream No.

1
2
)
4
b
6
7
8
t
|()
Description
Total stream, Ib/hr

Flow rate, sftJ/min @60°1
Temperature, "F
Pressure, psig
Flow rate, gpm
Specific gravity
pH
Undissolved solids, 7a

6
Gas to
electrostatic
precipitator
6,759,000

1,474,000
300






7
Gas to
spray tower
4,826,000

1,060,000
300






8
Gas to
stack
6,913,000

1,545,000
185






9
Makeup water
to spray tower
213,200




427




10
Recycle slurry
to presaturator
2.866.000




5.205


15



1
2
j
4
5
6
7
8
y
10
Stream No.
Description


Flow rate, sft^/min @60°I
Temperature . °F
Pressure. nslK
Flow rate. 2pm
Specific gravity
PH
Undissolved solids. %

11
Supernate to
oxidation-
recirculation
tank
73,470




747




12
Recycle slurry
to spray tower
57,320,000




104,110


15

13
Slurry to
thickener
feed tank
103,100




187


15

14
Slurry to
thickener
103,100




187


15

15
Thickener
underflow to
filters
38,680




58




Stream No.

1
2
1
4
b
6
/
8
y
10
Description
Total stream. Ib/hr

Flow rate, sftj/min @60°F
Temperature, °F
Pressure, psig
Flow rate , gpm
Specific gravity
PH
Undissolved solids, %

16
Thickener over-
flow to oxidatioi
recirculation
tank
60 , 600




121




17
Gypsum filter
cake to
disposal
19,340







80

18
Filtrate to
filtrate
surge tank
19,340




39




19
Filtrate to
oxidation-
recirculation
tank
12,870




26




20
Filtrate to
ball mills
6,470




13




        (continued)
            104

-------
                        TABLE 11 (continued)
Stream No.

1
2
i
4
5
6
7
8
9
1°
Description
Total stream. Ib/hr

Flow rate, sft^/min @60°!
Temperature . °F
Pressure, psig
Flow rate, Rpm
Specific gravity
PH
Undissolved solids, %

21
Limestone
to weigh
feeders
9,700









22
Limestone
slurry to mills
product tank
16 , 200




20


60

23
Limestone slurry
to oxidation-
recirculation
tank
16,200




20


60

24
Air to
oxidation-
recirculation
tank
14.080

3,067
60


















 9
10
8
9
10
                                 105

-------
     Makeup limestone is fine crushed and wet ball milled to 90% less
than 325 mesh and stored as a 60% solids slurry.  This slurry, along
with recycled water from the waste dewatering system, is added to the
absorbers to maintain 15% solids in the absorber recirculating slurry.
The recirculating slurry is pumped through the spray tower, from which
it drains into a recirculation-oxidation tank.  Air is sparged into the
tank to oxidize the CaS03-1/2^0 to CaS04«2H20  (gypsum).  A purge stream
is withdrawn from each tank and pumped to the dewatering system.

     The dewatering system consists of a thickener in which the purge
stream is thickened to 40% solids and a rotary filter in which it is
dewatered to 80% solids.  The resulting cake is piled in a holding area
from which it is trucked to the landfill.

     To facilitate cost determinations and comparisons, the limestone
slurry process is divided into six processing sections.  The equipment
list, giving the description and cost of each equipment item by section,
is shown in Table 12.  Each of these processing sections is described
below.

Material Handling—
     This area includes all of the facilities needed for receiving the
raw limestone, areas for a 30-day storage stockpile, and a 24-hour in-
process limestone storage area.

Feed Preparation—
     Three trains (two operating and one spare) of gyratory crushers and
wet ball mills to convert the raw limestone to a 90% minus 325 mesh; 60%
solids slurry is included in this area.  It also contains a product
storage tank with an 8-hour capacity.

Particulate Removal—
     Four 99.8% efficient ESP units sized for lignite are included in
this area.

Gas Handling—
     Included in this area is an inlet plenum supplying the four flue
gas ducts to the absorbers.  This area also includes the ductwork from the
boiler air heater to the ESP and from the ESP to the inlet plenum, the
emergency bypass ductwork around the absorber area, the ductwork from
the absorbers to the stack plenum, and four ID  fans to compensate for
the pressure drop in the FGD system.

S02 Absorption—
     Four trains of spray tower absorbers with presaturators, mist
eliminators, recirculation tanks, and recirculating pumps are included.
Oxidation air blowers and sparging rings for each recirculation tank are
also included.  Each absorber train is sized to handle one-third of the
total flue gas volume being scrubbed.
                                   106

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                            TABLE  12.  LIGNITE  CASE

                          LIMESTONE  SCRUBBING PROCESS

                     EQUIPMENT LIST, DESCRIPTION, AND  COST

Area 1 — Materials Handling


Item
1 . Mobile equipment
2. Hopper, reclaim


No.
1
1


Description
Bucket tractor
7 ft x 4-1/4 ft x 2 ft
Total
material
cost,
1982 $
76,000
1,200
Total
labor
cost,
1982 $
-
800
3.  Feeder, live
    limestone storage
    deep,  carbon steel

1   Vibrating pan,  5 tip
4.  Pump, tunnel slump   1
5.  Conveyor, live
    limestone feed
    Conveyor, live
    limestone feed
    (inclined)

    Elevator, live
    limestone feed
 !.  Bin, crusher feed    3
9.  Conveyor, feed belt  1
    Vertical,  60 gpm,  70 ft
    head,  5 hp,  carbon steel,
    neoprene lined
    (1 operating,  1 spare)

    Belt,  30 in. wide  x 100 ft
    long,  2 hp,  100 tons/hr,
    60 ft/min

    Belt,  30 in  wide x 190  ft
    long,  40 hp, 35 ft lift,
    100 tons/hr, 60 ft/min

    Continuous bucket,  12 in.
    x 8 in.  x  11-3/4 i»n., 75 hp,
    90 ft  lift,  100 tons/hr,
    160 ft/min

    13 ft  dia x  21 ft  high,
    w/cover,  carbon steel

    Belt,  30 in. wide  x 60  ft
    long,  7.5 hp,  100  tons/hr,
    60 ft/min
 5,500
 2,400
22,900



60,300



57,800




43,300


20,500
   500
   800
 1,400



 3,700



 6,700




24,100


 1,400
10.
11.


Tripper
Dust collecting
system
Subtotal


1 1 hp, 30 ft/min
1 Bag filter, polypropylene
bag, 2,200 aft3/min, 7-1/2
hp, automatic shaker system
(continued)
107
27,200
7,800
324,900


9,100
2,600
51,100



-------
TABLE 12 (continued)

Area 2 — Feed Preparation

1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Item No.
Feeder, crusher 3
Crusher 3
Ball mill 3
Tank, mills 3
product
Agitator, mills 3
product tank
Pump, mills 3
product tank
Tank, slurry feed 1
Agitator, slurry 1
feed tank
Pump, slurry feed 6
tank
Dust collecting 3
system
Subtotal
Total
material
cost,
Description 1982 $
Weigh belt, 18 in. wide x 49,600
14 ft long, 2 hp, 3 tons/hr
Gyratory, 0 x 1-1/2 to 3/4 297,100
in., 75 hp, 3 tons/hr
Wet, open system, 150 hp, 543,800
3.0 tons/hr
10 ft dia x 10 ft high, 13,700
5,500 gal, open top, four
10 in. baffles, agitator
supports, carbon steel,
flakeglass lined
36 in. dia, 10 hp, neoprene 22,900
coated
Centrifugal, 12 gpm, 60 ft 7,700
head, 1 hp, carbon steel,
neoprene coated
(2 operating, 1 spare)
12 ft dia x 12 ft high, 6,500
10,800 gal, open top, four
12 in. baffles, agitator
supports, carbon steel,
flakeglass lined
48 in. dia, 16 hp, neoprene 13,100
coated
Centrifugal, 7 gpm, 60 ft 15,000
head, 1/4 hp, carbon steelj
neoprene lined
Bag filter, polypropylene 23,300
bag, 2,200 aft3/min, 7-1/2
hp, automatic shaker system
992,700
Total
labor
cost,
1982 $
2,300
6,500
65,300
11,000
5,500
2,700
5,400
1,100
5,500
7,800
113,100
     (continued)
         108

-------
                          TABLE 12  (continued)
Are.

1.

2.
3.
4.
a 3 — Particulate Removal

Item No.
ESP 4

Conveyor, fly ash 1
to particulate bin
Bin, particulate 2
Vibrator 2
Subtotal

Total
material
cost,
Description 1982 $
99.8% removal efficiency 9,223,000
SCA = 700
Pneumatic, pressure-vacuum, 84,000
125 hp
28 ft dia x 28 ft high, 66,000
w/cover, carbon steel
Bin activator, 10 ft dia 28,900
9,401,900

Total
labor
cost,
1982 $.
4,542,700

30,509
64,800
4,800
4,642,800
Area 4 — Gas Handling
1.   Fans
Induced draft, 472,900
aft^/min, 8.6 in. static
head, 900 hp, fluid drive,
double width, double inlet,
Inconel
3,063,400
 52,600
    Subtotal
                            3,063,400
               52,600
Area 5—S0? Absorption
1.  SOo Absorber
2.  Tank, effluent-
    oxidation
Spray tower, 27 ft long     5,144,600
x 27 ft wide x 40 ft high,
1/4 in. carbon steel,
neoprene lined; FRP spray
header, 316 stainless steel
chevron vane entrainment
separator and nozzles
(3 operating, 1 spare)
42 ft dia x 42 ft high,
429,500 gal, open top,
four 42 in. wide baffles,
agitator supports, carbon
steel, flakeglass lined
(4 operating, 1 spare)

     (continued)

        109
  346,500
              418,500
280,000

-------
                            TABLE  12  (continued)

Area

5 (continued)
Item No.

Total
material
cost,
Description 1982 $

Total
labor
cost,
1982 $.
3.  Agitator, effluent-  4
    oxidation tank
4..  Pump, slurry
    recirculation
5.  Pump, presaturator
    recycle
6.  Pump, oxidation
    bleed
7.
     Air blower,
     oxidation
 8.   Sparger,  oxidation
 9.   Pump,  makeup
     water
10.   Soot blower

     Subtotal
                         12
168 in. dia, 100 hp,
neoprene coated
(3 operating, 1 spare)

Centrifugal, 17,400 gpm,
100 ft head, 100 hp,
carbon steel, neoprene
lined
(6 operating, 6 spare)

Centrifugal, 1,735 gpm,
100 ft head, 80 hp,
carbon steel, neoprene
lined
(3 operating, 5 spare)

Centrifugal, 62 gpm,
60 ft head, 2.0 hp,
carbon steel, neoprene
lined
(3 operating, 3 spare)

1,022 sft3/min, 125 hp
(3 operating, 1 spare)

21 -ft dia ring
(3 operating, 1 spare)

Centrifugal, 3,253 gpm,
200 ft head, 300 hp, carbon
steel
(1 operating, 1 spare)
                        32'  Air fixed
                                                             474,000   155,600
                                                          1,343,400   116,800
                                                              90,600    28,500
                                                              16,800     5>50o
                                                             66,200     3,100


                                                             52,100    31,000


                                                             31,700     3,600




                                                             89,500    83,500

                                                          7.655.400 1.126,100
                                 (continued)
                                      110

-------
                            TABLE 12 (continued)
 Area 6—Solids S_eDaration
           Item
No.
Description
 Total
material
 cost,
 1982 $
Total
labor
cost,
1982 $
 1.   Tank,  thickener
     feed
 2.   Agitator,  thickener  1
     feed tank

 3.   Pump, thickener      2
     feed
 4.   Thickener
 5.   Pump,  thickener
     overflow
     Tank, thickener
     overflow
     Pump,  thickener
     underflow
 5.   Tank,  filter feed    1
 9.   Agitator,  filter     1
     feed tank

10.   Pump,  filter feed    3
     slurry
    21 ft dia x 42 ft high,        34,500
    107,200 gal, open top,
    agitator supports, four
    19 in. baffles, carbon
    steel, flakeglass lined

    84 -in. dia, 60 hp,             40,300
    neoprene coated

    Centrifugal, 187 gpm,           8,100
    60 ft head, 5 hp,
    carbon steel, neoprene
    lined
    (1 operating, 1 spare)

    Stainless steel tank, 33 ft    46,600
    dia x 5 ft high; concrete
    basin, 4 ft high

    Centrifugal, 121 gpm, 75 ft     8,900
    head,  4 hp, carbon steel,
    neoprene lined
    (1 operating, 1 spare)

    8-1/2 ft dia x 5 ft high        1,200
    2,000 gal, open top,
    carbon steel

    Centrifugal, 58 gpm, 6 'ft       4,900
    head, 1 hp, carbon steel,
    neoprene lined
    (1 operating, 1 spare)

    5-1/2 ft dia x 5-1/2 ft high,   1,300
    963 gal,  open top,
    carbon steel, flakeglass
    lined

    22 -in. dia, 3 hp, neoprene      1,200
    coated

    Centrifugal, 29  gpm, 50 ft      8,000
    head, 1 hp, carbon steel,
    neoprene lined
                                 28,500
                                  3,300


                                  2,700
                                 49,300
                                   1,000
                                    800
                                   1,800
                                   1,100
                                     100
                                  2,700
                                   (continued)

                                       111

-------
                            TABLE 12 (continued)
Area 6_

(continued)
Item No.

Total
material
cost,
Description 1982 $

Total
labor
cost,
1982 $
11.  Filter
12.   Pump, filtrate
13.   Tank,  filtrate
     surge

14.   Pump,  filtrate
     surge  tank
15.   Conveyor, gypsum
     disposal
     Subtotal
3  Rotary vacuum, 5 ft dia
   x 5 ft face, 150 total
   hp

4  Centrifugal, 19 gpm, 20 ft
   head, 1 hp, carbon steel,
   neoprene lined
   (2 operating, 2 spare)

1  5 ft dia x 5 ft high,
   638 gal, carbon steel

2  Centrifugal, 39 gpm,
   head, 1 hp, carbon steel,
   neoprene .lined
   (1 operating, 1 spare)

1  Belt, 14 in. wide x 75- ft
   long, 100 ft inclined, 1-1/2
   hp, 11 tons/hr, 70 ft/min
185,800
 16,500
    600
  8,500
 37,100
50,400
 1,900
   400
 1,000
 3,500
                                  403,500    148,500
Note:  These costs represent equipment costs only.  Costs for piping,
       electrical equipment, instruments, foundations, and other installation
       costs are not included.  The differences in area costs between the
       equipment list and the capital summary sheets are due to these
       installation costs.

       Most equipment cost estimates are based on informal vendor quotes
       and TVA information.
                                     112

-------
Solids Separation—
     This area includes a single train of equipment for recovering the
gypsum from the absorber system effluent slurry.   The major equipment
consists of a thickener and a filter but other minor equipment such as
tanks, pumps, agitators, and a conveyor are also included.
LOW-SULFUR WESTERN COAL CASE

     The 0.7% sulfur western coal, with a heating value of 9,700 Btu/lb
and 9.7% ash, is lower in both heating value and ash than the eastern
coals used in this study.  Equally important are the characteristics of
the ash, which has a high calcium content and a high resistivity.  Both
of these factors are important determinants of flue gas cleaning costs,
particularly in economic comparisons of systems using spray dryers and
those using wet scrubbing with separate fly ash collection.  The alkalinity
of the ash can serve to supplement expensive (i.e., nonlimestone) absorbents.
Separate fly ash collection using ESP's requires higher SCA's than would
be used for high-sulfur eastern coals and, hence, more expensive ESP's.
The designs of FGD systems prescribed by these factors thus differ from
designs of the same process for eastern coals.

Soda Ash Spray Dryer Process

     The process uses five trains of spray dryers without warm-gas
bypass and one fabric filter baghouse.  Each spray dryer is equipped
with emergency hot-gas bypass ducts.  Four ducts, each with an ID booster
fan, connect the baghouse to the stack plenum.  The flow diagram and
layout are shown in Figures 19 and 20, and the material balance is
shown in Table 13.

     Dry bulk soda ash is received in self-unloading rail cars and
stored as the monohydrate under a saturated 32% solution, a common
industry practice that reduces storage volume.  The solution is withdrawn
and diluted to about 6% for use in the spray dryers.  Three top-mounted
rotary atomizers- are used in each spray dryer.  In addition to the
absorbent solution, water is supplied to the atomizers.  The absorbent
feed rate is controlled by the S02 content of the cleaned flue gas, and
the water rate is controlled by the temperature of the cleaned flue gas.
In this manner both S02 emissions and stack temperature are controlled.
Flue gas enters the spray dryers at about 300°F through manifolds in the
top and passes downward, mixing with the atomized absorbent.  The particle-
laden flue gas leaves the spray dryer at about 165°F and passes down an
inclined duct to the baghouse.  Reaction of S02 and dry absorbent continues
until the flue gas passes through the cake on the fabric filters.
Essentially all of the soda ash is utilized.  The accumulated sulfur-
salt and fly ash cake on the filters is periodically dislodged by reverse
air flow and falls into hoppers from which it is pneumatically conveyed
to storage silos at a rate of about 46,000 Ib/hr (900 ft3/hr).  It is
trucked dry to the landfill empoundment.

     To facilitate cost determinations and comparisons, the process is
divided into six processing sections.  The equipment list, giving the

                                  113

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                                                      (EMERGENCY BYPASS)
                                                                               wv
                                                                                 I   I   \
                                                                                                         TO

                                                                                                       DISPOSAL

                                                                                                        POND
Figure  19.   Low-sulfur western  coal case.   Soda ash spray dryer  process.  Flow  diagram.

-------
        COAL STORAGE
                                  ROAD
                                                                                    UJ




                                                                                    cc
Figure 20.  Low-sulfur western coal case.   Soda ash spray dryer  process.  Plot plan.

-------
              TABLE 13.  LOW-SULFUR WESTERN COAL  CASE




                    SODA ASH SPRAY DRYER PROCESS




                          MATERIAL BALANCE
Stream No.

1
2
j
4
b
6
/
8
y
ID
Description
Total stream, Ib/hr

Flow rate, sf t-Vmin@60°F
Temperature, °F
Pressure, psig
Flow rate, gpm
Specific gravity
PH
Undissolved solids, %

1
Coal to boiler
489,700









2
Combustion air
to air heater
5,119,000

1,131,000
80






3
Combustion air
to boiler
A, 419, 000

975,300
535






4
Gas to
economizer
4,897,000

1,045,000
890






5
Gas to
air heater
4,897,000

1,045,000
705








I
±
i

5
h
7
8
V
ilL
Description
Total stream, Ib/hr

Flow rate, sf t~Vmin@60°F
Temperature, °F
Pressure, psig
Flow rate, gpm
Specific gravity
PH
Undissolved solids, %


Gas to
FGD system
5,597,000

1,200,000
300







Gas from
spray dryer3
5,746,000

1,246,000
170






8
Gas to stack3
5,727,000

1,252,000
175






9
Waste to pond
45,500







100

10
Soda ash
solution
to mixing tank
20.000




30
1.34



Stream No.

1

3
4
5
6
1
8
y
1U
Description


Flow rate3 sf t3/min@60°F
Temperature, °F
Pressure, psig
Flow rate, gpm
Specific gravity
PH
Undissolved solids, %

11
Makeup water
to mixing tank
81,100




160
1.0



12
Soda ash
solution
to spray dryer
101,100




190
1.05



13
Dilution water
to spray dryer
19,890


60

40
1.0



























a.  Includes air inleakage
                                 116

-------
description and cost of each equipment item by section, is shown in
Table 14.  These costs do not include the investment required for
foundations, structures, electrical components, piping, instruments and
controls, etc.  Each of these processing sections is described below.

Material Handling—
     The material handling section includes all of the equipment to
receive soda ash by rail and to maintain a supply of soda ash solution
to the solution feed tank.  It includes an insulated soda ash storage
tank with a 30-day capacity and dust collection, temperature control,
and makeup water facilities.

Feed Preparation—
     The teed preparation section includes a single train of the equipment
required to dilute the saturated soda ash solution received from storage
and pump the resulting solution to the spray dryers.  A solution feed
tank with a 4-hour capacity is provided.

Gas Handling—
     Included in this area is an inlet plenum supplying the flue gas
ducts that feed the spray dryer trains.  This area also includes the ductwork
for the hot-gas bypass, the ductwork from the air heater to the inlet
plenum, the emergency bypass around the spray dryers, the ductwork from
the spray dryers to the baghouse, and the ductwork from the baghouse to
the stack plenum.  Four ID fans are provided between the baghouse and
the stack to compensate for the pressure drop through the FGD system.

S02 Absorption—
     Five spray dryers are provided (four operating and one spare); each
is sized to handle one-fourth of the total flue gas volume.  The spray'
dryers are 48 feet in diameter and 54 feet high with individual flue gas
manifolds for each of the three rotary atomizers.

Particulate Removal—
     A single baghouse containing 28 compartments and the associated
equipment is provided.

Particulate Handling—
     Two particulate storage bins and the associated pneumatic conveyors
are included to provide a 24-hour storage capacity for the waste.

Lime Spray Dryer Process

     The lime spray dryer process for the low-sulfur western coal is
exactly the same as the lignite.   The only differences between the
processes are the equipment sizes resulting from different flow rates.
The low-sulfur western coal case burns 41% less coal than the lignite
case, resulting in a 17% reduction in flue gas volume.  The low-sulfur
western coal also produces 23% less waste than the lignite because of
the lower flow rates.

     The flow diagram and plot plan for the lime spray dryer process are
shown in Figures 21 and 22, and the material balance shown in Table 15.


                                  117

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                 TABLE 14.   LOW-SULFUR WESTERN COAL CASE

                      SODA ASH SPRAY DRYER PROCESS

                  EQUIPMENT LIST,  DESCRIPTION, AND  COST

Area

1.
1 — Materials Handling
Item No.
Car shaker 1 To]

Total
material
cost,
Description 1982 $
3 mounting with crane, 25,300

Total
labor
cost,
1982 $
4,700
2.   Tank, soda ash      2
    solution storage
3.   Heater, solution    1
    Pump, soda ash
    solution recircu-
    lating
    Pump, soda ash
    solution feed
6.  Dust collecting
    system
    Subtotal
20 hp shaker, 7-1/2 hp
crane

42-1/2 ft dia x 45 ft      127,800
high, 423,000 gal, w/
cover, carbon steel,
insulated

Coil type, 100 ft2,            900
carbon steel

Centrifugal, 30 gpm,         2,300
50 ft head, 1 hp, carbon
steel, insulated
(1 operating, 1 spare)

Centrifugal, 30 gpm, 50      2,300
ft head, 1 hp, carbon
steel, insulated
(1 operating, 1 spare)
Bag filter, polypropylene   15,500
bag, 4,000 aft^/min, auto-
matic shaker system        _
                           174,100
    feed
47,000 gal, w/cover,
four 20 in. baffles,
carbon steel

    (continued)

       118
                                        86,200
                                           300
                                         1,100
                                         1,100
                                         5,200
                                        98,600
Area 2 — Feed Preparation
Item No. Description
1. Tank, solution 1 20 ft dia x 20 ft high

Total
material
cost ,
1982 $
15,000

Total
labor
cost,
1982 $
9,900

-------
                           TABLE  14  (continued)
Area 2  (continued)
         Item
                       No.
                               Description
                          Total
                         material
                          cost,
                          1982 $
              Total
              labor
              cost,
              1982 $
 2.
 3.
    Agitator, solution  1
    storage tank
Pump, solution
feed pump
     Subtotal
                        6
80 in. dia, 20 hp,
carbon steel

Centrifugal, 48 gpm,
200 ft head, 5 hp,
carbon steel
(4 operating, 2 spare)
    23,300


    8,500




    46,800
 2,400


 3,600




15,900
Area 3—Gas Handling

Item No. Description
Total
material
cost,
1982 $
Total
labor
cost,
1982 $
 1.  Fan
     Subtotal
                            Induced draft, 382,000   2,260,800      49,700
                            aft-Vmin, 12 in. static
                            head, 875 rpm, 1,250 hp,
                            fluid drive, double width,
                            double inlet, carbon
                            steel
                            (4 operating)            	      _______

                           	2,260,800      49,700
Area 4;—SO? Absorption
         Item
                       No.
       Description
 Total
material
 cost,
 1982 $
                                                               Total
                                                               labor
                                                               cost,
                                                               1982 $
1.   Spray dryer
     Subtotal
                        48 ft  dia x 54 ft
                        high,  3 rotary atomi-
                        zers,  carbon steel
                        (4 operating spray
                        dryers and 1 spare)
                                                      5,405,000
                                                     5,405,000
                                       709,000
                                                                    709,000
                                (continued)
                                    119

-------
                           TABLE  14 (continued)

Area 5 — Particulate
Item
1. Baghouse
Removal
No. Description
1 Automatic fabric

Total
material
cost,
1982 $
8,262,000

Total
labor
cost,
1982 $
2,971,500
                             filter,  28 compart-
                             ments,  2.5 air-to-
                             cloth ratio
     Subtotal
     culate feed

 2.   Bin, particulate
     storage
     Vibrator
     Subtotal
vacuum, 250 hp

27-1/2 ft dia x 30 ft
high, 17,800 ft3, 60°
cone, w/cover, carbon
steel

Bin activator, 10 ft dia
 63,200
 28,900

335,200
                         8,262,000   2,971,500
Area 6 — Particulate Handling
Item No. Description
1. Conveyor, parti- 1 Pneumatic, pressure-
Total
material
cost,
1982 $
243,100
Total
labor
cost,
1982 $
78,200
 42,300
  4,800

125,300
Basis:  Most equipment cost estimates are based on informal vendor quotes
        and TVA information.  The only exception is the cost for the spray
        dryers which is based on information supplied by the vendors.

        These costs represent equipment costs only.  Costs for piping,
        electrical equipment, instruments, foundations, and other instal-
        lation costs are not included.  The differences in area costs
        between the equipment list and the capital summary sheets are due
        to these installation costs.
                                    120

-------

CKET
VATOR



\






LIME
STORAGE
SILO
i




I
                      BUCKET

                     ELEVATOR
                                                                  AIR-
                                                                   13
                                                                                BAGHOUSE

                                                                             vw
                                                                               1    1   1
                                                                   17



i
9
SLURRY
FEED
TANK
                                                                                                            TO

                                                                                                          LANDFILL
Figure  21.   Low-sulfur western  coal case.  Lime spray  dryer process.   Flow diagram.

-------
                                                               ZZl
 H-
era
 r1
 o
 3

 eo
 c
 1— '
 l-h

 i-i
 ft)
 i-l
 3

 O
 o
 CO
 ro
 H-
 I
 fD
 i-!
 O
 n
 o>
 en
 en
ROAD
 O
 rt
                                                                                                         DOCK
                                                            RIVER

-------
             TABLE  15.   LOW-SULFUR WESTERN COAL CASE




                     LIME SPRAY DRYER PROCESS




                         MATERIAL BALANCE


2
)
4
5
6
7
8
9
t-°
Stream No.
Description

Flow rate, sft3/min@60oF
Temoerature. °F
Pressure, psie
Flow rate, aom
Specific gravity
DH
Undissolved solids. %

1
Coal to boiler









2
Combustion air
to air heater

1,131,000
80






3
Combustion air
to boiler

975,300
535






4
Gas to
economizer

1,045,000
890






5
Gas to
air heater

1.045.000
705






strf fini NO .
Description
1
I
J
4
b
6
7
8
9
111
Total stream, Ib/hr

Flow rate, sf tJ/min@60°F
Temperature, °F
Pressure, psig
Flow rate, aom
Specific gravity
PH
Undissolved solids, 7.

6
Gas to
FGD system
5,597,000

1,200,000
300






7
Gas to
spray dryer
4,547,000

975,000
300






8
Gas from
spray dryer3
4,743,000

1,020,000
160






9
Gas to
stack3
5,715,000

1,250,000
175






10
Waste to
landfill
44,650









Stream No.

1
2
j
4
•>
6
/
«
9
10
Description
Total stream, Ib/hr

Flow rate, sft->/min@60°F
Temperature, °F
Pressure, psig
Flow rate, gpm
Specific gravity
PH
Undissolved solids, %

11
Waste to
recycle
particulate silo
55,450









12
Makeup water
to recycle
slurry tank
83,150




]<;<;




13
Recycle slurry
to spray dryer
138,600







40

14
Makeup lime
to slaker
3,661









15
Makeup water
to slaker
11,350




23




Stream No.

1
2
1
4
5
6
7
a
y
10
Description
Total stream, Ib/hr

Flow rate, sf t3/min@600F
Temperature, °F
Pressure, psig
Flow rate, gpm
Specific gravity
PH
Undissolved solids, %


Grit to
landfill
366









	 17 	 1
Lime slurry to
spray dryer
14,650







22.5

1 	 TS 	
Dilution water
to spray dryer
19,890


60

40




























Includes air inleakage.
                                 123

-------
In the low-sulfur western coal case, three of the four trains process
81% of the flue gas at about 83% SC>2 removal efficiency.   When the clean
flue gas is combined with the bypass flue gas, it produces an overall
removal efficiency of 70% and a flue gas temperature of 165°F in the
baghouse and 175°F emitted to the stack.  In the low-sulfur western coal
case 55% of the waste from the baghouse is recycled while the other 45%
is stored in silos and trucked to the landfill.

     The equipment list shown in Table 16 is divided into the same six
processing areas used in lignite case.   The area-by-area  description
for the lignite process applies to this process.

Limestone Scrubbing Process

     The same basic design used for the limestone scrubbing process in
the lignite case is used for the low-sulfur western coal  case.
The only difference is the equipment sizes due to the reduction in flow
rate in the low-sulfur western coal case.  Also, 22% of the flue gas is
bypassed to the absorber outlet producing an overall 70%  removal
efficiency.

     The flow diagram and plot plan for the low-sulfur western coal case
limestone scrubbing process are shown in Figures 23 and 24, and the
material balance is shown in Table 17.   The equipment list is shown
in Table 18.  The same division by processing section and the same
description used in the lignite  case are used for the low-sulfur
western coal case.
LOW-SULFUR EASTERN COAL CASE

     The 0.7% sulfur eastern coal, with a heating value of 10,700 Btu/lb
and 16% ash, is representative of eastern bituminous coals.  In comparison
with the western coal, it has, in addition to a higher heating value, a
lower moisture content and a lower calcium content, both of which are
important in spray dryer FGD.  It thus provides a direct comparison at
the same coal sulfur content of western and eastern coals.

Lime Spray Dryer Process

     The lime spray dryer process for the low-sulfur eastern coal is
very similar in most design aspects to the design for the low-sulfur
western coal.  The primary design difference is the omission of waste
recycle for the low-sulfur eastern coal process because the available
alkalinity in the fly ash is too low to justify the added expense.  The
other differences between the processes are equipment size differences
resulting from the different flow rates.  Using the rates for the low-
sulfur western coal process as the basis, the low-sulfur eastern coal
process burns 17% less coal but this results in only a 2% reduction in
flue gas volume.  On the other hand, the low-sulfur eastern coal process
uses 12% more lime because the absorbent is not supplemented by fly ash
alkalinity.  The low-sulfur eastern coal process also produces 24% more
waste because of the higher ash content of the coal.

                                  124


-------
                 TABLE 16.  LQW-SULFUR WESTERN COAL CASE

                          LIME SPRAY DRYER PROCESS

                    EQUIPMENT LIST, DESCRIPTION, AND COST

Area 1 — Materials Handling


Item
1. Car shaker
2. Car puller
3. Hopper,
unloading
4. Pump, pit
sump


No.
1
1
1
3


Description
Top mounted with crane,
20 hp
25 hp with 5 hp return
12 ft x 12 ft x 2 ft bottom,
20 ft deep, carbon steel
Centrifugal, 60 gpm, 70 ft
head, 5 hp, carbon steel,
Total
material
cost ,
1982 $
74,700
64,600
3,700
10,600
Total
labor
cost ,
1982 $
11,300
24,200
2,600
3,300
     Conveyor, lime     1
     unloading
     (enclosed)

     Elevator, storage  1
     silo
 7. -  Silo, lime
     storage
 9.
Vibrators

Conveyor, live
lime feed

Elevator, live
lime feed
                        1

                        1
10.   Bin,  lime feed
                       neoprene lined

                       Belt, 24 in. wide, 200 ft       14,600       1,000
                       long, 2 hp, 100 tons/hr
Continuous bucket, 16 in. x     33,600       3,400
8 in. x 11-3/4 in., 75 ft
lift, 15 hp, 100 tons/hr,
160 ft/min

40 ft dia x 50 ft straight      94,300      86,000
side, 62,800 ft3, 45° slope,
carbon steel

Bin activator, 10 ft dia        14,500       2,400

Belt, 14 in. x 100 ft long,     11,400       1,000
2 hp, 16 tons/hr, 100 ft/min

Continuous bucket, 8 in. x 5-   16,800       2,700
1/2 in. x 7-3/4 in., 35 ft
lift, 2 hp, 16 tons/hr, 150
ft/min

11 ft dia x 12 ft straight      11,600      10,700
side, 1,140 ft3, 60° slope,
w/cover, carbon steel

      (continued)

         125

-------
                           TABLE 16  (continued)

Area




11.




Area




1.

2.

3.

4.



5.

6.
1 (continued)



Item No.
Dust collecting 1
system


Subtotal
2 — Feed Preparation



Item No.
Feeder, lime 2
bin discharge
Feeder, lime 2
feed
Slaker 2

Tank, slaker 2
product


Agitator, slaker 2
product tank
Pump, slaker 3




Description
Bag filter, polypropylene
bag, 2,200 ft3/min, 7-1/2
hp (1/2 cost in feed prepa-
ration area)





Description
Vibrating, 3-1/2 hp, carbon
steel
Screw, 6 in. dia x 12 ft long
1 hp, 2 tons/hr
Ball-mill type, 25 hp slaker,
1 hp classifier, 2.0 tons/hr
6 ft dia x 8 ft high, 1,700
gal, open top, four 6 in.
baffles, agitator supports,
carbon steel, neoprene lined
2 turbines, 24 in. dia, 3 hp,
neoprene coated
Centrifugal, 40 gpm, 50 ft

Total
material
cost,
1982 $
8,000



358,400

Total
material
cost,
1982 $,
8,300

4,000

107,100

6,800



15,800

5,300

Total
labor
cost ,
1982 $
1,600



150,200

Total
labor
cost,
1982 $
600

3,300

13,500

5,500



1,900

2,400
    product tank
7.   Tank, slurry
    feed
    Agitator, slurry   1
    feed tank
head, 1-1/2 hp, carbon steel,
neoprene lined
(2 operating, 1 spare)

10 ft dia x 12 ft high, 7,100    8,700
gal, open top, four 10 in.
baffles, agitator supports,
carbon steel, neoprene lined

40 in. dia, 7-1/2 hp, neoprene  15,300
coated

     (continued)

         126
7,000
1,300

-------
                             TABLE  16  (continued)

Area

9.
2 (continued)
Item No.
Pump, slurry 12 Cenl

Total
material
cost,
Description 1982 $
trifugal, 40 gpm, 100 30,000

Total
labor
cost,
1982 $
9,300
     feed tank
10.   Dust collecting
     system
     Subtotal
ft head, 5 hp, carbon
steel, neoprene lined
(6 operating, 6 spare)

Bag filter, polypropylene
bag, 2,200 ft3/min, 7-1/2
hp (1/2 cost in material
handling area)
3,900
                               205.200
600
           45.400
Area 3 — Gas Handling
Item No. Description
1. Fan 4 Induced draft, 382,000
aft3/min, 12 in. static
head, 875 rpm, 1,250 hp,
fluid drive, double width,
double inlet
(4 operating)
Subtotal
Area 4 — S02 Absorption
Item No. Description
1. Spray dryer 4 48 ft dia x 54 ft high,
with 3 rotary atomizers,
carbon steel
(3 operating, 1 spare)
Subtotal
(continued)
127
Total
material
cost,
1982 $
2,260,800
2,260,800

Total
material
cost,
1982 $
4,324,000
4,324,000

Total
labor
cost,
1982 $
49 , 700
49.700

Total
labor
cost,
1982 $
567,200
567.200


-------
                        TABLE 16 (continued)
Area 5 — Particulate Removal


Item No.
1. Baghouse 1
Subtotal


Description
Automatic fabric filter, 28
compartments, 2.5 air-to-
cloth ratio
Area 6 — Particulate Handling and Recycle


Item No.
1. Conveyor, parti- 1
culate feed to
bin
2. Bin, particulate 2
storage
Vibrator 2
3. Silo, particulate 2


Description
Pneumatic, pressure-vacuum,
250 hp
24 ft dia x 25 ft straight
side, 11,300 ft3, 6Qo slope,
w/cover, carbon steel
Bin activator, 10 ft dia
25 ft dia x 30 ft straight
Total
material
cost ,
1982 $
8,262,000
8,262,000

Total
material
cost,
1982 $
243,100
49,800
28,900
56,500
Total
labor
cost,
1982 $
2,971,500
2,971,500

Total
labor
cost,
1982 $
78,200
49,300
4,800
52,900
recycle
Feeder, particu-
late

Feeder, recycle
slurry tank

Tank, recycle
slurry
Agitator, recycle  1
slurry tank
side, 14,700 ft3, 60° slope,
w/cover, carbon steel

Vibrating, 3-1/2 hp, carbon      8,400         800
steel

Screw, 12 in. dia x 12 ft       30,800       4,700
long, 5 hp, 50 tons/hr

21 ft dia x 23 ft high,         37,200      29,500
55,400 gal, open top, four
21 in. baffles, agitator
supports, carbon steel,
neoprene lined

84 in. dia, 30 hp, neoprene     42,100       2,700
coated

      (continued)

          128

-------
                             TABLE 16 (continued)

Area 6 (continued)
Item No.
8. Pump, recycle 12 Cenl
Total
material
cost,
Description 1982 $
trifugal, 80 gpm, 100 ft 49 inn
Total
labor
cost,
1982 $
11 .800
     slurry feed
     Subtotal
head, 10 hp, carbon steel,
neoprene lined
(6 operating, 6 spare)
                               545.900
234,700
Basis:  Most equipment cost estimates are based on informal vendor quotes and
        TVA information.   The only exception is the cost for the spray dryers
        which is based on information supplied by the vendors.

        These costs represent equipment costs only.  Costs for piping, elec-
        trical equipment, instruments, foundations, and other installation
        costs are not included.   The differences in area costs between the
        equipment list and the capital summary sheets are due to these
        installation costs.
                                     129

-------
                                            SCRUBBER ARtA
                                              SPRAY TOWER
                                            FORCED OXIDATION
               I ECONOMIZER |   ELECTROSTATIC
                         PRECIPITATOR
              COMBUSTION
                AIR








r^
''., I//.'////////////'/,



*" * *








~sl
I.D FAN
MAKE-UP
* 1 WATER
1 	 *— *



        HOPPERS. FEEDERS AND CONVEYORS
                                                                                     -a
Figure  23.   Low-sulfur western coal case.   Limestone scrubbing process.   Flow diagram.

-------
                                                        LIMESTONE PILE
             COAL STORAGE
                                                     LIMESTONE   D
                                                     PREPARATION!  I
                                                     AREA      (—I
                                                                                       g
                                                                                         PUMP
                                                                                         STATION
                                                                                          cr
                                                                                          UJ
Figure  24.  Low-sulfur  western  coal case.   Limestone scrubbing process.   Plot plan.

-------
TABLE 17.  LOW-SULFUR WESTERN COAL CASE

      LIMESTONE SCRUBBING PROCESS

           MATERIAL BALANCE
Stream No.

i
I
J
*
i
6
t
8
9
JU
Description
Total stream, Ib/hr

Flow rate, sf t J/rnin@6Q°F
Temperature , °F
Pressure, psig
Flow rate, gpm
Specific gravity
pH
Undissolved solids, %

1
Coal to
boiler
489,700









2
Combustion
air to air
heater
5,119,000

1,131,000
80






3
Combustion
air to
boiler
4,419,000

975,300
535






4
Gas to
economizer
4,897.000

1,045,000
890






5
Gas to air
heater
4,897.000

1,045,000
705










2
J
4
5
ft
/
8
y
IV
Stream No.


Total stream, Ib/hr

Flow rate, sf t -Vmin@60oF
Temperature , "F
Pressure, psig
Flow rate, gpm
Specific gravity
PH
Undissolved solids, %

6
Gas to
electrostatic

5,597,000

1,200,000
300






7
Gas to
F y
4,333,000

934,800
300






8
Gas to

5,743,000

1,265,000
175






9
Makeup
water to

191,600




383




10
Recycle
slurry to

2,305,000




4,189
1.1

15

Stream No.

1
2
3
4
5
6
7
8
y
to
Description
Total stream, Ib/hr

Flow rate, sf t^/min(d60°F
Temperature , UF
Pressure, psig
Flow rate, gpm
Specific gravity
pH
Undissolved solids, %

11
Supernate
to oxidation-
recirculation
tank
46,760




93




12
Recycle
slurry to
spray
tower
46,090,000




83,763
1.1

15

13
Slurry to
thickener
feed tank
62,690




114
1.1

15

14
Slurry to
thickener
62,690




114
1.1

15

15
Thickener
underflow
to filters
23,510 •




35
1.33

40

Stream No.

1
2
J
4
"j
b
1
H
9
10
Description
Total stream, Ib/hr

Flow rate, sf t^/miniaeO0?
Temperature, °F
Pressure, psig
Flow rate, gpm
Specific gravity
pH
Undissolved solids, %

16
Thickener
overflow to
oxidation-
recirculation
tank
39,190




78




17
Gypsum filter
cake to
disposal
11,750





2.0

80

18
Filtrate to
filtrate
surge tank
11,750




23




19
Filtrate to
oxidation-
recirculation
tank
7,568




23




20
Filtrate to
ball mills
4,182




8




              (continued)
                 132

-------
                        TABLE 17  (continued)



J^
2
\
4
•i
6
7
jj
9
±2.
Stream No.

Description

Flow rate, sf t3/min@60"F
Temperature, °F
Pressure, psig
Flow rate, gpm
Specific gravity
pH
Undissolved solids, %

'21 	
Limestone
feeder
	 ___ 	









22
Limestone
slurry to
tank




19
1.1

60

23
Limestone
slurry to
oxidation-
tank
	 10 770 	




19
1.1

60


Air to
oxidation-
tank
	 8~577 	

1,893



















 8
 9
10
 6
 7
 8
 9
10
                                133

-------
                 TABLE 18.   LOW-SULFUR WESTERN COAL CASE

                       LIMESTONE SCRUBBING PROCESS

                   EQUIPMENT LIST, DESCRIPTION, AND COST

Area 1 — Materials Handling



1.
2.

3.


Item
Mobile equipment
Hopper, reclaim

Feeder, live


No.
1
1

1


Description
Bucket tractor
7 ft x 4-1/4 ft x 2 ft deep,
carbon steel
Vibrating pan, 5 hp
Total
material
cost ,
1982 $
76,000

1,200
5,500
Total
labor
cost ,
1982 $
-

800
500
    limestone storage

4.   Pump, tunnel
    sump
5.  Conveyor, live
    limestone feed
6.  Conveyor, live
    limestone feed
    (incline)

7.  Elevator, live
    limestone feed
Vertical, 60 gpm, 70 ft head,     2,400
5 hp, carbon steel, neoprene
lined
(1 operating, 1 spare)

Belt, 30 in. wide x 100 ft       22,900
long, 2 hp, 100 tons/hr,
60 ft/min

Belt, 30 in. wide x 190          60,300
ft long, 40 hp, 35 ft lift,
100 tons/hr, 60 ft/min

Continuous bucket, 12 in. x      66,500
8 in. x 11-3/4 in., 75 hp, 90
ft lift, 100 tons/hr, 160
ft/min
  800
1,400
3,500
6,700
8.
9.

Bin, crusher
feed
Dust collecting
system
Subtotal
2 13 .ft dia x 21 ft high, w/
cover, carbon steel
1 Bag filter, polypropylene
bag, 2,200 aft3/min, 7-1/2
hp, automatic shaker system

28,900
7,800

271,500
16,000
2,600

32,500
                                (continued)
                                   134

-------
TABLE 18 (continued)

Area



1.
2.
3.
4.
5.
6.
7.
8.
9.
10.



2 — Feed Preparation


Item No.
Feeder, crusher 2
Crusher 2
Ball mill 2
Tank, mills 2
product
Agitator, mills 2
product tank
Pump, mills 2
product tank
Tank, slurry 1
feed
Agitator, slurry 1
feed tank
Pump, slurry 6
feed tank
Dust collecting 2
system
Subtotal



Total
material
cost ,
Description 1982 $
Weigh belt, 18 in. wide x 14 33,100
ft long, 2 hp, 3.0 tons/hr
Gyratory, 0 x 1-1/2 to 3/4 198,100
in., 75 hp, 3. a tons/hr
Wet, open system, 200 hp, 404,000
3.0 tons/hr
10 ft dia x 10 ft high, 5,500 9,200
gal, open top, four 10 in.
baffles, agitator supports,
carbon steel, flakeglass
lined
36 in. dia, 10 hp, neoprene 15,300
coated
Centrifugal, 14 gpm, 60 ft 5,200
head, 1 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
11 ft dia x 11 ft high, 7,000 4,900
gal, open top, four 11 in.
baffles, agitator supports,
carbon steel, flakeglass lined
44 in. dia, 15 hp, neoprene 9,800
coated
Centrifugal, 5 gpm, 60 ft 14,700
head, 1/4 hp , carbon steel,
neoprene lined
(3 operating, 3 spare)
Bag filter, polypropylene 153500
bag, 2,200 aft3/min, 7-1/2
hp, automatic shaker system
709,800
(continued)
135

Total
labor
cost,
1982 $
1,600
4,300
47,200
7,300
3,600
1,900
4,100
800
5,500
5,200

81,500



-------
                            TABLE 18 (continued)
Area 3—Partlculate Removal
         Item
No.
Description
 Total
material
 cost,
 1982 $
Total
labor
cost,
1982 $
 1.  ESP
 2.  Conveyor, fly ash  1
     to particulate
     bin

 3.  Bin, particulate   2
 4.  Vibrator
     99.8% removal efficiency     7,385,300  3,821,500
     SCA = 700

     Pneumatic, pressure-vacuum,     84,000     30,500
     125 hp
     26 ft dia x 25 ft high,
     w/cover, carbon steel

     Bin activator, 10 ft dia
                       56,500     55,400
                       28,900
              4.800
Subtotal
Area 4 — Gas Handling



Item No. Description
1. Fans 4 Induced draft, 349,000
aft3/min, 8.4 in. static
head, 890 rpm, 700 hp,
fluid drive, double width,
double inlet, Inconel
(3 operating, 1 spare)
Subtotal
7,554,700

Total
material
cost,
1982 $
2,672,900





2,672.900
3,912,200

Total
labor
cost ,
1982 $
46,100





46.100
                                  (continued)
                                     136

-------
                           TABLE 18  (continued)

Area

1.
5 — SO? Absorption
Item No.
SO? absorber 4 Sp

Total
material
cost,
Description 1982 $
ray tower, 25 ft long x 4,313 100

Total
labor
cost ,
1982 $
360,700
2.  Tank, oxidation-   4
    effluent
3.  Agitator,
    oxidation-
    effluent
    tank

4.  Pump, slurry
    recirculation
12
5.  Pumps, presatu-    8
    rator, recycle
6.  Pump, oxidation    6
    bleed
7.   Air blower,        4
    oxidation

8.   Sparger, oxida-    4
    tion
25 ft wide x 40 ft high,
1/4 in. carbon steel, neo-
prene lining; FRP spray
headers, 316 stainless steel
chevron vane entrainment
separator and nozzles
(3 operating, 1 spare)

39 ft dia x 39 ft high,
344,800 gal, open top,
four 39 in. wide baffles,
agitator supports, carbon
steel, flakeglass lined
(3 operating, 1 spare)

156 in. dia, 100 hp,
neoprene coated
(3 operating, 1 spare)


Centrifugal, 13,930 gpm,
100 ft head, 700 hp, carbon
steel, neoprene lined
(6 operating, 6 spare)

Centrifugal, 1,400 gpm,
100 ft head, 75 hp, carbon
steel, neoprene lined
(3 operating, 5 spare)

Centrifugal, 39 gpm, 60-ft
head, 1 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)

620 sft3/min, 75 hp
(3 operating, 1 spare)

19-1/2 ft dia ring
(3 operating, 1 spare)

     (continued)
                                     299,400   241,900
                                     405,800   133,200
1,190,400   106,100
                                      83,900    25,900
                                     16,200




                                     48,200


                                     49,200
              5,500




              3,100


             31,000
                                    137

-------
                            TABLE 18 (continued)

Area 5 (continued)
Item
Total
material
cost,
Description 1982 $
Total
labor
cost,
1982 $
 9.   Pump,  makeup
     water
10.  Soot blowers
     Centrifugal,  2,620 gpm,  200     27,200      3,100
     ft head,  250  hp,  carbon  steel
     (1 operating, 1 spare)

32   Air,  retractable                89,500     83,500
Subtotal
Area 6 — Solids Separation
Item No.
6,522,900

Total
material
cost,
Description 1982 $
994,000

Total
labor
cost,
1982 $
 1.  Tank, thickener
     feed
 2.  Agitator, thick-
     ener feed tank

 3.  Pump, thickener
     feed
 4.  Thickener
 1   19-1/2 ft dia x 39 ft high,     29,800     24,600
     86,100  gal, open top,
     agitator supports, four
     19 in. baffles, carbon
     steel, flakeglass lined

 1   2 turbines, 78 in. dia,         34,500      2,800
     50 hp, neoprene coated

 2   Centrifugal, 117 gpm, 60 ft      7,800      2,200
     head, 3 hp, carbon steel,
     neoprene lined
     (1 operating, 1 spare)

 1   Stainless steel tank, 26 ft     34,400     37,500'
     dia x 5 ft high; concrete
     basin, 4 ft high
 5.  Pump, thickener
     overflow
     Centrifugal, 75 gpm, 75 ft
     head, 2 hp, carbon steel
     (1 operating, 1 spare)

          (continued)
8,700
1,000
                                     138

-------
                           TABLE 18  (continued)
Area 6  (continued)
         Item
No.
Description
 Total
material
 cost,
 1982 $
Total
labor
cost,
1982 $
 6.  Tank, thickener
     overflow

 7.  Pump, filter
     feed slurry
  ].  Filter
 9.  Pump, filtrate
10.  Tank, filtrate     1
     surge

11.  Pump, filtrate     2
     surge tank
12.  Conveyor, gypsum   1
     disposal
     6 ft dia x 6 ft high, 1,230        900        600
     gal, open top, carbon steel

     Centrifugal, 35 gpm, 50 ft       5,400      1,800
     head, 1 hp, carbon steel
     (1 operating, 1 spare)

     Rotary vacuum, 11 ft dia x     134,900     34,800
     11 ft face, 15 total hp

     Centrifugal, 24 gpm, 20 ft       8,300        900
     head, 1 hp, carbon steel
     (1 operating, 1 spare)

     4 ft dia x 4 ft high, 390          400        300
     gal, carbon steel

     Centrifugal, 24 gpm, 85 ft       8,400        900
     head, 1 hp, carbon steel
     (1 operating, 1 spare)

     Belt, 14 in. wide x 50 ft       32,900      3,100
     long, 100 ft inclined, 1 hp,
     5.9 tons/hr, 40 ft/min
     Subtotal
                                                           306,400    110,500
Note:  These costs represent equipment costs only.  Costs for piping,
       electrical equipment, instruments, foundations, and other installa-
       tion costs are not included.  The differences in area costs between
       the equipment list and the capital summary sheets are due to these
       installation costs.

       Most equipment cost estimates are based on informal vendor quotes
       and TVA information.
                                     139

-------
     The flow diagram and plot plan for the lime spray dryer process are
shown in Figures 25 and 26,  and the material balance shown in Table 19.
As in the low-sulfur western coal process, three of the four trains
process 81% of the flue gas  at 83% SC>2 removal efficiency.   Thus,  when
the cleaned flue gas is combined with the bypassed flue gas, the process
produces an overall removal  efficiency of 70% and a flue gas temperature
of 160°F in the baghouse and 170 F downstream of the ID booster fan.
All waste collected in the baghouse is stored in silos, from which it is
trucked to the landfill.

     The equipment list is shown in Table 20.  The same division of
equipment into six processing areas as is used for the low-sulfur
western coal process is used.  Except that there is no waste recycle,
the area-by-area description for the low-sulfur western coal process
applies to this process.

Limestone Scrubbing Process

     The limestone scrubbing process for the low-sulfur eastern coal
case is similar in most design aspects to the low-sulfur western coal
process.  As in the lime spray dryer process, 17% less eastern coal is
burned, compared to the western coal, and slightly less flue gas is
produced.  In contrast, slightly more S02 is emitted  (a 92% S02 emission
in the flue gas instead of 85% is used because of the low alkalinity of
the fly ash) and about 30% more fly ash is produced.  Because of the
different flue gas composition, as compared with the western coal case,
only 19% of the flue gas is bypassed and a small amount of indirect
steam reheat is necessary to produce a 175°F temperature in the recom-
bined flue gas.  Other differences from the limestone scrubbing process
described for the low-sulfur western coal consist of duct and equipment
size differences.  The flow diagram and plot plan for the low-sulfur
eastern coal case limestone scrubbing process are shown in Figures  27
and 28, and the material balance is shown in Table 21.  The equipment
list is shown in Table 22.  The same division by processing section is
used as is used in the low-sulfur western coal case and the same descriptions
apply.


HIGH-SULFUR EASTERN COAL CASE

     The 3.5% sulfur eastern coal, with a heating value of 10,700 Btu/lb
and 16% ash, is representative of eastern and midwestern coals widely
used by utilities in these areas.  It differs from the low-sulfur western
coal in having a higher heating value and sulfur content and a lower
moisture and calcium content.  It provides a comparison of spray dryer
FGD technology in what may be considered  typical western and eastern
coal applications.  With the low-sulfur eastern coal  it provides a
comparison of different sulfur contents in otherwise  similar coals.

Lime Spray Dryer Process

     The lime spray dryer process  for  the high-sulfur  eastern coal  is
similar  to the designs  for  the low-sulfur western and  eastern coals.  As

                                  140

-------
                                                      (EMERGENCY  BYPASS)
  PULVERIZED
    COAL
    BUCKET
   ELEVATOR
LIME
STORAGE
SILO
i




                         BUCKET
                        ELEVATOR
             Q
D
                                                                        AIR •
                                                                                       BAGHOUSE
                                                                                  H20

1




19
14

SLURRY
FEED
TANK
                                                                                     hsi
                                                                                     1    1    1
                                                                                                          PLENUM
                                                                                                                 PARTICULATE
                                                                                                                   STORAGE
                                                                                                                    BIN
                                                                                                                     TO
                                                                                                                  LANDFILL
Figure 25.   Low-sulfur  eastern  coal  case.  Lime spray dryer process.   Flow  diagram.

-------
         COAL STORAGE
          x—x—x - x —x—x

          i   Q    i
              X
              o
          *—X—X-X—X—X
                            O
                            z
nr
i w
I Q£ Q
KOO:
J. fe <
                                               ROAD
                                       SERVICE

                                       BUILDING
                                 500MW UNIT
TURBINE

 ROOM
             BOILER

             ROOM
                                    FUTURE
                                    FUTURE
                                     ROAD
il
 (0
                                                                                             te.
Figure 26.   Low-sulfur  eastern  coal case.  Lime spray dryer process.   Plot plan.

-------
               TABLE 19.  LOW-SULFUR EASTERN COAL CASE




                       LIME.SPRAY  DRYER PROCESS




                           MATERIAL BALANCE

Description
1

\

c
_6_
H
q
iO.
Total stream. Ib/hr

Flow rate, sft3/min@60°F
Temperature, °F 	
Pressure, pslg 	
Flow rate, gpm 	
Specific gravity 	
pH
Undissolved solids , %

1
Coal to boiler
406,000








2
Combustion air
to air heater
5,089,000

1,123,000
80






Combustion air
to boiler
4,393.000

969,400
535





4
Gas to
economizer


1,005,000
890





5
Gas to
air heater
4.787.000

1,005,000
705 _






Description
1
2
t
4
•i
h
1
fl
q
10
Total stream, Ib/hr

Flow rate, sftJ/min@60°J
Temperature, °F
Pressure, psig
Flow rate, gpm
Specific gravity
pH
Undissolved solids, %


Gas to
FGD system
5,485,000

1,158,000
300







Gas to
spray dryer
4,454,000

940,000
366







Gas from
spray dryer3
4,696,000

1,023,000
166







Gas to
stacka
5,692,000

1,245,000
175







Waste to
landfill
56,250









Stream No.
Description
I
•>
\
it
S
6
7
H
9
III
Total stream, Ib/hr

Flow rate, sf t->/min@60°F
Temperature, °F
Pressure, psig
Flow rate, gpm
Specific gravity
pH
Undissolved solids, %

11
Makeup lime
to slaker
4,110









12
Makeup water
to slaker
11,400




23




13
Grit to
landfill
410









14
Makeup water to
slurry feed tank
102,600




205




15
Lime slurry
to spray dryer
117,700




228


3

Stream No.
Description
1
2
)
It
5
6
7
8
9
10
Total stream, Ib/hr

Flow rate, sft3/min@60"I
Temperature, °F
Pressure, psig
Flow rate, gpm
Specific gravity
pH
Undissolved solids, 7,

16
Dilution water
to spray dryer
103,000




205




















































a.  Includes air inleakage.
                                  143

-------
                    TABLE 20.  LOW-SULFUR EASTERN COAL CASE

                          LIME SPRAY DRYER PROCESS

                    EQUIPMENT LIST, DESCRIPTION, AND COST
Area 1—Materials Handling
          Item
                   No.
         Description
 Total
material
 cost,
 1982 $
Total
labor
cost,
1982 $
 1.   Car shaker          1

 2.   Car puller          1

 3.   Hopper, unloading   1


 4.   Pump, pit sump      3
     Conveyor, lime
     unloading (en-
     closed)

     Elevator, storage
     silo
 7.  Silo, lime storage  1
 9.
Vibrators

Conveyor, live
lime feed

Elevator, live
lime feed
10.   Bin, lime feed
                        Top mounted with crane, 20 hp   74,700    11,300

                        25 hp with 5 hp return          64,600    24,200

                        12 ft x 12 ft x 2 ft bottom,     3,700     2,600
                        20 ft deep, carbon steel

                        Centrifugal, 60 gpm, 70 ft      10,600     3,300
                        head, 5 hp, carbon steel,
                        neoprene lined

                        Belt, 24 in. wide, 200 ft       14,600     1,000
                        long, 2 hp, 100 tons/hr
                        Continuous bucket, 16 in. x     33,600     3,400
                        8 in. x 11-3/4 in., 75 ft
                        lift, 15 hp, 100 tons/hr,
                        160 ft/min
                        40 ft dia x 55 ft straight
                        side, 69,000 ft3, 45° slope,
                        carbon steel
                               100,300    90,100
Bin activator, 10 ft dia        14,500     2,400

Belt, 14 in. x 100 ft long,     11,400     1,000
2 hp, 16 tons/hr, 100 ft/min

Continuous bucket, 8 in. x      16,800     2,700
5-1/2 in. x 7-3/4 in., 35 ft
lift, 2 hp, 16 tons/hr, 150
ft/min

11 ft dia x 12 ft straight      11,600    10,700
side, 1,140 ft3, 60° slope,
w/cover, carbon steel

     (continued)

         144

-------
                           TABLE 20 (continued)

Area 1 (continued)

Item ; No.
11. Dust collecting 1
system
Subtotal

Description
Bag filter, polypropylene
bag, 2,200 ft^/min, 7-1/2
hp (1/2 cost in feed prepa-
ration area)
Total
material
cost,
1982 $
8,000
363,400
Total
labor
cost,
1982 $
1,600
154,300
Area 2 — Feed Preparation

Item No.
1. Feeder, lime 2
bin discharge
2. Feeder, lime 2
feed
3 . Slaker 2
4. Tank, slaker 2

Description
Vibrating, 3-1/2 hp, carbon
steel
Screw, 6 in. dia x 12 ft Ion;
1 hp, 1.0 tons/hr
Ball-mill type, 25 hp slaker
1 hp classifier, 2.0 tons/hr
6 ft dia x 10 ft high, -2,100
Total
material
cost,
1982 $
8,300
g, 4,000
, 107,100
8,200
Total
labor
cost,
1982 $
600
3_,300
13,500
6,700
    product
5.  Agitator, slaker
    product tank

6.  Pump,  slaker
    product tank
7.   Tank,  slurry
    feed
gal, open top, four 6 in.
baffles, agitator supports,
carbon steel, neoprene lined

2 turbines, 24 in. dia, 3 hp,
neoprene coated

Centrifugal, 40 gpm, 50 ft
head, 1-1/2 hp, carbon steel,
neoprene lined
(2 operating, 1 spare)

22 ft dia x 22 ft high,
60,300 gal, open top, four
22 in. baffles, agitator
supports, carbon steel,
neoprene lined
    (continued)

       145
15,800


 5,300
1,900


2,400
36,600    29,600

-------
                            TABLE  20  (continued)
Area 2 (continued)
Item
8. Agitator, slurry
feed tank
9 . Pump , slurry
Total
material
cost,
No. Description 1982 $
1 88 in. dia, 10 hp, neoprene 33,200
coated
12 Centrifugal, 228 gpra, 100 ft 57,900
Total
labor
cost,
1982 $
2,100
22,900
     feed tank
10.   Dust collecting
     system
     Subtotal
head, 10 hp, carbon steel,
neoprene lined
(6 operating, 6 spare)

Bag filter, polypropylene bag,
2,200 ft3/min, 7-1/2 hp, (1/2
cost in materials handling
area)
8,000    1,600
                             aft3/min, 12 in. static
                             head, 875 rpm, 1,250 hp,
                             fluid drive, double
                             width, double inlet
                             (4 operating)
                               284,400   84,600
Area 3 — Gas Handling
Item No. Description
1. Fan 4 Induced draft, 380,000
Total
material
cost,
1982 $
2,260,800
Total
labor
cost,
1982 $
49,700
     Subtotal
                              2,260,800   49.700
                                 (continued)
                                     146

-------
                           TABLE 20 (continued)
Area 4—S02 Absorption
         Item
No.
Description
 Total
material
 cost,
 1982 $
Total
labor
cost,
1982 $
 1.  Spray dryer
     Subtotal
     48 ft dia x 54 ft high,  4,324,000     567,200
     with 3 rotary atomizers,
     carbon steel
     (3 operating spray dryers,
     1 spare)                  _  	     	

    	4,324,000     567,200
Area 5—Particulate Removal
         Item
No.
Description
 Total
material
 cost,
 1982 $
Total
labor
cost,
1982 $
 1.  Baghouse
     Subtotal
     Automatic fabric filter, 8,262,000   2,971,500
     28 compartments, 2.5 air-
     to-cloth ratio	   	

                              8,262,000   2,971,500
Area 6 — Particulate Handling
Item No.
Total
material
cost,
Description 1982 $
Total
labor
cost,
1982 $
     Conveyor, parti-
     culate feed to
     bin
 1   Pneumatic, pressure-
     vacuum, 250 hp
                  243,100
               78,200
     Bin, particulate
     storage
     26 ft dia x 26 ft
     straight side, 13,800
     ft^, 60° slope, w/cover,
     carbon steel
                   53,500
               54,800
Vibrator
Subtotal
2
Bin
activator,
10
ft
dia
28
325
,900
,500
4,
137,
800
800
                                    147

-------
-P-
00
                                                   SCRUBBER AREA
                                                    SPRAY TOWEK
                                                   FORCED OXIDATION
                     | ECONOMIZER   ELECTROSTATIC
                           —'   PHECIPITATOR
            Y^  /  I  AIR HI
                    COMBUSTION
                      AIR
                               V\/\/,D«N
                                 ASH TO
                                DISPOSAL









J±k

'/,:///'/«'//////////













&
1 D FAN
^ 	 MAKE-UP






              HOPPERS. FEEDERS AND CONVEYORS
      Figure  27.   Low-sulfur eastern  coal case.   Limestone scrubbing process.   Flow  diagram.

-------
                                                          LIMESTONE PILE
               COAL STORAGE
                                                       LIMESTONE
                                                       PREPARATION PI
                                                       AREA     (	1
                                                                                           PUMP
                                                                                           STATION
Figure 28.  Low-sulfur  eastern coal case.   Limestone scrubbing process.  Plot  plan.

-------
TABLE 21.  LOW-SULFUR EASTERN COAL CASE
      LIMESTONE SCRUBBING PROCESS
           MATERIAL BALANCE
Stream No.
Description
1
2
J
4
5
6
7
H
9
1°
Total stream, Ib/hr

Flow rate, sf t J/min@60"F
Temperature , "F
Pressure, psig
Flow rate, gpm
Specific gravity
pH
Undissolved solids, X

1
Coal to
boiler
406,000









2
Combustion
air to air
heater
5,089,000

1,123,000
80






3
Combustion
air to
boiler
4,393,000

969,400
535






4
Gas to
economizer
4,787,000

1,005,000
890






5
Gas to
air heater
4,787,000

1,005,000
705








1
2
J
4
b
6
7
8
9
10
Stream No.
Description
Total stream, Ib/hr

Flow rate, sft->/min@60°I
Temperature , UF
Pressure, psig
Flow rate, gpm
Specific gravity
pH


6
Gas to
electrostatic
precipitator
5,485,000

1,159,000
300






7
Gas to
spray tower
4,454,000

940,700
300






8
Gas to
stack
5,622,000

1,225,000
175






9
Makeup
wate- to
spray tower
171,900




344




10
Recycle
slurry to
presaturator
2,206,600




4,008
1.1

15

Stream No.
Description
1
2
J
4
5
6
7
a
9
10
Total stream, Ib/hr

Flow rate, sf t J/min@60"I
Temperature , UF
Pressure, psig
Flow rate, gpm
Specific gravity
pH
Undissolved solids , %

11
Supernate
to oxidation-
recirculation
tank
46,130




92




12
Recycle
slurry to
spray
tower
44,141,000




80,220
1.1

15

13
Slurry to
thickener
feed tank
63,800




116
1.1

15

14
Slurry to
thickener
63,800




116
1.1

15

15
Thickener
underflow
to filters
23,940




36
1.33

40

Stream Mo.
Description
1
2
)
4
5
h
7
8
9
10
Total stream, Ib/hr

Flow rate, sf t3/min@60"F
Temperature, UF
Pressure, psig
Flow rate, gpm
Specific gravity
PH
Undissolved solids, %

16
Thickener
overflow to
oxidation-
re circulat ion
tank
38,350




77




17
Gypsum filter
cake to
disposal
11,970




12
2.0

80

18
Filtrate to
filtrate
surge tank
11,970




24




19
Filtrate
to oxidation-
recirculation
tank
7,784




16




20
Filtrate to
ball mills
4,186




8




               (continued)
                  150

-------
                        TABLE 21 (continued)
Stream No.
Description
1
2
j
4
S
ft
7
H
9
10
Total stream, Ib/hr

Flow rate, sftJ/minSftUor
Temperature , UF
Pressure, psig
Flow rate, gpm
Specific gravity
pH
Undissolved solids, %

21
Limestone
to weigh
feeder
6,602









22
Limestone
slurry to
mills product
tank
10,480




19
1.1

60

23
Limestone
slurry to
oxidation-
recirculation
tank
10,480




19
1.1

60

24
Air to
oxidation-
recirculation
tank
8,740

1,904
80


















 I
 2
 J
 4
~
 6
 7
 8
 9
10
 I
 2
 j
 4
 5
 6
 7
 8
 9
10
 5
 ft
 7
 H
 9
10
                                151

-------
                TABLE 22.   LOW-SULFUR EASTERN COAL CASE

                       LIMESTONE SCRUBBING PROCESS

                  EQUIPMENT LIST, DESCRIPTION,  AND COST

Area 1 — Materials Handling



1.
2.


Item
Mobile equipment
Hopper, reclaim


No.
1
1


Description
Bucket tractor
7 ft x 4-1/4 ft x 2 ft
Total
material
cost,
1982 $
76,000
1,200
Total
labor
cost,
1982 $
-
800
3.  Feeder, live
    limestone storage

4.  Pump, tunnel
    sump
5.  Conveyor, live
    limestone feed
    Conveyor, live
    limestone feed
    (incline)

    Elevator, live
    limestone feed
8.  Bin, crusher        2
    feed

9.  Dust collecting     1
    system
    Subtotal
    deep,  carbon steel

1   Vibrating pan,  5 hp
  5,500
    Vertical, 60 gpm,  70 ft      2,400
    head, 5 hp, carbon steel,
    neoprene lined
    (1 operating, 1 spare)

    Belt, 30 in. wide x 100     22,900
    ft long, 2 hp, 100 tons/hr,
    60 ft/min

    Belt, 30 in. wide x 190     60,300
    ft long, 40 hp, 35 ft lift,
    100 tons/hr, 60 ft/min

    Continuous bucket, 12 in.   66,500
    x 8 in. x 11-3/4 in., 75
    hp, 90 ft lift, 100 tons/hr,
    160 ft/min
    13 ft dia x 21 ft high,
    w/cover, carbon steel

    Bag filter, polypropylene
    bag, 2,200 aft3/min, 7-1/2
    hp, automatic shaker
    system
 28,900


  7,800




271,500
   500
               800
 1,400



 3,700



 6,700




16,000


 2,600




32,500
                               (continued)
                                    152

-------
                           TABLE 22 (continued)
Area 2—Feed Preparation
         Item
No.
Description
 Total
material
 cost,
 1982 $
Total
labor
cost,
1982 $
 1.  Feeder,
     crusher
 2.   Crusher
 3.  Ball mill
 4.  Tank, mills
     product
 5.  Agitator, mills
     product tank

 6.  Pump, mills
     product tank
 7.  Tank, slurry
     feed
 8.  Agitator, slurry    2
     feed tank

 9.  Pump, slurry        6
     feed tank
10.  Dust collecting
     system
     Subtotal
    Weigh belt, 18 in. wide     33,100
    x 14 ft long, 2 hp,
    3.0 tons/hr

    Gyratory, 0 x 1-1/2 to     198,100
    3/4 in., 75 hp, 3.0
    tons/hr

    Wet, open system, 190      410,400
    hp, 3.0 tons/hr

    10 ft dia x 10 ft high,      9,200
    5,500 gal, open top,
    four 10 in. baffles,
    agitator supports,
    carbon steel, flakeglass
    lined

    36 in. dia, 10 hp,          15,300
    neoprene coated

    Centrifugal, 14 gpm, 60      5,200
    ft head, 1 hp, carbon
    steel, neoprene lined
    (1 operating, 1 spare)

    11 ft dia x 11 ft high,      5,100
    7,500 gal, open top,
    four 11 in. baffles,
    agitator supports, carbon
    steel, flakeglass lined

    44 in. dia, 15 hp,          10,100
    neoprene coated

    Centrifugal, 4 gpm, 60      14,800
    ft head, 1/4 hp, carbon
    steel, neoprene lined
    (3 operating, 3 spare)

    Bag filter, polypropylene
    bag, 2,200 aft3/min, 7-1/2
    hp, automatic shaker
    system
                      15,500
                               716,800
                                (continued)
                                     153
                                  1,600



                                  4,300



                                 47,800


                                  7,300
                                  3,700


                                  1,800
                                  4,200
                                    800
                                  5,500
               5,200
                                 82,200

-------
                          TABLE 22 (continued)

Area

3 — Particulate Removal
Item No.

Total
material
cost,
Description 1982 $

Total
labor
cost,
1982 $
1.   ESP
4   99.8% removal effi-
    ciency
    SCA = 700
7,385,300  3,821,500
2.   Conveyor, fly
    ash to particu-
    late bin
1   Pneumatic, pressure-
    vacuum, 125 hp
   84,000     30,500
3.   Bin,
    particulate

4.   Vibrator
    Subtotal
2   28 ft dia x 28 ft high,     66,000     64,800
    w/cover, carbon steel
2   Bin activator, 10 ft
    dia
   28,900
 4,800
                             7,564,700  3,921,600
Area 4 — Gas Handling
Total
material
cost,
Item No. Description 1982 $
Total
labor
cost,
1982 $
1.  Fans
    Subtotal
    Induced draft, 347,000
    aft-Vmin, 8.5 in.
    static head, 890 rpm,
    700 hp, fluid drive,
    double width, double
    inlet, Inconel
    (3 operating,   spare)
2,701,400
46,500
                             2,701.400     46,500
                               (continued)

                                    154

-------
                           TABLE 22  (continued)

Area

1.
5 — S02 Absorption
Item No.
SC>2 absorber 4 Sp

Total
material
cost,
Description 1982 $
ray tower, 24 ft long x 4,303.900

Total
labor
cost ,
1982 $
360,100
2.  Tank,
    oxidation-
    effluent
    Agitator,
    oxidation-
    effluent
    tank

    Pump, slurry
    recirculation
    Pumps, presatu-
    rator recycle
    Pump, oxidation
    bleed
7.  Air blower,
    oxidation

8.  Sparger,
    oxidation
     24 ft wide x 40 ft high,
     1/4 in. carbon steel, neo-
     prene lining; FRP spray
     headers, 316 stainless
     steel chevron vane entrain-
     ment separator and nozzles
     (3 operating, 1 spare)

     39 ft dia x 39 ft high,
     343,900 gal, open top, four
     31-1/2 in. wide baffles,
     agitator supports, carbon
     steel, flakeglass lined
     (3 operating, 1 spare)

     156 in. dia, 100 hp,
     neoprene coated
     (3 operating, 1 spare)
12   Centrifugal, 13,360 gpm,
     100 ft head, 700 hp, carbon
     steel, neoprene lined
     (6 operating, 6 spare)

 8   Centrifugal, 1,340 gpm,
     100 ft head, 75 hp, carbon
     steel, neoprene lined
     (3 operating, 5 spare)

 6   Centrifugal, 41 gpm, 60 ft
     head,  1 hp, carbon steel,
     neoprene lined
     (3 operating, 3 spare)

 4    660 sft3/min, 100 hp
     (3 operating, 1 spare)

 4   19-1/2 ft dia ring
     (3 operating, 1 spare)

         (continued)
  298,800    241,500
  405,100    133,000
1,188,800    106,000
   83,800




   16,200




   50,000


   49,200
25,800




 5,500




 3,100


31,000
                                   155

-------
                         TABLE 22  (continued)

Area

9.
10.
Area

1.
Area

1.
5 (continued)
Item No. Description
Pump, makeup 2 Centrifugal, 2,500 gpm,
water 200 ft head, 250 hp ,
carbon steel
(1 operating, 1 spare)
Soot blower 48 Air, fixed
Subtotal
6 — Stack Gas Reheat
Item No. Description
Reheater 4 Inline steam type,
628 ft2, Inconel 625
Subtotal
7 — Solids Separation
Item No. Description
Tank, thickener 1 19-1/2 ft dia x 39 ft

Total
material
cost,
1982 $
27,200
235,900
6,658,900

Total
material
cost ,
1982 $
859,300
859,300

Total
material
cost,
1982 $
29,700

Total
labor
cost,
1982 $
3,100
146,000
1,055,100

Total
labor
cost,
1982 $
36,700
36,700

Total
labor
cost,
1982 $
24,600
    feed
2.   Agitator, thick-
    ener feed tank

3.   Pump, thickener
    feed
high, 85,900 gal, open
top, agitator supports,
four 19 in. baffles,
carbon steel, flakeglass
lined

2 turbines, 78 in. dia,
50 hp, neoprene coated

Centrifugal, 123 gpm,
60 ft head, 3 hp, carbon
steel, neoprene lined
(1 operating, 1 spare)

   (continued)

        156
34,400


 7,800
2,800


2,200

-------
                          TABLE 22  (continued)
Area

4.
7 (continued)
Item
Thickener

Total
material
cost,
No. Description 1982 $
1 Stainless steel tank, 35,700

Total
labor
cost,
1982 $
38,800
 5.   Pump,  thickener
     overflow pumps
 6.   Tank,  thickener
     overflow
 7.   Pump,  filter
     feed
 8.   Filter
 9.  Pump, filtrate
10.  Tank, filtrate
     surge

11.  Pump, filtrate
     surge tank
12.  Conveyor, gypsum
     disposal
     Subtotal
    27 ft dia x 5 ft high;
    concrete basin,  4 ft
    high

2   Centrifugal, 77  gpm,         8,700
    75 ft head, 2 hp, carbon
    steel, neoprene  lined
    (1 operating, 1  spare)

1   7 ft dia x 5 ft  high,          900
    1,340 gal, open  top,
    carbon steel

2   Centrifugal, 38  gpm,         5,400
    50 ft head, 1 hp,
    carbon steel
    (1 operating, 1  spare)

2   Rotary vacuum, 11 ft dia   138,800
    x 11 ft face, 15 total hp
    (1 operating, 1 spare)

2   Centrifugal, 24 gpm, 20      8,300
    ft head, 1 hp, carbon
    steel, neoprene lined
    (1 operating, 1 spare)

1   4 ft dia x 4 ft high,          400
    395 gal, carbon steel

2   Centrifugal, 24 gpm, 85      8,400
    ft head, 1 hp, carbon steel
    (1 operating, 1 spare)

1   Belt, 14 in. wide x 50 ft   32,900
    long, 100 ft inclined, 1.5
    hp; 6 tons/hr, 40 ft/min   ________
 1,000
                                                                       600
 1,800
35,300
                                                                       900
                                                                       300
   900
 3,100
                               311,400    112,300
Note:  These costs represent equipment costs only.  Costs for piping,
       electrical equipment, instruments, foundations, and other installa-
       tion costs are not included.  The differences in area costs between
       the equipment list and the capital summary sheets are due to these
       installation costs.

       Most equipment cost estimates are based on informal vendor quotes
       and TVA information,
                                    157

-------
in the low-sulfur eastern coal process, no waste recycle is used.  The
major difference between this process and the low-sulfur coal processes
is that about 89% SC>2 reduction is required, greatly reducing the amount
of flue gas bypass that can be used.  Bypass (excluding the emergency
bypass) in this case is reduced to 4%.  For comparison, the flue gas
volume and composition for the high-sulfur eastern coal process is very
similar, with the exception of sulfur content, to the low-sulfur eastern
coal process.  The design differences between the processes are the
result of the higher 862 removal requirements.  In this case, five spray
dryer trains are used (four operating and one spare) to handle the
additional flue gas volume passed through the spray dryers.

     The flow diagram and plot plan are shown in Figures 29 and 30, and
the material balance is shown in Table 23.  Four of the five trains
process 96% of the flue gas at an 89% S02 removal efficiency.  The
recombined flue gas passes through the baghouse at 160°F and is at 170°F
downstream of the ID booster fan.  All waste is stored in silos, from
which it is trucked to the landfill.  The equipment list is shown in
Table 24.  The same division of equipment by processing area is used as
was used for the other coal cases.  The same description of equipment
and function also apply.

Limestone Scrubbing Process

     The same basic design that was used in the low-sulfur cases is used
for the high-sulfur eastern coal limestone scrubbing process.  Since
about 89% SC>2 removal is necessary, however, no flue gas bypass is used,
and five absorber trains (four operating and one spare) are used to
handle the additional flue gas scrubbed.  Since all of the flue gas
emerges from the absorbers at 127°F, full indirect steam reheat to 170°F
is required.   The flow diagram and plot plan are shown in Figures 31 and
32, and the material balance is shown in Table 25.  With the exceptions
discussed above, the process descriptions for the low-sulfur limestone
scrubbing processes apply.  The equipment list is shown in Table 26.
The area-by-area discussion for the low-sulfur processes also apply to
this process.
                                 158

-------
                                            (EMERGENCY BYPASS)
Figure 29.   High-sulfur eastern  coal case.  Lime spray dryer process.   Flow diagram.

-------
                                                               091
0<5
 C
 i-J
 CD
 H-

 r
 en
 h->
 Ml
n>
$
CO
(f
fD
n
o
03
o
CD
CO
(0
o.
i-i
i-i
O
O
m
CO
CO
                                                     ROAD
                    I                11                l
               §
               o
                    I	11	I
ROAD
                                                                                I  I I  lD-
O
rt
                                                                                                         DOCK
                                                            RIVER

-------
TABLE 23.  HIGH-SULFUR EASTERN COAL CASE




        LIME SPRAY DRYER PROCESS




            MATERIAL BALANCE
Stream No.
Description
1
2
j
4
5
6
7
8
9
1°
Total stream, Ib/hr

Flow rate, sf t3/min@60°F
-Temperature. °F
Pressure, psig
Flow rate, epm
Specific gravity
pH
Undissolved solids, %

1
Coal to
boiler
406,000









2
Combustion
air to air
heater
5,021,200

1,108,000
80






3
Combustion
air to
boiler
4,334,800

956,600
535






4
Gas to
economizer
4,776,600

1,011,000
890






5
Gas to
air heater
4,538,000

960,300
705






Stream No.

!
2
j
4
b
b
7
8
9
|P
Description
Total stream, Ib/hr

Flow rate, sft-Vmin@60°I
Temnerature. °F
Pressure, nsie
Flow rateT gpm
Soecific yravitv
OH
Undissolved solids. %

6
Gas to
FGD system
5,224.000

1,106,000
300






7
Gas to
spray dryer
5.224 000

1,106,000
300






8
Gas to
baghouse
s 723 nno

1,231,000
170






9
Gas to
stack
5.648.000

1.237.000
180






10
Waste to
landfill
110.100









Stream No.

1
2
]
4
5
h
/
H
9
10
Description
Total stream, Ib/hr

Flow rate, sft-Vmin@60°P
Temperature, "F
Pressure, psig
Flow rate, gpm
Specific gravity
pH
Undissolved solids, %

11
Waste to
recycle
particulate
silo
31,200









12
Makeup water
to recycle
slurry tank
46,800


60

94




13
Recycle slurry
to spray dryer
78,000







40

14
Makeup lime
to slaker
40,900









15
Makeup water
to slaker
126.700




253






I
2
i
4
5
h
1
8
y
10
Description
Total stream, Ib/hr

Flow rate, sf t3/min@60°F
Temperature , °F
Pressure, psig
Flow rate, gpm
Specific gravity
PH
Undissolved solids T %

	 is 	
Grit to
landfill
4,100









	 _ 	
Lime slurry to
spray dryer
163,500







22.5

18
Dilution water
to spray dryer
30,590


60

60
1.0



























                  161

-------
             TABLE  24-  HIGH-SULFUR EASTERN COAL CASE




                    LIME  SPRAY DRYER PROCESS




               EQUIPMENT LIST, DESCRIPTION, AND COST

Area

1.
2.
3.
4.
5.
6.
7.
8.
9.

10.
1 — Materials Handling
Item
Car shaker
Car puller
Hopper,
unloading
Pump, pit sump
Conveyor, lime
unloading
(enclosed)
Elevator, lime
storage
Conveyor, lime
storage (enclosed,
silo mounted)
Tripper
Silo, lime
storage
Vibrators
Conveyor , live
No.
1
1
1
3
1
1
1
1
3
3
1
Total
material
cost,
Description 1982 $
Top mounted with crane,
20 hp
25 hp with 5 hp return
12 ft x 12 ft x 2 ft bottom,
20 ft deep, carbon steel
Centrifugal, 60 gpm, 70 ft
head, 5 hp, carbon steel,
neoprene lined
Belt, 24 in. wide, 200 ft
long, 2 hp, 100 tons/hr,
200 ft/min
Continuous bucket, 16 in. x 8
in. x 11-3/4 in., 112 ft lift,
25 hp, 100 tons/hr, 160 ft/min
Belt, 24 in. wide x 170 ft
long, 3 hp, 100 tons/hr,
200 ft/min
5 hp, 30 ft/min
50 ft dia x 90 ft straight
side, 178,500 ft3, 45° slope,
concrete
Bin activator, 10 ft dia
Belt, 18 in. x 215 ft long,
74,700
64,600
3,700
10,600
14,600
42,900
33,300
33,000
449,700
43,400
28,500
Total
labor
cost,
1982 $
11,300
24,200
2,600
3,300
1,000
5,300
9,600
9,300
1,225,500
7,100
2,200
lime feed
2 hp, 40 tons/hr, 150 ft/min




    (continued)
                               162

-------
TABLE 24 (continued)
Area



11.



12.


13.



Area




1.

2.

3.

4.




5.



1 (continued)


Item No.
Elevator , live 3
lime feed


Bin, feed 3


Dust collecting 1
system


Subtotal
2 — Feed Preparation



Item No.
Feeder , lime 3

Conveyor , lime 3
feed
Slaker 3

Tank, s laker 3
product



Agitator, slaker 3
product tank



Total
material
cost,
Description 1982 $
Continuous, bucket 14 in. 54,900
x 8 in. x 11-3/4 in. , 70
ft lift, 5 hp, 40 tons/hr,
160 ft/min
20 ft dia x 30 ft straight 62,200
side, 8,900 ft3, 60° slope,
w/cover, carbon steel
Bag filter, polypropylene 8,000
bag, 2,200 ft3/min, 7-1/2
hp, (1/2 cost in feed prepa-
ration area)
924,100

Total
material
cost,
Description 1982 $
Vibrating, 3-1/2 hp, carbon 12,500
steel
Screw, 9 in. dia x 12 ft 7,500
long, 2 hp, 10.2 tons/hr
Ball-mill type, 125 hp slaker, 600,100
3 hp classifier, 11.0 tons/hr
8 ft dia x 10 ft high, 56,000
3,500 gal, open top, four
8 in. baffles, agitator
supports, carbon steel,
neoprene lined
32 in. dia, 3 hp, neoprene 23,700
coated
(continued)
163

Total
labor
cost,
1982 $
8,100



56,100


1,600


1,366,600

Total
labor
cost,
1982 $
900

6,200

30,100

48,000




2,800




-------
                            TABLE 24 (continued)

Area 2

(continued)
Item No.

Total
material
cost,
Description 1982 $

Total
labor
cost,
1982 $
 6.   Pump,  slaker
     product tank
 7.   Tank,  slurry
     feed
 8.   Agitator,  slurry
     feed tank

 9.   Pump,  slurry
     feed tank
10.   Dust collecting
     system
     Subtotal
15
     Centrifugal, 211 gpm,
     100 ft head, 10 hp,  carbon
     steel, neoprene lined
     (2 operating, 1 spare)

     27-1/2 ft  dia x 30 ft high,
     131,000 gal, open top,
     four 27-1/2 in. baffles,
     agitator supports, carbon
     steel, neoprene lined

     108 in. dia, 40 hp,  neoprene
     coated
Centrifugal, 211 gpm,
ft head, 10 hp, carbon
steel, neoprene lined
(8 operating, 7 spare)
     Bag filter,  polypropylene
     bag, 2,200 ft/min,  7-1/2
     hp (1/2 cost in material
     handling area)
                               14,500
                               51,700
                               73,200
74,800
                                8,000
                             aft3/min, 12 in.  static
                             head,  700 rpm,  1,250 hp,
                             fluid  drive, double width,
                             double inlet
Subtotal
                                 2,260,800
            5,800
           40,700
 3,600


30,300
            1,600
                                                           922,000    170,000
Area 3 — Gas Handling
Item No. Description
1. Fan 4 Induced draft, 368,700
Total
material
cost,
1982 $
2,260,800
Total
labor
cost,
1982 $
49,700
                                          49.700
                                 (continued)
                                    164

-------
                            TABLE 24 (continued)
Area 4—S02 Absorption
          Item
No.
Description
 Total
material
 cost,
 1982 $
Total
labor
cost,
1982 $
 1.  Spray dryer
     Subtotal
     48 ft dia x 54 ft high,
     with 4 rotary atomizers,
     carbon steel
     (4 operating, 1 spare)
                    5,405,000   709,000
                                  5,405,000   709,000
Area 5—Particulate Removal
          Item
No.
Description
 Total
material
 cost,
 1982 $
Total
labor
cost,
1982 $
 1.  Baghouse
     Subtotal
     Automatic fabric filter
     26 compartments, 2.5 air-
     to-cloth ratio
                    8,032,600 2,921,100
                                  8,032.600 2,921,100
Area 6—Particulate Handling
          Item
No.
Description
 Total
material
 cost,
 1982 $
Total
labor
cost,
1982 $
     Conveyor, parti-
     culate feed to
     bin

     Bin, particulate
     storage
     Vibrator
 1   Pneumatic, pressure-vacuum,
     350 hp


 2   29 ft dia x 37 ft straight
     side, 24,400 ft3, 60° slope,
     w/cover, carbon steel

 2   Bin activator, 10 ft dia
                      323,600    96,300
                       79,800    75,500
                       28,900     4,800
                                 (continued)
                                    165

-------
                            TABLE 24 (continued)

Area 6 (continued)
Item No. Description
3. Silo, particu- 2 20 ft dia x 24 ft straigh
Total
material
cost,
1982 $
t 36,100
Total
labor
cost ,
1982 $
33,900
 4.
 5.
     late recycle
Feeder, parti-
culate recycle

Feeder, recycle
slurry tank

Tank, recycle
slurry
 7.
Agitator, recycle   1
slurry tank
     Pump, recycle
     slurry feed
     Subtotal
                   12
side, 7,600 ft3, 60° slope,
w/cover, carbon steel

Vibrating, 3-1/2 hp, carbon
steel

Screw, 12 in. dia x 12 ft
long, 5 hp, 50 tons/hr

19 ft dia x 22 ft high,
46,700 gal, open top, four
19 in. baffles, agitator
supports, carbon steel,
neoprene lined

76 in. dia, 20 hp, neoprene
coated

Centrifugal, 41 gpm, 100 ft
head, 5 hp, carbon steel,
neoprene lined
8,400
30,800
26,700
800
4,700
21,400
26,300     2,700


30,000     9,000
                                                       590,600   249,100
Note:  These costs represent equipment costs only.   Costs for piping, elec-
       trical, instruments, foundations, and other  installation costs are not
       included.  The differences in area costs between the equipment list
       and the capital summary sheets are due to these installation costs.

       Most equipment cost estimates are based on informal vendor quotes and
       internal TVA information.  The only exceptions are the costs for the
       spray dryers and the baghouse which were provided by the vendors.
                                     166


-------
                                                     (EMERGENCY BYPASS)
                                                                                                  r-Q—
                                                                                                   FILTRATE
                                                                                                   RECEIVER
                                                                                                            . TO SYPSUM
                                                                                                            FIELD DISPOSAL
           HOPPERS, FEEDERS, AND CONVEYORS
Figure 31.   High-sulfur  eastern coal  case.   Limestone scrubbing process.   Flow  diagram.

-------
                                                                         LIMESTONE PILE
oo
                            COAL STORAGE
                                                                      LIMESTONE
                                                                      PREPARATION
                                                                      AREA
o
O
                                                                                                          PUMP
                                                                                                          STATION
      Figure  32.   High-sulfur eastern coal  case.  Limestone  scrubbing process.  Plot plan.

-------
TABLE 25.  HIGH-SULFUR EASTERN COAL CASE




       LIMESTONE SCRUBBING PROCESS




            MATERIAL BALANCE
Stream No.
Description
1
'1.
\
4
•i
f>
7
K
9
10
Total stream, Ib/hr

Flow rate, sftJ/min@60°F
Temperature . "F
Pressure, psig
Flow rate, gpm
Specific gravity
pH
Undissolved solids, %

1
Coal to
boiler
406,000









2
Combustion
air to air
heater
5,021,200

1,108,000
80






3
Combustion
air to
boiler
4,334,800

956,600
535






4
Gas to
economizer
4,776,600

1,011,000
890






5
Gas to
air heater
4,776,600

1,011,000
705






Stream Mo.
Description
1
2
J
4
b
b
7
8
9
Iff
Total stream, Ib/hr

Flow rate, sft^/min@60"F
Temperature , "F
Pressure, psig
Flow rate, gpm
Specific gravity
PH
Undissolved solids, %

6
Gas to
electrostatic
precipitator
5,463,000

1,156,000
300






7
Gas to
spray tower
5,414,000

1,156,000
300






8
Gas to
stack
5,639,000

1,236,000
175






9
Makeup
water to
spray tower
276,500




553




10
Slurry to
recirculation
tank
71,693,600




130,246


15

Stream No.

1
2
•1
4
5
6
7
8
9
10
Description
Total stream, Ib/hr

Flow rate, sft3/min@60"F
Temperature, °F
Pressure, psig
Flow rate, Epm
Specific gravity
pH
Undissolved solids, %

11
Recycle
slurry to
spray tower
68,720,000




124,800


15

12
Recycle
s lurry to
presaturator
3,054,000




5,547


15

13
Slurry to
thickener
feed tank
481,200




874


15

14
Thickener
underflow to
filter feed
tank
180,400




272




15
Thickener
overflow to
oxidation tank
288,300




577




Stream No.


2
i
4
5
6
7
H
9
1U
Description
Total stream, Ib/hr

Flow rate, sf t J/min@60°F
Temperature , °F
Pressure, psig
Flow rate, jjpm
Specific gravity
pH
Undissolved solids , %

16
Gypsum filter
cake to
disposal
90,220




92


80

17
Filtrate to
oxidation
tank
90,220




181

•>


18
Total supernate
return
378,500




757




19
Supernate
to oxidation
tank
348,300




697




20
Supernate to
ball mills
30,160




60




               (continued)



                  169

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TABLE 25 (continued)
Stream No.
Description
J
2
j
4
5
ft
7
8
9
10
Total stream, Ib/hr

Flow rate. s£t3/min@60°F
Temperature. °F
Pressure, psig
Flow rate, apm
Specific firavit-V
PH
Undissolved solids, %

21
Limestone
to weigh
feeder
48,240









22
Limestone
slurry to
mills product
tank
80,390




101
1.6

60

23
Limestone
slurry to
recirculation
tank
80,390




101
1.6

60

24..
Air to
oxidation
tank
59,950

13,060
60






25
Steam to
reheater
96,730


A 70






         170

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                  TABLE 26.   HIGH-SULFUR EASTERN COAL CASE

                         LIMESTONE SCRUBBING PROCESS

                    EQUIPMENT LIST, DESCRIPTION, AND COST

Area

1.
2.
3.
1 — Materials
Item
Handling
No.
Car shaker 1
Car puller 1
Hopper, limestone 1

Description
Top mounted with crane
25 hp puller, 5 hp return
16 ft dia x 10 ft straight

Total
material
cost,
1982 $
71,900
63,100
15,500

Total
labor
cost,
1982 $
13,000
19,600
5,900
     unloading
 4.  Feeder, limestone  1
     unloading
 5.   Conveyor,  lime-
     stone unloading
     Conveyor, lime-
     stone stocking
     (incline)

     Dust collecting
     system
 8.  Pump, unloading
     pit sump

 9.  Conveyor, lime-
     stone stocking
10.   Tripper            1

11.   Mobile equipment   1

12.   Hopper, reclaim    2
13.   Feeder,  live       2
     limestone storage
side height, includes 6 in.
square grating

Vibrating pan, 42 in. wide       5,500        500
x 60 in. long, 3 hp, 250
tons/hr

Belt, 36 in. wide x 20 ft       11,400      1,400
long, 5 hp, 250 tons/hr,
130 ft/min

Belt, 36 in. wide x 310 ft      85,300      4,800
long, 50 hp, 250 tons/hr
Bag filter, polypropylene       11,200      5,200
bag, 2,200 aft3/min, 7-1/2
hp, automatic shaker system,
w/dust hood

Centrifugal, 60 gpm, 70 ft       2,400        800
head, 5 hp, neoprene lined

Belt, 36 in. wide x 200 ft      73,100      3,900
long, 5 hp, 250 tons/hr, 130
ft/min

1 hp, 30 ft/min                 27,200      9,100

Scraper tractor                141,900

7 ft x 4-1/4 ft x 2 ft           2,400      1,600
deep, carbon steel

Vibrating pan, 3 hp             10,900      1,000
                                  (continued)
                                     171

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                             TABLE 26 (continued)

Area 1

14. Pi
(continued)
Item
imp , tunnel

Total
material
cost,
No. Description 1982 $
1 Vertical, 60 gpm, 70 ft head, 2,400

Total
labor
cost,
1982 $
800
     sump
15.   Conveyor, live    1
     limestone feed
16.   Conveyor, live
     limestone feed
     (incline)

17.   Elevator, live
     limestone feed
5 hp, carbon steel, neoprene
lined (1 operating, 1 spare)

Belt, 30 in. wide x 200 ft      40,900
long, 5 hp, 100 tons/hr,
60 ft/min

Belt, 30 in. wide x 190 ft      60,300
long, 40 hp, 35 ft lift,
100 tons/hr, 60 ft/min

Continuous bucket, 12 in. x     57,800
8 in. x 11-3/4 in., 75 hp,
90 ft lift, 100 tons/hr, 160
ft/min
2,900
3,700
6,700
18.
19.
20.
21.
Area
1.
2.
3.
Bin, crusher
feed
Conveyor , feed
belt
Tripper
Dust collecting
system
Subtotal
3
1
1
1
13 ft dia x 21 ft high, w/
cover, carbon steel
Belt, 30 in. wide x 60 ft
long, 7.5 hp, 100 tons/hr,
60 ft/min
1 hp, 30 ft/min
Bag filter, polypropylene
bag, 2,200 aft3/min, 7-1/2
hp, automatic shaker system
43,300
20,500
27,200
7,800
782,000
24,000
1,400
9,100
2,600
118,000
2 — Feed Preparation
Feeder, crusher
Crusher
Ball mill
3
3
3
Weigh belt, 18 in. wide x 14
ft long, 2 hp, 13.0 tons/hr
Gyratory, 0 x 1-1/2 to 3/4
in., 75 hp, 13.0 tons/hr
Wet, open system, 700 hp,
49,600
297,100
1,678,000
2,300
6,500
119,300
                           13.0 tons/hr
                                  (continued)
                                     172

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                             TABLE 26 (continued)
Area 2 (continued)
          Item
                     No.
        Description
 Total      Total
material    labor
 cost,      cost,
 1982 $     1982 $
 4.  Tank, mills
     product
                          10 ft dia x 10 ft high,          13,700
                          5,500 gal, open top, four  10  in.
                          baffles, agitator supports,
                          carbon steel, flakeglass
                          lined
                                            11,000
 5.  Agitator, mills   3
     product'tank

 6.  Pump, mills       3
     product tank
 7.  Tank, slurry
     feed
 8.  Agitator, slurry  1
     feed tank
9.  Pump, slurry
    feed tank
                       8
10.  Dust collecting   3
     system, ball
     mill

     Subtotal
36 in. dia, 10 hp, neoprene
coated

Centrifugal, 51 gpm, 60 ft
head, 2 hp, carbon steel,
neoprene lined
(2 operating, 1 spare)

20-3/4 ft dia x 20-3/4 ft
high, 52,430 gal, open top,
four 20-3/4 in. baffles,
agitator supports, carbon
steel, flakeglass lined

83 in. dia, 50 hp, neoprene
coated

Centrifugal, 25 gpm, 60 ft
head, 1 hp, carbon steel,
neoprene lined
(4 operating, 4 spare)

Bag filter, polypropylene
bag, 2,200 aft3/min, 7-1/2
hp, automatic shaker system
                                                           22,900


                                                            8,500
  40,100


  21,500
                                                           23,300
              5,500


              2,700
                                                           18,900     15,600
3,300


7,300
              7,800
                                                        2,174,200    181,300
Area 3—Particulate Removal
 1.  ESP
                      4   99.8% removal efficiency
                          SCA = 550
                              6,267,100  3,133,000
 2.  Conveyor, fly     1   Pneumatic, pressure, vacuum,     84,000     30,500
     ash  particulate      125 hp
     bin
 3.  Bin, particulate  2   26 ft dia x 25 ft high,          66,000     64,800
                           w/cover, carbon steel

                                  (continued)
                                     173

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                             TABLE 26 (continued)

Area 3

(continued)
Item No. Description

Total
material
cost,
1982 $

Total
labor
cost,
1982 $
 4.  Vibrator

     Subtotal

Area 4—Gas Handling

 1.  Fans
Bin activator, 10 ft dia
   28,900
 4,800
                             6,446.000  3,233,100
Induced draft, 368,700
aft3/min, 9-1/2 in. static
head, 890 rpm, 800 hp,
fluid drive, double width,
double inlet, Inconel
(4 operating, 1 spare)
3,651,600
     Subtotal
                             3,651,600
61,800
              61,800
Area 5—S02 Absorption
 1.  S02 absorber
 2.  Tank, oxidation-  5
     recirculation
     Agitator, oxida-  5
     tion-recircula-
     tion tank

     Tank, effluent    5
     hold
Spray tower, 28 ft long x
28 ft wide x 40 ft high,
1/4 in. carbon steel,
neoprene lining; FRP spray
headers, 316 stainless
steel chevron vane entrain-
tnent separator and nozzles
(4 operating, 1 spare)

27-1/2 ft dia x 39 ft
high, 171,600 gal, open top,
four 27-1/2 in. wide baffles,
agitator supports, carbon
steel, flakeglass lined
(4 operating, 1 spare)

110 in. dia, 75 hp
neoprene coated
(4 operating, 1 spare)

39 ft dia x 39 ft high,
343,200 gal, open top,
four 39 in. wide baffles,
agitator support, carbon
steel

       (continued)
         174
5,429,500    449,500
  218,500    180,600
  309,600    127,000
  373,000    301,500

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                           TABLE 26  (continued)
Area

5.
5 (continued)
Item No.
Agitator, 5

Description
156 in.dia, 100 hp,

Total
material
cost,
1982 $
505,600

Total
labor
cost,
1982 $
207,500
6.
7.
effluent hold
tank

Pump, slurry
recirculation
15
Pumps, presatu- 10
rator, recycle
    Pump,  oxida-
    tion bleed
                          neoprene coated
Centrifugal, 15,600 gpm,    1,581,400     139,400
100 ft head, 800 hp, carbon
steel, neoprene lined
(8 operating, 7 spare)

Centrifugal, 1,400 gpm,       104,700      32,300
100 ft head, 75 hp, carbon
steel, neoprene lined
(4 operating, 6 spare)

Centrifugal, 221 gpm, 60       34,300      11,500
ft head, 7-1/2 hp, carbon
steel, neoprene lined
(4 operating, 4 spare)
9.
10.
11.
12.
Area
Blower, oxida- 6
tion air
Sparger, oxida- 5
tion air
Pump , makeup 2
water
Soot blowers 60
Subtotal
6 — Stack Gas Reheat
3,300 sft3/min, 400 hp
(4 operating, 2 spare)
19-1/2 ft dia ring
(4 operating, 1 spare)
Centrifugal, 3,470 gpm,
200 ft head, 300 hp, carbon
steel
(1 operating, 1 spare)
Air, retractable

208,400
95,200
33,200
294,900
9,188,300

4,700
41,600
3,700
182,600
1,681,900

1.  Reheater
                      Inline steam type, 2,776
                      ft2, 1/2 of tubes made of
                      Inconel 625 and 1/2 made
                      of Corten
    Subtotal
                                  2,614,700
                                                  2,614,700
                                          165,900
                                                165,900
                                (continued)

                                   175

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                             TABLE 26 (continued)

Area 7 — Solids Separation
Item No. Description
Total
material
cost,
1982 $
Total
labor
cost,
1982 $
 1.   Tank,  thickener   1
     feed
     Agitator,
     thickener  feed
     tank
19-1/2 ft dia x 39 ft           29,700     24,600
high, 85,700 gal, open top,
agitator supports, four 19-1/2
in. baffles, carbon steel,
flakeglass lined

2 turbines, 77 in. dia, 50      34,400      2,800
hp, neoprene coated
     Pump,  thickener
     feed
 4.   Thickener
 5.   Pump,  thickener   2
     overflow
     Tank,  thickener
     overflow
     Pump,  thickener
     underflow
 !.   Tank,  filter      1
     feed
 9.   Agitator,  filter  1
     feed tank

10.   Pump,  filter      3
     feed slurry
Centrifugal, 868 gpm, 60 ft     15,900      5,300
head, 25 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)

Stainless steel tank, 71 ft    127,100    130,200
dia x 6 ft high; concrete
basin, 4 ft high

Centrifugal, 583 gpm, 75 ft     10,400      1,200
head, 20 hp, carbon steel
(1 operating, 1 spare)

16-1/4 ft dia x 6-1/4 ft         3,300      2,200
high, 9,600 gal, open top,
carbon steel

Centrifugal, 275 gpm, 10 ft      7,800      3,200
head, 1 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)

9-1/4 ft dia x 9-1/4 ft          3,600      3,000
high, 4,490 gal, open top,
carbon steel, flakeglass
lined

36 in. dia, 7-1/2 hp,            5,300        400
neoprene coated

Centrifugal, 135 gpm, 50 ft     11,900      3,500
head, 5 hp, carbon steel,
neoprene lined
(2 operating, 1 spare)

      (continued)
         176

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                            TABLE 26 (continued)
Area

11.
7 (continued)
Item No.
Filter 3 Ro

Total
material
cost,
Description 1982 $
itary vacuum, 11 ft dia x 372,300

Total
labor
cost,
1982 $
68,000
12.  Pump, filtrate   4
13.  Tank, filtrate   1
     surge
14.  Pump, filtrate   2
     surge tank
15.  Conveyor,        1
     gypsum disposal
     Subtotal
11 ft face, 15 total hp
(2 operating, 1 spare)

Centrifugal, 91 gpm, 20 ft
head, 1 hp, carbon steel
(2 operating, 2 spare)

8 ft dia x 8 ft high,
3,000 gal, open top, carbon
steel

Centrifugal, 182 gpm, 85 ft
head, 7-1/2 hp, carbon steel
(1 operating, 1 spare)

Belt, 14 in. wide x 75 ft
long, 100 ft inclined, 1.5
hp, 5.9 tons/hr, 40 ft/min
17,200
 1,600
 9,200
 37,100
1,900
1,100
1,000
3,500
                                686,800   251,900
Basis:  Most equipment cost estimates are based on informal vendor quotes and
        TVA information.

        These costs represent equipment costs only.  Costs for piping, elec-
        trical equipment, instruments, foundations, and other installation
        costs are not included.  The differences in area costs between the
        equipment list and the capital summary sheets are due to these
        installation costs.
                                    177

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                    ECONOMIC EVALUATION AND COMPARISON
     Based on the power plant,  design and economic premises,  and the
specific process equipment for each process described in the  previous
sections, study-grade capital investments, first-year revenue require-
ments, and levelized annual revenue requirements are prepared for the
economic evaluation and comparison of the soda ash and lime spray dryer
processes and a limestone scrubbing process (including an ESP).   Both
first-year and levelized annual revenue requirements are calculated.
First-year annual revenue requirements are useful for comparing  the
relative cost differences between processes for their first year of
operation, and they are an indicator of the magnitude of the  annual
revenue requirements.  However, first-year annual revenue requirements
are not representative of the actual cost of operating the plant since
they do not consider either the time-value of money or inflation over
the life of the plant.  In order to reflect these costs, a levelizing
factor is applied to the first-year annual revenue requirements  to give
a levelized annual revenue requirement.  This levelizing factor  is based
on a 10% discount factor and a 6% inflation rate over the 30-year life
of the power unit.  Sensitivity analyses are also performed to evaluate
the effects of varying the raw material price and stoichiometry  for the
lime spray dryer process.

     Even though the spray dryer processes are described and  costed as
proven technology, the current status of development does not fully
justify this assumption since none of the spray dryer processes  have
been operated on a commercial coal-fired boiler.  However, for TVA cost
estimation purposes each system is assumed to be proven technology.
ACCURACY OF ESTIMATES

     The accuracy associated with these study-grade cost estimates,
i.e., -20%, +40%, is defined as the relationship between the estimated
costs and what the actual installed costs for the process might be.  The
accuracy assigned to a cost estimate is empirical and not related to
variabilities in a statistical sense, but rather, it depends on both the
amount and the quality of the technical data available.  Accuracy ranges
also reflect the numerous uncertainties surrounding estimates made using
simplifying assumptions.  For example, in a study-grade estimate in
which only a flowsheet, material balance, and an equipment list are
available—and all other indirect investments are factored—the uncer-
tainty surrounding the investment is much greater than a preliminary-
level estimate where quantities and costs for piping, electrical equip-
ment, instruments, etc., are calculated rather than factored.  However,

                                 178

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when comparing the study-grade costs for two competing process technologies,
many of the same simplifying assumptions are made for each of the processes,
and therefore the comparability is greater than the accuracy of the
estimates.  When directly comparing two estimates of the same grade, the
uncertainty ranges associated with the compared costs are estimated to be
only ±10%.
LIGNITE CASE—CAPITAL INVESTMENT

Results

     The capital investment for the lime spray dryer process for the
lignite case is $82.6M ($165/kW) as shown in Table 27 and the capital
investment for the limestone scrubbing process (a combined particulate-
collection-limestone FGD system) is $107.6M ($215/kW) as shown in Table 28.

Comparison

     The direct investment and the total capital investment for the two
FGD systems are shown in Table 29.  The lime spray dryer process is
about 23% less capital intensive than the limestone scrubbing process.
The major reasons for this substantial difference in capital investment
between the lime spray dryer process and the limestone scrubbing process
are shown in Table 30, in which the major capital investment areas for
each process are compared.  The major capital investment differences are
in the S02 absorption, particulate removal, and gas handling areas.  All
are areas in which the costs for the limestone scrubbing process are
substantially higher than the equivalent area in the lime spray dryer
process.  The differences in the S02 absorption area are primarily due
to the use of a spray dryer as the absorber.  In the spray dryer process
presaturators, mist eliminators, forced-oxidation equipment, and large
recirculating pumps and tanks are not required in the S02 absorption
area.  Eliminating this process equipment leads to a significantly lower
investment for the SOo absorption area in the lime spray dryer process.
                         TABLE 29.   LIGNITE CASE

               DIRECT INVESTMENTS AND CAPITAL INVESTMENTS

Direct
investment
Process
Lime
spray
Limestone
dryer
scrubbing
M$
41.
59.
$/kW
5
2
83
118
.0
.4
Total capital
investment
M$
82.
107.

6
4
$/kW
165.
214.

3
7
                                 179

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                    TABLE  27.   LIGNITE CASE

                       CAPITAL  INVESTMENT

                   LIME SPRAY  DRYER PROCESS

              (500-MW new coal-fired unit,  0.9%  S  in  coal;
               70% SC>2 removal; onsite solids disposal)
                                                        Investment, k$

Direct Investment

Material handling                                            1,778
Feed preparation                                               765
Gas handling                                                10,665
S02 absorption                                               7,336
Particulate removal                                         12,091
Particulate handling                                         2,163

     Total process capital                                  34,798

Services, utilities, and miscellaneous                        2,088

     Total direct investment excluding  landfill              36,886

Solids disposal                                                867
Landfill construction                                        3t756

     Total direct investment                                41,509


Indirect Investment

Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency

     Total fixed investment                                  63,637


Other Capital Investment

Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital

     Total capital investment                                82,627

Dollars of total capital  per kW  of generation capacity       165.25
Basis
  Upper Midwest plant  location  represents project beginning mid-1980,
   ending mid-1983.  Average  cost basis for scaling, mid-1982.
  Minimum in-process storage, redundant scrubber train, and pumps are
   spared.
  Landfill located one mile from power plant.
  FGD process investment begins at boiler air heater exit.  Stack plenum
   and stack excluded.
  Only nominal construction overtime included.

                                180

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                   TABLE  28.   LIGNITE CASE


                      CAPITAL  INVESTMENT


                 LIMESTONE  SCRUBBING PROCESS


          (500-MW new coal-fired power unit, 0.9% S in coal;
               70% SC>2 removal; onsite solids disposal)


                                                        Investment,  k$

Direct Investment

Material handling                                            1,291
Feed preparation                                             2,406
Particulate removal                                         15,076
Gas handling                                                13,249
S02 absorption                                              17,357
Stack gas reheat
Solids separation

     Total process capital

Services, utilities,  and miscellaneous

     Total direct investment excluding landfill

Solids disposal
Landfill construction

     Total direct investment                                 59,226


Indirect Investment

Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency

     Total fixed investment                                  84,213


Other Capital Investment

Allowance for startup and modifications                       6,263
Interest during construction                                 13,014
Royalties
Land                                                           920
Working capital                                              2.950

     Total capital investment                               107,360

Dollars of total capital per kW of generation capacity       214.72
Basis
  Upper Midwest plant  location represents project beginning in early
   1981 and ending in  late  1983.  Average cost basis for scaling,  mid-1982.
  Minimum in-process storage, redundant scrubber train and feed
   preparation area, pumps  spared.
  Disposal area located  one mile from power plant.
  FGD process investment begins at boiler air heater exit.  Stack  plenum
   and stack excluded.
  Only nominal construction overtime included.

                                 181

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                       TABLE 30.   LIGNITE CASE

                 SUMMARY OF THE CAPITAL INVESTMENTS


                                         Total cost, k$
               Investment area
   Lime
spray dryer
  process
Limestone
scrubbing
 process
         Material handling
         Feed preparation
         Gas handling
         S02 absorption
         Particulate removal
         Particulate handling
         Solids separation
         Solids disposal
         Landfill construction
         Land
         All other capital costs
   1,778
     765
  10,665
   7,336
  12,091
   2,163

     867
   3,756
     960
  42,246
            Total capital investment    82,627
   1,291
   2,406
  13,249
  17,357
  15,076

   2,268
     790
   3,690
     920
  50,313

 107,360
         Basis:  TVA design and economic premises
     The differences in investment between the lime spray dryer process
and limestone scrubbing process for the gas handling area are primarily
due to two factors:  the larger ductwork requirements for the limestone
scrubbing process and corrosion-resistant materials of construction used
downstream of the 862 absorbers.  Larger ductwork is required for the
limestone scrubbing process because of the ductwork needed to neck up to
the ESP and then neck down after the ESP, which is not required for the
baghouse in the spray dryer process.  Since the flue gas downstream of
the spray dryer is not saturated, and thus corrosion is not expected to
be a problem, the ductwork from the spray dryer to the baghouse and from
the baghouse to the stack is made of Corten.   In the limestone
scrubbing process, the flue gas leaving the spray tower is saturated and
contains entrained liquid (the bypassed flue gas is not mixed with
the scrubbed gas until it enters the stack plenum) and corrosion could
be a significant problem.  Therefore, the flue gas ducts downstream of
the spray towers are made of stainless steel.  Stainless steel is about
3-1/2 times as expensive as Corten.   About half of the increased
cost for ductwork in the limestone scrubbing process is due to this
higher material cost for ductwork downstream of the absorber. (For the
same reasons, the ID fan in the limestone scrubbing process is made of
Inconel and is thus much more expensive than the ID fan in the spray
dryer process.)
                                  182

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     The particulate collection area investment is lower for the spray
dryer process even though the spray dryer process cost is based on a
baghouse and the cost for the limestone scrubbing process is based on an
ESP.  There are several reasons for this lower cost.  Since the baghouse
is located downstream of the spray dryers, the flue gas has been cooled
and thus the baghouse treats a much lower volume of flue gas.  The other
major reason for the more expensive ESP is that the fly ash is expected
to have a high resistivity and require a high SCA.

     The limestone scrubbing process also has the highest investment for
the feed preparation and the particulate handling/solids separation
areas.  The feed preparation investment is higher for the limestone
scrubbing process because crushers and ball mills are needed to grind
the limestone.  The feed preparation area in the lime spray dryer process
involves only slaking to prepare the absorbent slurry.  The slightly
higher investment for the limestone scrubbing process in the particulate
handling/solids separation area is due to the nature of the wastes.  The
FGD waste in the limestone scrubbing process is in the form of a dilute
slurry which must be separated (by a thickener and a filter) into FGD
waste and water for recycle to the process.  The particulate handling
area for the spray dryer process involves conveying the waste, which is
collected as a dry free-flowing solid, to the waste storage bins and
particulate recycle bins.  This area also includes the equipment to
reslurry and recycle the FGD waste through the spray dryer to increase
absorbent utilization.

     The limestone scrubbing process has the lowest investment in land-
fill construction, land, and the solids disposal area, although the
differences do not completely counteract the higher investments required
in other areas.  These lower costs result because the gypsum from the
limestone scrubbing process is much more dense than the dry FGD waste
from the lime spray dryer process.

     The investment for the limestone scrubbing process material handling
section is less than the spray dryer process.  The lime spray dryer
process has higher material handling investment primarily because a
large storage silo is required for a 30-day lime supply, but also because
of the various large conveyors and elevators to move the lime.  The
limestone for the limestone scrubbing process can be stored on the
ground and thus the material handling area includes only the large
conveyors and elevators.

     The category in Table 30, all other capital costs, includes those
costs which are calculated entirely or in part as a percentage of the
direct investment.  Thus if the process has a higher direct investment
(i.e., the limestone slurry process) it will have a proportionally
higher charge for all other capital costs.

     In order to facilitate comparisons of these economic results with
those from other EPA-sponsored evaluations, the total capital investments
                                  183

-------
are presented in a slightly different form in Table 31.   In this table
the capital investment is broken down into three areas:   SC>2 absorption,
particulate removal, and waste disposal.  Each area includes not only
direct investment for equipment, piping, electrical equipment, etc., but
also its pro rata share of the indirect investments and all other capital
charges.  Previously identified direct investment areas grouped in the
862 absorption area are:  material handling, feed preparation, gas
handling, and SO,., absorption.  The particulate removal area consists
only of the original particulate removal area.  The waste disposal area
combines the particulate handling/solids separation, solids disposal,
and landfill construction.
                         TABLE 31.   LIGNITE CASE

                           CAPITAL  INVESTMENTS

Area
S02 absorption
Particulate removal
Waste disposal
Capital
investment
Investment,
Lime
spray dryer
process
89.13
51.25
24.87
165.25
$/kW
Limestone
scrubbing
process
133.35
57.47
23.90
214.72

             Basis:  TVA design and economic premises




LIGNITE CASE—ANNUAL REVENUE REQUIREMENTS

Results

     The first-year annual revenue requirements for the lime spray dryer
process are $20.92 in 1984 dollars as shown in Table 32.  The equivalent
first-year unit revenue requirement is 7.61 mills/kWh.  Levelized annual
and unit revenue requirements are  $28.69M and 10.43 mills/kWh respectively.
The first-year annual revenue requirements for the limestone scrubbing
process are $26.32M as shown in Table 33.  The equivalent first-year
unit revenue requirement is 9.57 mills/kWh.  Levelized annual and unit
revenue requirements  are $35.65M and 12.96 mills/kWh respectively.

Comparison

     The first-year and the levelized annual revenue requirements for
each of the FGD processes are shown in Table 34.  In terms of first-year

                                  184

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                        TABLE 32.  LIGNITE  CASE

                     ANNUAL REVENUE REQUIREMENTS

                      LIME  SPRAY DRYER PROCESS

               (500-MW new coal-fired power unit, 0.9% S  in  coal;
                    70%  SC>2 removal; onsite solids disposal)
Annual
quantity
Direct Costs - First-Year
Raw materials
Lime 16,300 tons
Total raw material cost
Conversion costs
Operating labor and supervision
FGD 25,400 man-hr
Solids disposal 30,675 man-hr
Utilities
Fuel 209,375 gal
Process water 139,570 kgal
Electricity 43,703,473 kWh
Maintenance
Labor and material
Analysis 4,200 man-hr
Total conversion costs
Total direct costs
Indirect Costs - First-Year
Overheads
Plant and administrative
Total first-year operating and maintenance cost
Levelized capital charges (14.7% of
total capital investment)
Total first-year annual revenue requirements
Levelized first-year operating and maintenance
cost (1.886 first-year 0 and M)
Levelized capital charges (14.7% of
total capital investment)
Levelized annual revenue requirements
Unit Total annual
cost, $ cost, k$


102.00/ton 1,663
1,663


15.00/man-hr 381
21.00/man-hr 644

1.60/gal 335
0.14/kgal 20
0.037/kWh 1,617

2,232
21.00/man-hr 88
5,317
6,980


1,794
8,774

12.146
20,920

16,548

12.146
28,694
First-year annual revenue requirements
Levelized annual revenue requirements
20.92
28.69
Mills/kWh

   7.61
  10.43
Basis
  Upper Midwest plant location, 1984 revenue requirements.
  Remaining life of power plant, 30 years.
  Power unit onstream time,  5,500 years
  Coal burned, 2,291,575 tons/yr, 9,500 Btu/kWh.
  Total direct investment,  $41,509,000; total fixed investment,  $63,637,000; and
   total  capital investment  $82,627,000.


                                     185

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                        TABLE  33.   LIGNITE  CASE

                     ANNUAL REVENUE REQUIREMENTS

                     LIMESTONE  SCRUBBING PROCESS
               (500-MW new coal-fired power unit,  0.9%  S in coal;
                    70% S02 removal; onsite solids disposal)
Direct Costs  -  First-Year

Raw materials
  Limestone

     Total raw  material cost

Conversion costs
  Operating labor  and supervision
    FGD
    Solids disposal
  Utilities
    Fuel
    Process water
    Electricity
  Maintenance
    Labor and material
  Analysis

     Total conversion costs

     Total direct  costs
                                       Annual
                                      quantity
                      Unit
                      cost, $
    26,700 tons
    39,620 man-hr
    29,447 man-hr

   185,625 gal
   144,871 kgal
53,683,254 kWh
              Total annual
                cost, k$
 8.50/ton
15.00/man-hr
21.00/man-hr

 1.60/gal
 0.14/kgal
 0.037/kWh
     3,335 man-hr    21.00/man-hr
  227

  227
  594
  618

  297
   20
1,986

3,851
	70_

7,436

7,663
Indirect Costs  -  First-Year

Overheads
  Plant and administrative
                                                                       2,872
     Total first-year operating and maintenance costs

Levelized capital charges (14.7% of
 total capital investment)

     Total first-year annual revenue requirements

Levelized first-year operating and maintenance
 costs (1.886 first-year 0 and M)

Levelized capital charges (14.7% of
 total capital investment)

     Levelized annual revenue requirements
                                    10,535
                                    19,869
First-year annual revenue requirements
Levelized annual revenue requirements
               M$

              26.32
              35.65
 Mills/kWh

    9.57
   12.96
Basis
  Upper Midwest plant  location, 1984 revenue requirements.
  Remaining life of  power plant, 30 years.
  Power unit onstream  time, 5,500 hr/yr.
  Coal burned,  2,291,575 tons/yr, 9,500 Btu/kWh.
  Total direct  investment, $59,226,000; total fixed investment,  $84,213,000; and
   total capital investment, $107,360,000.
                                      186

-------
 annual revenue requirements,  the  lime  spray  dryer  process  is  substantially
 lower than the limestone scrubbing process  (21%  less).   The relative
 ranking in terms  of levelized annual revenue requirement does not  change
 although the percentage difference does  change slightly.
                        TABLE 34.  LIGNITE CASE

          FIRST-YEAR AND LEVELIZED ANNUAL REVENUE REQUIREMENTS
                            First-year annual      Levelized annual
                          revenue requirements   revenue requirements
Process
Lime spray dryer
Limestone scrubbing
M$
20.92
26.32
Mills /kWh
7.61
9.57
M$
28.69
35.65
Mills /kWh
10.43
12.96
    Basis:  TVA design and economic premises
     Table  35 compares  the various cost components of the first-year
 annual revenue requirements for each process.  With the exception of the
 raw material and all other annual costs categories (which include minor
 costs such  as process water, analysis, and waste disposal fuel), the
 limestone scrubbing process has the highest annual costs of the two
 processes.  The higher  annual costs for the limestone scrubbing process
 relative to the lime spray dryer process are primarily due to three
 areas:  levelized capital charges, maintenance costs, and overhead
 costs.  These areas alone are about $6.3M higher in the limestone scrubbing
 process than in the lime spray dryer process.

     The higher levelized capital charge for the limestone scrubbing
process is due to its higher capital investment, as previously discussed.
Maintenance costs are much higher for the limestone scrubbing process
because of the limestone handling and grinding equipment and the equipment
needed to recirculate large quantities of the erosive slurry.   Since the
overhead charges are calculated as a percentage of the direct costs
excluding utilities, the overheads for the limestone scrubbing process
are substantially higher than those for the lime spray dryer process.

     The raw material annual costs are the only major area in which the
lime spray dryer process is higher than the limestone scrubbing process.
This higher raw material cost in the lime spray dryer process  is due to
the use of a more reactive alkali reagent,  which has  a higher  unit  cost.
The differences  in annual quantities used (16,300 tons of  lime,  26,700
tons of limestone)  are not as significant as the differences in unit
costs assumed ($102/ton for lime,  $8.50/ton for limestone).   The effects
on the first-year annual revenue requirements of different unit costs of
the raw materials and the raw material stoichiometry  are discussed  in
the next section in the form of a sensitivity analysis.

                                  187

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                        TABLE 35.   LIGNITE CASE

           SUMMARY OF FIRST-YEAR ANNUAL REVENUE REQUIREMENTS


                                          Total cost,  k$
                  Annual cost
   Lime      Limestone
spray dryer  scrubbing
  process	process
Raw material
Operating labor and
supervision
Electricity
Maintenance
Overheads
Levelized capital charges
All other
1,663
1,025

1,617
2,232
1,794
12,146
443
227
1,212

1,986
3,851
2,872
15,782
387
             Total first-year annual     20,920      26,317
              revenue requirements
          Basis:  TVA design and economic premises
LIGNITE CASE—SENSITIVITY ANALYSIS

Sensitivity to Absorbent Prices

     The sensitivities of the first-year annual revenue requirements to
raw material costs for the lime spray dryer process and the limestone
scrubbing process were calculated using the absorbent costs shown in
Table 36.  The results of this sensitivity analysis are shown in Figure 33,


                        TABLE 36.   LIGNITE  CASE

           DELIVERED  UNIT PAW MATERIAL  COSTS  ASSUMED  FOR THE

                          SENSITIVITY ANALYSIS

Process Raw material
Lime spray dryer Lime


Limestone scrubbing Limestone


Variation
Low
Base
High
Low
Base
High
$/tona
82.00
102.00
143.00
7.00
8.50
12.00
% change
-20
-
+40
-20
-
+40

   a.  Delivered cost
                                  138

-------
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     Although the lime spray dryer process is more sensitive than the
limestone scrubbing process to changes in the price of the absorbent,
the low-sulfur nature of the lignite and the low SC>2 removal requirements
preclude changes from the base-case costs from significantly changing
the economic results.  The lime spray dryer process has lower first-year
annual revenue requirements regardless of the lime costs selected
(within the -20% to +40% range).   For example,  a 40% increase in the
delivered cost of lime results in only a 2.2% increase in the first-year
annual revenue requirements for the lime spray dryer process.  This is
still 18% less than the first-year annual revenue requirements for the
base-case limestone scrubbing process.

     The limestone scrubbing process, because of the low unit cost of
limestone as well as the lower sulfur level in the coal and the lower
SC>2 removal requirements, is essentially insensitive to the delivered
cost of limestone (a 40% increase in cost results in only a 0.3% increase
in first-year annual revenue requirements).

Sensitivity to Raw Material Stoichiometry

     Since the spray dryer process technology has only been demonstrated
on a pilot-plant scale, the assumed Stoichiometry in the spray dryer
could change as the technology is developed.  The required Stoichiometry
for coals with the same sulfur content could also change, depending on
the fly ash alkalinity of the coal being burned.  Therefore, a sensitivity
analysis showing the changes in first-year revenue requirements as the
Stoichiometry in the spray dryer is changed has been included.  Table 37
lists both the base-case and the alternative stoichiometries used in the
sensitivity analysis.  The stoichiometries given are in moles of alkali
per mole of S02 absorbed.  The range of stoichiometries shown for the
lime spray dryer process is 1.1 (-10%) to 1.46 (19.7%).

     The capital investments for each processing area are adjusted by
using area scale factors and the ratio of flow rates through each area.
Processing areas that are sized independently of the absorbent rates
(gas handling and SC>2 absorption) are the same for each of the alternative
stoichiometries.  Many of the processing areas that are dependent on the
absorbent flow rate contribute only minor amounts to the capital investment.
For example, a 20% increase in absorbent flow rate increases the capital
investment about 1%.

     The annual revenue requirements for the lime spray dryer process
are somewhat more sensitive to the absorbent Stoichiometry than they are
to the absorbent cost.  For example, a 20% increase in the absorbent
Stoichiometry results in a 2.5% increase in first-year revenue requirements,
However, from these results (as shown in Figure 34) it is apparent that
Stoichiometry changes over a wide range will have little effect on the
capital investment and annual revenue requirement relationships of the
two processes for this lignite case.
                                  190

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                                 TABLE 37.   LIGNITE CASE

                  COMPARISON OF CAPITAL INVESTMENT AND FIRST-YEAR UNIT

                  REVENUE REQUIREMENTS FOR THE LIME SPRAY DRYER PROCESS

                         AT VARIOUS RAW MATERIAL STOICHIOMETRIES

Process
Lime spray
Limestone scrubbing

Raw material
stoichiometry
Variation Value3 % change*5
Low
Base
High
Base
1.10 -9.9
1.22
1.46 19.7
1.12
capital
$/kW
164.0
165.3
167.3
214.7
Total
investment
% changeb
-0.79
1.21
-
First-year unit
revenue requirements
mills /kWh % change^
7.50 -1.45
7.61
7.80 2.50
9.57

a.  Raw material stoichiometry is defined as mols of alkali per mol of S02 absorbed.
b.  Change is calculated relative to the base-case value.

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LOW-SULFUR WESTERN COAL CASE—CAPITAL INVESTMENT

Results

     The capital investment for the soda ash spray dryer process for the
low-sulfur western coal case is $79.4M ($159/kW) in mid-1982 dollars as
shown in Table 38.  The capital investment for the lime spray dryer
process is $77.1M ($154/kW) as shown in Table 39.  The capital investment
for the limestone scrubbing process (a combined particulate-collection-
limestone FGD system) is $88.1M ($176/kW) as shown in Table 40.

Comparison

     The direct investment and the total capital investment for the
three FGD systems are shown in Table 41.  Both the lime and the soda ash
spray dryer processes are about 10% to 12% less capital intensive than
the limestone scrubbing process.  Although the lime spray dryer process
is the least capital intensive of the three FGD systems for the low-
sulfur western coal case, the difference (about 3% in capital investment)
between the two spray dryer processes is not highly significant when
compared with the accuracy limits associated with studies of this type.
                TABLE 41.  LOW-SULFUR WESTERN COAL CASE

               DIRECT INVESTMENTS AND CAPITAL INVESTMENTS

Direct
investment

Lime
Soda
Process
spray dryer
ash spray dryer
Limestone scrubbing
M$
38.
40.
48.
$/kW
6
9
5
77
81
97
.2
.9
.0
Total
capital
investment
M$
77.
79.
88.
$/kW
1
4
1
154
158
176
.2
.9
.1

     The major reasons for this substantial difference in capital
investment between the spray dryer processes and the limestone scrubbing
process are shown in Table 42, in which the major investment areas for
each process are compared.  The major investment differences are in the
S02 absorption and gas handling areas.  Both are areas in which the
costs for the limestone scrubbing process are substantially higher than
the equivalent area in the spray dryer processes.  The differences in
the S02 absorption area are primarily due to the use of a spray dryer as
the absorber which eliminates the need for presaturators, mist eliminators,
forced-oxidation equipment, and large recirculating pumps and tanks.
Eliminating this process equipment leads to a significantly lower direct
investment for the S02 absorption area in the spray dryer processes.

                                  193

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           TABLE 38.   LOW-SULFUR WESTERN COAL CASE

                       CAPITAL  INVESTMENT

                 SODA ASH  SPRAY DRYER PROCESS

             (500-MW new  coal-fired unit, 0.7% S in coal;
               70%  S02  removal; onsite solids disposal)
Direct Investment

Material handling
Feed preparation
Gas handling
S02 absorption
Particulate removal
Particulate handling

     Total process  capital

Services, utilities, and miscellaneous

     Total direct investment excluding pond

Solids disposal
Pond construction

     Total direct investment
                                                        Investment., k$
40,941
Indirect Investment

Engineering design and supervision
Architect and engineering  contractor
Construction expense
Contractor fees
Contingency

     Total fixed investment
61,408
Other Capital Investment

Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital

     Total capital investment

Dollars of total capital  per kW of  generation capacity
79,448

158.90
Basis
  Upper Midwest plant location represents project beginning mid-1980,
   ending mid-1983.  Average cost  basis  for scaling, mid-1982.
  Minimum in-process storage, redundant  scrubber train, and pumps are
   spared.
  Pond located one mile from power plant.
  FGD process investment begins at boiler air heater exit.  Stack plenum
   and stack excluded.
  Only nominal construction overtime included.

                                   194

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           TABLE 39.   LOW-SULFUR WESTERN COAL CASE

                       CAPITAL  INVESTMENT

                   LIME SPRAY  DRYER PROCESS

             (500-MW new coal-fired unit, 0.7% S in coal;
               70% SC>2  removal; onsite  solids disposal)
Direct Investment

Material handling
Feed preparation
Gas handling
S02 absorption
Particulate removal
Particulate handling and recycle

     Total process capital

Services, utilities, and miscellaneous

     Total direct investment  excluding landfill

Solids disposal
Landfill construction

     Total direct investment
                                                        Investment,  k$
38,587
Indirect Investment

Engineering design and supervision
Architect and engineering  contractor
Construction expense
Contractor fees
Contingency

     Total fixed investment
59,369
Other Capital Investment

Allowance for startup  and modifications
Interest during construction
Royalties
Land
Working capital

     Total capital investment

Dollars of total capital per kW of generation capacity
Basis
  Upper Midwest plant  location represents project beginning mid-1980,
   ending mid-1983.  Average  cost basis for scaling, mid-1982.
  Minimum in-process storage, redundant scrubber train,  and pumps  are
   spared.
  Landfill located one mile from power plant.
  FGD process  investment begins at boiler air heater exit.   Stack  plenum
   and stack excluded.
  Only nominal construction overtime included.

                                195

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        TABLE 40.    LOW-SULFUR WESTERN  COAL CASE


                     CAPITAL  INVESTMENT


                LIMESTONE SCRUBBING PROCESS


          (500-MW new coal-fired power unit, 0.7% S in coal;
               70% S02 removal;  onsite solids  disposal)


                                                       Investment,  k$

Direct Investment

Material handling                                            1,009
Feed preparation                                             1,923
Particulate  removal                                         11,688
Gas handling                                               11,646
S02 absorption                                              15,054
Stack gas reheat
Solids separation

     Total process capital

Services, utilities, and miscellaneous

     Total direct investment excluding landfill

Solids disposal
Landfill construction

     Total direct investment                                48,511


Indirect Investment

Engineering  design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency

     Total fixed investment                                 69,026


Other Capital Investment

Allowance for startup and modifications                      5,232
Interest during construction                                10,672
Royalties                                                     -
Land                                                          670
Working capital                                             2.464

     Total capital investment                               88,064

Dollars of total capital per kW of generation  capacity       176.13
Basis
  Upper Midwest  plant  location represents project beginning in early
   1981 and ending  in  late 1983.  Average cost basis for scaling, mid-
   1982.
  Minimum in-process storage, redundant scrubber train and feed prepara-
   tion area,  pumps spared.
  Disposal area  located one mile from power plant.
  FGD process  investment begins at boiler air heater exit.  Stack plenum
   and stack excluded.
  Only nominal construction overtime included.

                                196

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                TABLE  42.  LOW-SULFUR WESTERN COAL CASE

                  SUMMARY OF THE CAPITAL INVESTMENTS
                                          Total cost, k$
          Investment area
   Lime
spray dryer
  process
 Soda ash
spray dryer
  process
Limestone
scrubbing
 process
   Material handling               1,691          461       1,009
   Feed preparation                  680           91       1,923
   Gas handling                   10,030        9,088      11,646
   S02 absorption                  7,366        9,208      15,054
   Particulate removal            11,523       11,523      11,688
   Particulate handling            2,057          750
   Solids separation                 -            -         1,828
   Solids disposal                   719          725         616
   Landfill/pond construction      2,520        7,228       2,158
   Land                              770        1,146         670
   All other  capital  costs        39,757       39,228      41,472

      Total capital investment    77,113       79,448      88,064
   Basis:  TVA design and economic premises
     The differences in investment between the spray dryer processes and
limestone scrubbing process for the gas handling area are primarily due
to two factors:  the larger ductwork requirements for the limestone
scrubbing process and corrosion-resistant materials of construction
(stainless steel) used downstream of the S02 absorbers.   Since the flue
gas downstream of the spray dryer is not saturated, and thus corrosion
is not expected to be a problem, the ductwork from the spray dryer to
the baghouse and from the baghouse to the stack is made of Corten steel.
In the limestone scrubbing process, the flue gas leaving the spray tower
is saturated and contains entrained liquid (the bypassed flue gas is not
mixed with the scrubbed gas until it enters the stack plenum) and
corrosion could be a significant problem.  Therefore, the flue gas ducts
downstream of the spray tower are made of stainless steel.  (For the
same reasons, the ID fan in the limestone scrubbing process is made of
Inconel and is thus much more expensive than the ID fan in the spray
dryer processes.)

     Due to the different raw material characteristics of the spray
dryers processes, the only other area similar in both of the spray dryer
processes is the particulate collection area.  The particulate collection
area investment is the same for both of the spray dryer processes and is
essentially the same for the limestone scrubbing process even though the
spray dryer process costs are based on a baghouse and the cost for the
limestone scrubbing process is based on an ESP.
                                  197

-------
     The limestone scrubbing process also has the highest  investment  for
the feed preparation and the particulate handling/solids separation
areas.  The feed preparation investment is somewhat more expensive for
the limestone scrubbing process because it is necessary to grind the
limestone before preparing the absorbent slurry.   The feed preparation
area in the lime spray dryer process involves only slaking to prepare
the absorbent slurry and the same area in the soda ash spray dryer
process involves simply diluting the saturated soda ash solution to
prepare the absorbent solution.  The lime spray dryer and the limestone
scrubbing processes have much higher particulate handling/solids separation
area investments than the soda ash spray dryer process.  The lime spray
dryer process has the highest investment because it not only includes
the equipment to convey the FGD waste to waste storage bins and recycle
bins but also the equipment to reslurry and recycle the FGD waste through
the spray dryer to increase absorbent utilization.  For the limestone
slurry process this is due to the FGD waste being in the form of a
dilute slurry which must be separated (by a thickener and a filter) into
FGD waste and water for recycle to the process.  The particulate handling
area for the soda ash spray dryer process involves only conveying the
waste, which is collected as a dry free-flowing solid, to the waste
storage bins.

     The limestone scrubbing process has the lowest investment in land-
fill/pond construction, land, and the disposal area, although the differ-
ences do not balance the higher investments required in other areas.
The landfill/pond construction, land, and solids disposal area costs  for
the soda ash spray dryer process are much higher than the equivalent
areas in the other processes because the soluble nature of the waste
requires a pond rather than a landfill for disposal.

     The investment for the limestone scrubbing process material handling
section falls between those of the spray dryer processes.   The lime
spray dryer process has the highest material handling investment primarily
because a large storage silo is required for a 30-day lime supply, but
also because of the various large conveyors and elevators to move the
lime.  The limestone for the limestone scrubbing process can be stored
on the ground and thus the material handling area includes only the
large conveyors and elevators.  The soda ash spray dryer process has  the
lowest area investment since the soda ash is stored as a slurry in a
large tank, and other than several small pumps requires no additional
equipment.

     In order to facilitate comparisons of these economic results with
those from other EPA-sponsored evaluations, the total capital investments
are presented in a slightly different form in Table 43.  In this table
the capital investment is broken down into three areas:  862 absorption,
particulate removal, and waste disposal.  Each area includes not only
the direct investment for equipment, piping, electrical equipment, etc.,
but also its pro rata share of the indirect investments and all other
capital charges.  Previously identified direct investment areas grouped
in the S02 absorption area are:  material handling, feed preparation,
gas handling, and S02 absorption.  The particulate removal area consists

                                  198

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only of the original particulate removal area.   The waste disposal area
combines the particulate handling solids separation, solids disposal,
and landfill/pond construction.
               TABLE 43.  LOW-SULFUR WESTERN COAL CASE

                          CAPITAL INVESTMENTS



                                     Investment, $/kW
Area
Lime
spray dryer
process
Soda ash
spray dryer
process
Limestone
scrubbing
process
        S02  absorption           85.62
        Particulate  removal      48.84
        Waste  disposal           19 . 76
81.85
48.84
28.21
114.96
 44.56
 16.61
Capital
investment
154.22 158.90 176.13

        Basis:   TVA  design  and  economic  premises
LOW-SULFUR WESTERN COAL CASE—ANNUAL REVENUE REQUIREMENTS

Results

     The first-year annual revenue requirements for the soda ash spray
dryer process are $20.41M in 1984 dollars as shown in Table 44.  This
corresponds to a first-year unit revenue requirement of 7.42 mills/kWh.
Equivalent levelized annual revenue requirements for the soda ash spray
dryer process are $28.15M, or 10.23 mills/kWh.  The first-year annual
revenue requirements for the lime spray dryer process are $19.02M as
shown in Table 45.  The equivalent first-year unit revenue requirement
is 6.92 mills/kWh.  Levelized annual and unit revenue requirements are
$25.82M and 9.39 mills/kWh respectively.  The first-year annual revenue
requirements for the limestone scrubbing process are $21.73M as shown in
Table 46.  The equivalent first-year unit revenue requirement is 7.90
mills/kWh.  Levelized annual and unit revenue requirements are $29.52M
and 10.73 mills/kWh respectively.

Comparison

     The first-year and the levelized annual revenue requirements for
each of the FGD processes are shown in Table 47.  In terms of first-year
annual revenue requirements, the relative ranking of the three processes
from lowest cost to the highest is lime spray dryer, soda ash spray

                                  199

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             TABLE 44.   LOW-SULFUR  WESTERN COAL  CASE

                     ANNUAL REVENUE REQUIREMENTS

                    SODA ASH  SPRAY DRYER PROCESS
               (500-MW new coal-fired power unit, 0.7% S  in  coal;
                   70% S02 removal; onsite solids disposal)

Direct Costs - First-Year
Raw materials
Soda ash
Total raw material cost
Conversion costs
Operating labor and supervision
FGD
Solids disposal
Utilities
Fuel
Process water
Electricity
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Annual
quantity


18,350 tons



16,640 man-hr
28,362 man-hr

165,725 gal
70,236 kgal
41,152,243 kWh


4,191 man-hr


Unit
cost, $


145.00/ton



15.00/man-hr
21.00/man-hr

1.60/gal
0.14/kgal
0.037/kWh


21.00/man-hr


Total annual
cost, k$


2,661
2,661


250
596

265
10
1,523

1,863
88
4,595
7,256
Indirect Costs - First-Year

Overheads
  Plant and  administrative
                                                                      1,475
     Total first-year operating  and maintenance costs

Levelized capital charges (14.7% of
 total capital investment)

     Total first-year annual revenue requirements

Levelized first-year operating and maintenance
 costs (1.886 first-year 0 and M)

Levelized capital charges (14.7% of
 total capital investment)

     Levelized annual revenue requirements
                       8,731
                      16,467
First-year  annual revenue requirements
Levelized annual revenue requirements
20.41
28.15
Mills/kWh

   7.42
  10.23
Basis
  Upper Midwest plant location,  1984 revenue requirements.
  Remaining  life of power plant,  30 years.
  Power unit  onstream time, 5,500 hr/yr.
  Coal burned, 1,116,500 tons/yr, 9,500 Btu/kWh.
  Total direct investment, $40,941,000; total fixed investment, $61,408,000;  and
   total capital investment,  $79,448,000.

                                      200

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             TABLE  45.   LOW-SULFUR WESTERN COAL  CASE

                     ANNUAL REVENUE  REQUIREMENTS

                      LIME  SPRAY  DRYER PROCESS
              (500-MW new coal-fired power unit,  0.7% S in coal;
                   70% S02 removal; onsite solids disposal)

Direct Costs - First-Year
Raw materials
Lime
Total raw material cost
Conversion costs
Operating labor and supervision
FGD
Solids disposal
Utilities
Fuel
Process water
Electricity
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Annual
quantity


10,100 tons



25,400 man-hr
28,152 man-hr

163,750 gal
82,193 kgal
39,571,324 kWh


4,191 man-hr


Unit
cost, $


102.00/ton



15. 00 /man-hr
21,00/man-hr

1.60/gal
0 . 14/kgal
0.037/kWh


2 1.00 /man-hr


Total annual
cost, k$


1,030
1,030


381
591

262
12
1,464

2,136
88
4,934
5,964
Indirect  Costs - First-Year

Overheads
  Plant and  administrative
                       1,717
     Total first-year operating and maintenance costs

Levelized capital charges (14.7% of
 total capital investment)

     Total first-year annual revenue requirements

Levelized first-year operating and maintenance
 costs (1.886 first-year 0 and M)

Levelized capital charges (14.7% of
 total capital investment)

     Levelized annual revenue requirements
                       7,681
                      14,486
First-year annual revenue requirements
Levelized annual revenue requirements
19.02
25.82
Mills/kWh

  6.92
  9.39
Basis
  Upper Midwest plant location,  1984  revenue requirements.
  Remaining life of power plant,  30 years.
  Power unit onstream time, 5,500 hr/yr.
  Coal burned, 1,346,700 tons/yr, 9,500 Btu/kWh,
  Total direct investment, $38,587,000; total fixed investment,  $59,369,000; and
   total capital investment, $77,113,000.

                                     201

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             TABLE 46.    LOW-SULFUR WESTERN  COAL CASE

                     ANNUAL REVENUE  REQUIREMENTS

                     LIMESTONE SCRUBBING  PROCESS
               (500-MW new coal-fired power unit, 0.7% S in coal;
                    70% S02 removal;  onsite solids disposal)
Direct Costs  -  First-Year

Raw materials
  Limes t one

     Total raw  material cost

Conversion costs
  Operating labor  and supervision
    FGD
    Solids disposal
  Utilities
    Fuel
    Process water
    Electricity
  Maintenance
    Labor and material
  Analysis

     Total conversion costs

     Total direct  costs
                                       Annual
                                      quantity
                      Unit
                     cost, $
    17,600  tons
    39,620  man-hr
    25,981  man-hr

   134,540  gal
   120,000  kgal
40,769,000  kWh
             Total annual
                cost, k$
 8.50/ton
15.00/man-hr
21.00/man-hr

 1.60/gal
 0.14/kgal
 0.037/kWh
     3,330 man-hr   21.00/man-hr
  150

  150
  594
  546

  215
   17
1,508

3,219
	70

6,169

6,319
Indirect Costs  -  First-Year

Overheads
  Plant and administrative
     Total first-year operating and maintenance  costs

Levelized capital charges (14.7% of
 total capital  investment)

     Total first-year annual revenue requirements

Levelized first-year operating and maintenance
 costs (1.886 first-year 0 and M)

Levelized capital charges (14.7% of
 total capital  investment)

     Levelized  annual revenue requirements
                                     2,467


                                     8,786
                                    16,570
First-year annual revenue requirements
Levelized annual revenue requirements
               M$

              21.73
              29.52
 Mills/kWh

    7.90
   10.73
Basis
  Upper Midwest  plant  location, 1984 revenue requirements.
  Remaining life of  power plant, 30 years.
  Power unit onstream  time, 5,500 hr/yr.
  Coal burned,  1,346,700 tons/yr, 9,500 Btu/kWh.
  Total direct  investment, $48,511,000; total fixed investment, $69,026,000; and
   total capital investment, $88,064,000.
                                      202

-------
dryer, and limestone scrubbing.   The lime spray dryer process is slightly
lower in cost than the soda ash spray dryer process (7% less) and sub-
stantially lower than the limestone slurry process (12% less).   The
relative ranking in terms of levelized annual revenue requirement does
not change although the percentage difference does change slightly.
                TABLE 47.   LOW-SULFUR WESTERN  COAL  CASE

         FIRST-YEAR AND LEVELIZED ANNUAL REVENUE REQUIREMENTS
                            First-year  annual       Levelized annual
                          revenue requirements   revenue requirements
Process
Lime spray dryer
Soda ash spray dryer
Limestone scrubbing
M$
19.02
20.41
21.73
Mills/kWh
6.92
7.42
7.90
M$
25.82
28.15
29.52
Mills/kWh
9.39
10.23
10.73
   Basis:  TVA design and economic premises
     Table 48 compares the various cost components of the first-year
annual revenue requirements for each process.  With the exception of the
costs for raw material, electricity, and all other categories, the
limestone scrubbing process has the highest annual costs of all three
processes.  The higher annual costs for the limestone scrubbing process
relative to the spray dryer processes are primarily due to three areas:
levelized capital charges, maintenance costs, and overhead costs.  These
areas alone are about $3.5M higher in the limestone scrubbing process
than in the spray dryer processes.

     The higher levelized capital charge for the limestone scrubbing
process is due to its higher capital investment.  Maintenance costs are
much higher for the limestpne scrubbing process because of the limestone
handling and grinding equipment and the equipment needed to recirculate
large quantities of the erosive slurry.  Since the overhead charges are
calculated as a percentage of the direct costs excluding utilities,
(i.e., maintenance and operating labor), the overheads for the limestone
scrubbing process are substantially higher than those for the spray
dryer processes.
                                  203

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                TABLE 48.   LOW-SULFUR WESTERN  COAL  CASE

          SUMMARY OF FIRST-YEAR ANNUAL REVENUE REQUIREMENTS

Total cost, k$


Annual cost
Raw material
Operating labor and
supervision
Electricity
Maintenance
Overheads
Levelized capital charges
All other
Lime
spray dryer
process
1,030
972

1,464
2,136
1,717
11,336
362
Soda ash
spray dryer
process
2,661
846

1,523
1,863
1,475
11,679
363
Limestone
scrubbing
process
150
1,140

1,508
3,219
2,467
12,945
302
      Total first-year annual
       revenue requirements
19,017
20,410
21,731
   Basis:  TVA design and  economic  premises
     The raw material annual costs are the only major area in which the
spray dryer processes are significantly higher than the limestone scrubbing
process.  This higher raw material cost in the spray dryer processes is
due to the use of a more reactive alkali reagent,  which has a higher
unit cost.  The differences in annual quantities used (10,100 tons of
lime, 18,350 tons of soda ash, 17,600 tons of limestone) are not as
significant as the differences in unit costs assumed ($102/ton for lime,
$145/ton for soda ash, $8.50/ton for limestone).  The effects on the
first-year annual revenue requirements of different unit costs of the
raw materials and the raw material stoichiometry are discussed in the
next section in the form of a sensitivity analysis.

     A comparison of the various cost components for the two spray dryer
processes shows that the largest difference is in the raw materials cost
($1.6M).  The soda ash spray dryer process has a higher raw material
cost because of both the higher annual consumption (no waste recycle)
and the higher unit cost of the soda ash, compared with lime.  Other
less significant differences are in three areas:  maintenance, overheads,
and levelized capital charges.  The soda ash process has a higher levelized
capital charge because it has a somewhat higher total capital investment.
The maintenance cost (and overhead cost because it is calculated in part
as a percentage of the maintenance cost) is somewhat lower for the soda
ash process because the material handling equipment required to prepare
the soda ash for use in the process involves only solutions rather than
solids and aqueous slurries.
                                  204

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LOW-SULFUR WESTERN COAL CASE—SENSITIVITY ANALYSIS

Sensitivity to Absorbent Prices

     The sensitivities of the first-year annual revenue requirements to
raw material costs for the lime spray dryer process, the soda ash spray
dryer process, and the limestone scrubbing process were calculated using
the absorbent costs shown in Table 49.  The results of this sensitivity
analysis are shown in Figure 35.
                 TABLE 49.   LOW-SULFUR WESTERN COAL CASE

           DELIVERED UNIT RAW MATERIAL COSTS ASSUMED FOR THE

                          SENSITIVITY ANALYSIS
Process Raw material
Lime spray dryer Lime


Soda ash spray dryer Soda ash


Limestone scrubbing Limestone


Variation $/tona % change
Low
Base
High
Low
Base
High
Low
Base
High
82.00
102.00
143.00
116.00
145.00
203.00
7.00
8.50
12.00
-20
-
+40
-20
-
+40
-20
-
+40

    a.  Delivered cost
     Although  the lime  spray dryer process and the soda ash process are
more sensitive than  the limestone scrubbing process to changes in  the
price  of  the absorbent, the low-sulfur nature of  the coal and the  low
S02 removal requirements preclude changes from the base-case costs from
significantly  changing  the economic results.  The lime spray dryer
process has lower first-year annual revenue requirements regardless of
the lime  costs selected (within  the -20% to +40%  range).  For example, a
40% increase in the  delivered cost of lime results in only a 2.2%
increase  in the first-year annual revenue requirements for the lime
spray  dryer process.  This is still 5% less than  the first-year annual
revenue requirements  for the base-case soda ash spray dryer process and
11% less  than  the first-year annual revenue requirements for the base-
case limestone scrubbing process.
                                  205

-------
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     The soda ash spray dryer process is slightly more sensitive to the
delivered price of the raw material because of the higher unit cost of
soda ash.  A 40% increase in the delivered cost of soda ash increases
the first-year annual revenue requirements for the soda ash spray dryer
process about 3.2%.  This is still about 1% less than the limestone
scrubbing process.

     The limestone scrubbing process, because of the low unit cost of
limestone as well as the lower sulfur level in the coal and the lower
SC>2 removal requirements, is essentially insensitive to the delivered
cost of limestone (a 40% increase in cost results in only a 0.3% increase
in first-year annual revenue requirements).

Sensitivity to Raw Material Stpichipmetry

     The sensitivity analysis for the low-sulfur western coal compares
only the lime spray dryer process and the limestone scrubbing process
since the soda ash spray dryer process usually approaches 100% absorbent
utilization.  Table 50 lists both the base-case and the alternative
stoichiometries used in the sensitivity analysis.  The stoichiometries
given are in moles of alkali per mole of SC>2 absorbed.  The range of
stoichiometries shown for the lime spray dryer process is 1.1 (-10%) to
1.46 (19.7%).

     Many of the processing areas that are dependent on the absorbent
flow rate contribute only minor amounts to the capital investment.  For
example, a 20% increase in absorbent flow rate increases the capital
investment about 1%.  The annual revenue requirements for the lime spray
dryer process are somewhat more sensitive to the absorbent stoichiometry
than to the absorbent cost.  For example, a 20% increase in the absorbent
stoichiometry results in a 2.0% increase in first-year revenue requirements.
However, from these results (as shown in Figure 36) it is apparent that
stoichiometry changes over a wide range will have little effect on the
capital investment and annual revenue requirement relationships of the
two processes for this low-sulfur western coal case.
LOW-SULFUR EASTERN COAL CASE—CAPITAL INVESTMENT

Results

     The capital investment for the lime spray dryer process for the
low-sulfur eastern coal application is $75.3M ($151/kW) in mid-1982
dollars as shown in Table 51.  The capital investment for the limestone
scrubbing process is $92.6M ($185/kW) as shown in Table 52.

Comparison

     The direct investment and the total capital investment for the two
FGD systems are shown in Table 53.  The lime spray dryer process is
substantially less (19%) capital intensive than the limestone scrubbing
process for this low-sulfur eastern coal case.

                                  207

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Ki
o
00
                                    TABLE  50.   LOW-SULFUR WESTERN COAL CASE


                             COMPARISON  OF CAPITAL  INVESTMENT  AND FIRST-YEAR UNIT


                             REVENUE REQUIREMENTS FOR  THE LIME SPRAY  DRYER PROCESS


                                    AT VARIOUS  RAW  MATERIAL  STOICHIOMETRIES



Process
Lime spray dryer


Limestone scrubbing


Raw material
stoichiometry
Variation Value3 % changeb
Low
Base
High
Base
1.1 -10
1.22
1.46 19.7
1.12
Total
capital investment
$/kW % changeb
153.3 -0.58
154.2
156.1 1-23
176.1
First-year
unit
revenue requirements
mills /kWh %
6.85
6.92
7.06
7.90
changeb
-1.01
-
2.02
-

           a.   Raw material stoichiometry is  defined as  mols  of alkali per mol of S02 absorbed.
           b.   Change is calculated relative  to the  base-case value.

-------
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           TABLE  51.   LOW-SULFUR EASTERN  COAL  CASE


                        CAPITAL INVESTMENT

                    LIME SPRAY DRYER  PROCESS


             (500-MW new coal-fired unit, 0.7% S  in coal;
               70%  SC>2  removal; onsite solids disposal)


                                                        Investment, k$

Direct Investment

Material handling                                            1,762
Feed preparation                                               909
Gas handling                                                 9,770
S02 absorption                                               7,336
Particulate removal                                         11,523
Particulate handling                                           753

     Total process  capital

Services, utilities, and miscellaneous

     Total direct investment excluding landfill

Solids disposal
Landfill construction

     Total direct investment                                 37,770


Indirect Investment

Engineering design and  supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency

     Total fixed investment                                  57,949


Other Capital Investment

Allowance for startup and modifications
Interest during construction
Royalties
Land
Working capital

     Total capital investment                                75,303

Dollars of total capital per kW of generation capacity       150.61
Basis
  Midwest plant location represents project beginning mid-1980, ending
   mid-1983.  Average cost  basis  for  scaling, mid-1982.
  Minimum in-process storage,  redundant scrubber train, and pumps are
   spared.
  Landfill located one mile from  power plant.
  FGD process investment begins at boiler air heater exit.  Stack plenum
   and stack excluded.
  Only nominal construction overtime  included.

                                  210

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        TABLE 52.   LOW-SULFUR EASTERN  COAL CASE


                     CAPITAL  INVESTMENT


  \             LIMESTONE  SCRUBBING PROCESS
   \
    \      (500-MW new  coal-fired power unit, 0.7% S  in coal;
               70% S02 removal; onsite solids disposal)


                                                        Investment, k$

Direct Investment

Material handling                                            1,011
Feed preparation                                             1,944
Particulate removal                                         11,688
Gas handling                                                11,665
S02 absorption                                              15,597
Stack gas reheat                                             1,225
Solids separation                                            1,846

     Total process capital                                   44,976

Services, utilities, and miscellaneous                        2,699

     Total direct investment  excluding landfill              47,675

Solids disposal                                                743
Landfill construction                                         2,625

     Total direct investment                                 51,043


Indirect Investment

Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency

     Total fixed investment                                  72,573


Other Capital Investment

Allowance for startup  and modifications                       5,454
Interest during construction                                 11,205
Royalties
Land                                                           795
Working capital                                              2.590

     Total capital investment                               92,617

Dollars of total capital per  kW of  generation capacity       185.23
Basis
  Midwest plant location  represents project beginning in early 1981  and
   ending in late 1983.   Average cost basis for scaling, mid-1982.
  Minimum in-process  storage, redundant scrubber train and feed prepara-
   tion area, pumps spared.
  Disposal area located one mile from power plant.
  FGD process investment  begins at boiler air heater exit.  Stack plenum
   and stack excluded.
  Only nominal construction overtime included.

                                211

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                 TABLE 53.   LOW-SULFUR EASTERN  COAL  CASE

               DIRECT INVESTMENTS  AND  CAPITAL INVESTMENTS

Direct
investment
Process
Lime spray dryer
Limestone scrubbing
M$
37.8
51.0
$/kW
75.5
102.1
Total
capital
investment
M$
75.3
92.6
$/kW
150.6
185.2

     The major investment differences between the lime spray dryer
process and the limestone scrubbing process are in the S02 absorption
and gas handling areas as shown in Table 54.  Other less significant
differences are in the feed preparation, stack gas reheat, material
handling, and particulate handling/solids separation areas.  With the
exception of the material handling area, the limestone scrubbing process
costs are higher than those for the corresponding areas in the lime
spray dryer process.  The investment difference in the S02 absorption
area alone is about $8.2M.  The use of a spray dryer as an absorber
results in a less expensive area cost since it eliminates the need for
large slurry recirculating tanks and pumps, mist eliminators, and the
forced-oxidation equipment which are required in the limestone scrubbing
process.  The gas handling area is substantially higher for the limestone
scrubbing process primarily because of the requirement for additional
ductwork costs for bypassing some of the flue gas around the scrubber
area to the stack plenum rather than the individual scrubber bypass
which is used in the lime spray dryer process.  The higher investment
for the solids separation area in the limestone scrubbing process, as
compared with the particulate handling area in the lime spray dryer
process, is due to the nature of the wastes.  The FGD waste from the
lime spray dryer process is collected dry and is simply conveyed to a
storage silo before being trucked to the landfill (there is no waste
recycle).  The FGD waste from the limestone slurry is pumped through a
thickener and a filter and conveyed to a storage pile before being
trucked to a landfill.

     The investment for the feed preparation area is slightly higher for
the limestone scrubbing process while the solids disposal equipment
cost, landfill construction cost, and land cost are slightly higher for
the lime spray dryer process.  The material handling area cost for the
lime spray dryer process is higher than the equivalent limestone scrubbing
area because of the need to store lime in silos rather than in a pile,
as is the case with limestone.
                                 212

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                TABLE 54.  LOW-SULFUR EASTERN COAL CASE

                  SUMMARY OF THE CAPITAL INVESTMENTS


                                         Total cost, k$
               Investment area
   Lime
spray dryer
  process
Limestone
scrubbing
 process
         Material handling               1,762       1,011
         Feed preparation                  909       1,944
         Gas handling                    9,770      11,665
         S02 absorption                  7,336      15,597
         Stack gas reheat                  -         1,225
         Particulate removal            11,523      11,688
         Particulate handling              753
         Solids separation                 -         1,846
         Solids disposal                   855         743
         Landfill construction           2,939       2,625
         Land                              905         795
         All other capital costs        38,551      43,478

            Total capital investment    75,303      92,617
         Basis:   TVA design and economic premises
     In order to facilitate comparisons of the economic results with
those from other EPA-sponsored evaluations, the capital investments for
each process are presented in a slightly different form in Table 55.  In
this table the total capital investment is broken down into three areas:
S02 absorption, particulate removal, and waste disposal.  Each area
includes not only the direct investment for equipment, piping, electrical
equipment, etc., but also its pro rata share of the indirect investments
and all other capital charges.  Previously identified direct investment
areas grouped in the SOo absorption area are:  material handling, feed
preparation, gas handling, and S02 absorption.  The particulate removal
area consists only of the original particulate removal area.  The waste
disposal area combines the particulate handling, solids separation,
solids disposal, and landfill/pond construction.
LOW-SULFUR EASTERN COAL CASE—ANNUAL REVENUE REQUIREMENTS

Results

     The first-year annual revenue requirements for the lime spray dryer
process are $18.67M in 1984 dollars as shown in Table 56.  This corresponds
to a first-year unit revenue requirement of 6.79 mills/kWh.  Equivalent
levelized annual revenue requirements for the lime spray dryer process

                                  213

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             TABLE 56.   LOW-SULFUR EASTERN  COAL CASE

                     ANNUAL REVENUE  REQUIREMENTS

                      LIME  SPRAY  DRYER  PROCESS
               (500-MW new coal-fired power unit, 0.7% S in coal;
                    70% S02 removal; onsite solids disposal)
Direct Costs  -  First-Year

Raw materials
  Lime

     Total raw  material cost

Conversion costs
  Operating labor  and supervision
    FGD
    Solids disposal
  Utilities
    Fuel
    Process water
    Electricity
  Maintenance
    Labor and material
  Analysis

     Total conversion costs

     Total direct  costs
                                       Annual
                                      quantity
                      Unit
                     cost. $
    11,300  tons
    25,400  man-hr
    30,505  man-hr

   205,625  gal
   150,821  kgal
39,410,135  kWh
             Total annual
                cost. k$
75.00/ton
15.00/man-hr
21.00/man-hr

 1.60/gal
 0.14/kgal
 0.037/kWh
     4,199  man-hr   21.00/man-hr
  848

  848
  381
  641

  329
   21
1,458

2,058
	88

4,976

5,824
Indirect Costs  -  First-Year

Overheads
  Plant and administrative
     Total first-year operating and maintenance costs

Levelized capital charges (14.7% of
 total capital investment)

     Total first-year annual revenue requirements

Levelized first-year operating and maintenance
 costs (1.886 first-year 0 and M)

Levelized capital charges (14.7% of
 total capital investment)

     Levelized annual revenue requirements
                                     7,512
                                    14,168
First-year annual revenue requirements
Levelized annual revenue requirements
              18.58
              25.24
 Mills/kWh

   6.76
   9.18
Basis
  Midwest plant location,  1984 revenue requirements.
  Remaining life of power  plant, 30 years.
  Power unit onstream time, 5,500 years.
  Coal burned, 1,116,500 tons/yr, 9,500 Btu/kWh.
  Total direct investment, $37,770,000; total fixed investment, $57,949,000; and
   total capital investment, $75,303,000.

                                      214

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are $25.40M, or 9.24 mills/k¥h.  The first-year revenue requirements for
the limestone scrubbing process are $22.87M as shown in Table 57.  This
is equivalent to a first-year unit revenue requirement of 8.34 mills/kWh.
Levelized annual revenue requirements are $31.21M, or 11.35 mills/kWh.
                TABLE 55.   LOW-SULFUR EASTERN COAL CASE

                           CAPITAL INVESTMENTS

Area
SO- absorption
Particulate removal
Waste disposal
Investment,
Lime
spray dryer
process
85.63
48.84
16.13
$/kW
Limestone
scrubbing
process
121.93
44.56
18.72
                Capital
                 investment          150.60        185.21
             Basis:   TVA design and economic premises
Comparison

     The first-year and the levelized' annual revenue requirements for
both the lime spray dryer and the limestone scrubbing processes are
given in Table 58.  In both first-year and levelized annual revenue
requirements the lime spray dryer process is substantially lower (19%
lower) in cost than the limestone scrubbing process.


               TABLE 58.  LOW-SULFUR EASTERN COAL CASE

         FIRST-YEAR AND LEVELIZED ANNUAL REVENUE REQUIREMENTS
                             First-year           Levelized annual
                         revenue requirements
Process
Lime spray dryer
Limestone scrubbing
M$
18.58
22.95
Mills /kWh
6.76
8.34
M$
25.24
31.21
Mills /kWh
9.18
11.35
                                 215

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            TABLE 57.   LOW-SULFUR EASTERN  COAL CASE

                    ANNUAL REVENUE  REQUIREMENTS

                    LIMESTONE SCRUBBING PROCESS
              (500-MW new coal-fired power unit, 0.7% S in coal;
                   70% S02 removal; onsite solids disposal)

Direct Costs - First-Year
Raw materials
Limestone
Annual
quantity
18,400 tons
Unit
cost, $
8. 50 /ton
Total annual
cost, k$
156
     Total  raw material cost

Conversion  costs
  Operating labor and supervision
    FGD
    Solids  disposal
  Utilities
    Fuel
    Steam
    Process water
    Electricity
  Maintenance
    Labor and material
  Analysis

     Total  conversion costs

     Total  direct costs
40,110 man-hr
27,276 man-hr
151,250 gal
93,780 klb
125,097 kgal
41,015,749 kWh
15. 00 /man-hr
21.00/man-hr
1.60/gal
2.50/klb
0.14/kgal
0.037/kWh
3,329 man-hr   21.00/man-hr
                                                                        156
                  602
                  573

                  242
                  234
                   18
                1,518

                3,355
                	70

                6,612

                6,768
Indirect Costs - First-Year

Overheads
  Plant and administrative

     Total first-year operating and maintenance costs

Levelized capital charges (14.7% of
 total capital investment)

     Total first-year annual revenue requirements

Levelized first-year operating and maintenance
 costs (1.886 first-year 0 and M)

Levelized capital charges (14.7% of
 total capital investment)

     Levelized annual revenue requirements
                               17,598
First-year annual  revenue requirements
Levelized annual revenue requirements
         22.95
         31.21
Mills/kWh

   8.34
  11.35
Basis
  Midwest plant  location, 1984 revenue requirements.
  Remaining life of power plant, 30 years.
  Power unit onstream time, 5,500 hr/yr.
  Coal burned,  1,116,500 tons/yr, 9,500 Btu/kWh.
  Total direct  investment, $51,043,000; total  fixed investment, $72,573,000;  and
   total capital investment, $92,617,000.

                                     216

-------
     Table 59 compares the various cost components of the first-year
annual revenue requirements for each process.   With the exception of the
raw material and the "all other" categories,  the limestone scrubbing
process has the higher annual cost.  From Table 59 it is apparent that
the limestone scrubbing process has higher revenue requirements primarily
because of higher annual costs in the same three areas as the other coal
cases:  levelized capital charges, maintenance costs, and overhead
costs.  These areas alone are about $4.7M higher in the limestone scrubbing
process than the lime spray dryer process.
               TABLE  59.   LOW-SULFUR EASTERN  COAL  CASE

           SUMMARY  OF FIRST-YEAR ANNUAL REVENUE REQUIREMENTS


                                         Total cost, k$
                  Annual cost
   Lime      Limestone
spray dryer  scrubbing
  process	process
          Raw material                      848          156
          Operating  labor  and              1,022        1,175
           supervision
          Electricity                      1,458        1,518
          Steam                             -            234
          Maintenance                      2,058        3,355
          Overheads                        1,688        2,563
          Levelized  capital charges       11,070       13,615
          All other                          438          330

             Total first-year annual      18,582       22,946
              revenue  requirements
          Basis:   TVA design and economic premises
     The higher levelized capital charge for the limestone scrubbing
process is due to its higher capital investment.  Maintenance costs are
much higher for the limestone scrubbing process because of the maintenance
for equipment needed to handle and grind the limestone and also to
handle and recirculate large quantities of the erosive slurry.  Overheads
are higher primarily because of the higher maintenance costs for the
limestone scrubbing process.

     Other somewhat higher costs for the limestone scrubbing process
include operating labor, steam, and electricity.  Operating labor is
higher because of the operation of additional equipment.  The steam
consumption is for supplemental reheat (only a small reheater is required
for this coal case) which the spray dryer process is claimed not to need.
Electrical costs are somewhat higher because of the large pumps required
to recirculate the slurry.

                                  217

-------
     The raw material cost is the only major category in which the lime
spray dryer process is higher than the limestone scrubbing process.
This higher raw material cost in the lime spray dryer process is primarily
due to the higher unit cost for lime ($75/ton for lime versus $8.50/ton
for limestone) and also because a higher stoichiometry is used with the
lime spray dryer process.  The effects on the first-year annual revenue
requirements of changing the unit cost of the raw material and also the
raw material stoichiometry are discussed in the next section in the form
of a sensitivity analysis.
LOW-SULFUR EASTERN COAL CASE—SENSITIVITY ANALYSIS

Sensitivity to Raw Material Prices

     The sensitivity of the first-year annual revenue requirements for
the lime spray dryer process and the limestone scrubbing process to the
delivered absorbent cost was calculated for the range of costs listed in
Table 60.  The results of this sensitivity analysis are shown in Figure 37,

                TABLE 60.  LOW-SULFUR EASTERN COAL CASE

          DELIVERED UNIT RAW MATERIAL COSTS ASSUMED FOR THE

                         SENSITIVITY ANALYSIS

Process Raw material
Lime spray dryer Lime


Limestone scrubbing Limestone


Variation
Low
Base
High
Low
Base
High
$/ton
60.00
75.00
105.00
7.00
8.50
12.00
% change
-20
-
+40
-20
-
+40

     Although the lime spray dryer process is more sensitive than the
limestone scrubbing process to changes in the delivered price of the
absorbent, because of the low-sulfur nature of the coal and the low SOo
removal requirement the changes from the base case costs do not signifi-
cantly change the economic results.  The lime spray dryer process has
lower first-year annual revenue requirements regardless of the absorbent
prices selected (within the -20%, +40% range).  For example, a 40%
increase in the delivered cost of lime results in only a 1.8% increase
in the first-year annual revenue requirements for the lime spray dryer
process which is still 18% less than the first-year annual revenue
requirements for the base case limestone scrubbing process.
                                  218

-------
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     The limestone scrubbing process,  due to the low unit cost of lime-
stone as well as the lower sulfur level in the coal and the lower SC^
removal requirements, is essentially insensitive to the delivered cost
of limestone.  A 40% increase in the cost of limestone results in only a
0.4% increase in the first-year annual revenue requirements for the
limestone scrubbing process.

Sensitivity to Raw Material Stoichiometry

     Table 61 lists both the base case and the alternative stoichiometries
used in the sensitivity analysis for the low-sulfur eastern coal.  (The
raw material stoichiometries are given as moles of alkali per mole of
SC>2 absorbed.)  The range of stoichiometries for the lime spray dryer
process is 1.17 (-10%) to 1.56 (20%).   The results are shown in Figure 38.

     Since many of the processing areas that are dependent on the absorbent
flow rate contribute only minor amounts to the capital investment, a 20%
increase in absorbent flow rate increases the capital investment only
about 1%.  The annual revenue requirements for the lime spray dryer
process are somewhat more sensitive to the absorbent Stoichiometry than
to the absorbent cost.  For example, a 20% increase in the raw material
Stoichiometry results in a 1.9% increase in first-year revenue requirements,
However, from these results it is apparent that Stoichiometry changes
over a wide range will have little effect on the capital investment and
annual revenue requirement relationships of the two processes.
HIGH-SULFUR EASTERN COAL CASE—CAPITAL INVESTMENT

Results

     The capital investment for the lime spray dryer process for the
high-sulfur eastern coal application is $100.1M ($200/kW) in mid-1982
dollars as shown in Table 62.  The capital investment for the limestone
scrubbing process is $122.OM ($244/kW) as shown in Table 63.
     The direct investment and the total capital investment for the two
FGD systems are shown in Table 64.  The lime spray dryer process is
substantially  (about 18%) less capital intensive than the limestone
scrubbing process for this high-sulfur eastern coal case.

     The primary investment difference between the lime spray dryer
process and the limestone scrubbing process is in the S02 absorption
area,  as shown in Table 65.  As was previously discussed in the other
comparison sections, the large difference in investment in the S02
absorption area ($12.6M) is due to the use of the spray dryer as the
absorber.  Other major differences between the processes are in the
material handling and particulate handling/solids separation areas.
Again,  the reasons  for the large investment differences in these areas
                                  220

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                         TABLE 61.   LOW-SULFUR EASTERN COAL CASE

                  COMPARISON OF CAPITAL INVESTMENT AND FIRST-YEAR UNIT

                 REVENUE REQUIREMENTS FOR THE LIME SPRAY DRYER PROCESS

                         AT VARIOUS RAW MATERIAL STOICHIOMETRIES

Raw material
stoichiometry
Process
Lime spray dryer
Limestone scrubbing
Variation
Low
Base
High
Base
Value3 % change13
1.17 -10
1.30
1.56 20
1.12
Total
capital investment
$/kW % change13
149.6 -0.69
150.6
152.7 1.37
185.2
First-year unit
revenue requirements
mills/kWh
6.69
6.76
6.89
8.32
% change"
-1.04
1.92
—
a.  Raw material stoichiometry is defined as mols of alkali per mol of S02 absorbed.
b.  Change is calculated relative to the base-case value.

-------
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          TABLE 62.   HIGH-SULFUR  EASTERN COAL  CASE


                       CAPITAL  INVESTMENT


                   LIME  SPRAY  DRYER PROCESS

            (500-MW new coal-fired unit,  3.5% S in coal;
              88.6% SC>2 removal;  onsite solids disposal)


                                                        Investment, k$

Direct Investment

Material handling
Feed preparation
Gas handling
SC>2 absorption
Particulate removal
Particulate handling

     Total process capital

Services, utilities, and miscellaneous

     Total direct investment excluding landfill

Solids disposal                                               1,443
Landfill construction                                         4,899

     Total direct investment                                 50,094


Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Contingency

     Total fixed investment                                  76,517
Other Capital Investment

Allowance for startup and modifications                        6,825
Interest during construction                                 11,712
Royalties                                                       413
Land                                                          1,520
Working capital                                               3,109

     Total capital investment                                100,096

Dollars of total capital per kW  of generation capacity        200.19
Basis
  Midwest plant location represents project beginning mid-1980, ending
   mid-1983.   Average cost basis for scaling, mid-1982.
  Minimum in-process storage, redundant scrubber train, and pumps are
   spared.
  Landfill located one mile  from power plant.
  FGD process investment begins"! at boiler air heater exit.  Stack plenum
   and stack  excluded.
  Only nominal construction  overtime included.

                                 223

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        TABLE 63.  HIGH-SULFUR  EASTERN  COAL  CASE


                     CAPITAL  INVESTMENT


                 LIMESTONE SCRUBBING  PROCESS


          (500-MW new coal-fired power unit, 3.5% S  in coal;
              89.6% S02 removal; onsite solids disposal)


                                                        Investment, k$

Direct Investment

Material handling
Feed preparation
Particulate removal
Gas handling
S02 absorption
Stack gas reheat
Solids separation

     Total process  capital

Services, utilities, and miscellaneous

     Total direct investment excluding landfill

Solids disposal                                              1,007
Landfill construction                                         3,A41

     Total direct investment                                 67,080


Indirect Investment

Engineering design  and supervision                            4,453
Architect and engineering contractor                          1,287
Construction expense                                         10,296
Contractor fees                                              3,304
Contingency                                                  8,940

     Total fixed  investment                                  95,360


Other Capital Investment

Allowance for startup and modifications                       7,165
Interest during construction                                 14,719
Royalties                                                      -
Land                                                         1,070
Working capital                                              3,639

     Total capital  investment                               121,953

Dollars of total  capital per kW  of generation capacity       243.91
Basis
  Midwest plant location represents project beginning in early 1981 and
   ending in late 1983.   Average  cost basis for scaling, mid-1982.
  Minimum in-process storage,  redundant scrubber train and feed prepara-
   tion area, pumps spared.
  Disposal area located one  mile  from power plant.
  FGD process investment begins at boiler air heater exit.  Stack plenum
   and stack excluded.
  Only nominal construction  overtime included.

                                224

-------
have been previously discussed.  The higher landfill construction cost
for the lime spray dryer process results from the lower density of the
FGD waste in the landfill when compared with the gypsum waste from the
limestone scrubbing process.  This is the same reason that the solids
disposal area investment and the land costs for the lime spray dryer
process are somewhat higher than those for the limestone scrubbing
process.


                TABLE 64.  HIGH-SULFUR EASTERN COAL CASE

               DIRECT INVESTMENTS AND CAPITAL INVESTMENTS

Process
Lime spray dryer
Limestone scrubbing
Direct
investment
M$ $/kW
50.1 100.2
67.1 134.2
Capital
investment
M$ $/kW
100.1 200.2
122.0 243.9

           Basis:  TVA design and economic premises
               TABLE 65.  HIGH-SULFUR EASTERN COAL CASE
                  SUMMARY OF THE CAPITAL INVESTMENTS
                                          Total cost, k$
                Investment area
   Lime
spray dryer
  process
Limestone
scrubbing
 process
          Material handling
          Feed preparation
          Gas handling
          S02 absorption
          Stack gas reheat
          Particulate removal
          Particulate handling
          Solids separation
          Solids disposal
          Landfill construction
          Land
          All other capital costs
    5,014
    2,438
   11,456
    9,018

   11,235
    2,114

    1,443
    4,899
    1,520
   50,959
             Total capital investment    100,096
  2,518
  4,618
 13,653
 21,625
  3,325
  9,998

  3,350
  1,007
  3,441
  1,070
 57,348

121,953
          Basis:  TVA design and economic premises
                                   225

-------
     In order to facilitate comparisons with other EPA-sponsored eval-
uations, the capital investments for each process are presented in a
slightly different form in Table 66.  In this table the total capital
investment is broken down, into three areas:  SC>2 absorption, particulate
removal, and waste disposal.  Each area includes the direct investment
for equipment, piping, electrical equipment, etc., and also its pro
rata share of the indirect investments and all other capital charges.
Previously identified direct investment areas grouped in the S02 absorption
area are:  material handling, feed preparation, gas handling, and SC>2
absorption.  The particulate removal area consists only of the original
particulate removal area.  The waste disposal area combines the particulate
handling, solids separation, solids disposal, and landfill/pond construction.
               TABLE 66.  HIGH-SULFUR EASTERN COAL CASE

                          CAPITAL INVESTMENTS

Area
SC>2 absorption
Particulate removal
Waste disposal
Investment, $/kW
Lime Limestone
spray dryer scrubbing
process process
121.94 177.83
47.62 38.12
30.62 27. 95
              Capital
               investment           200.18        243.90
           Basis:  TVA design and economic premises



HIGH-SULFUR EASTERN COAL CASE—ANNUAL REVENUE REQUIREMENTS

Results

     The first-year annual revenue requirements for the lime spray dryer
process are $31.89M in 1984 dollars, as shown in Table 67.  This corresponds
to a first-year unit revenue requirement of 11.60 mills/kWh.  Levelized
annual revenue requirements for the lime spray dryer process are $47.11M,
or 17.13 mills/kWh.  The first-year annual revenue requirements for the
limestone scrubbing process are $32.38M as shown in Table 68.  Equivalent
unit revenue requirements are 11.78 mills/kWh.  Levelized annual revenue
requirements are $45.34M, or 16.49 mills/kWh.
                                  226

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           TABLE 67.   HIGH-SULFUR EASTERN COAL  CASE

                    ANNUAL REVENUE  REQUIREMENTS

                      LIME SPRAY  DRYER  PROCESS
               (500-MW new coal-fired power unit,  3.5% S in coal;
                  88.6% SC>2 removal; onsite solids  disposal)
Direct Costs  -  First-Year

Raw materials
  Lime

     Total raw  material  cost

Conversion costs
  Operating labor and  supervision
    FGD
    Solids disposal
  Utilities
    Fuel
    Process water
    Electricity
    Boiler heat loss
  Maintenance
    Labor and material
  Analysis

     Total conversion  costs

     Total direct costs
                                       Annual
                                      quantity
                      Unit
                     cost, $
            Total annual
               cost, k$
   112,400  tons    75.00/ton
    29,120 man-hr  15.00/man-hr
    36,429 man-hr  21.00/man-hr
   408,125  gal
   143,636  kgal
42,767,100  kWh
   137,400  MBtu
1.60/gal
0.14/kgal
0.037/kWh
3.32/MBtu
     4,238 man-hr   21.00/man-hr
                 8,430

                 8,430
   437
   765

   653
    20
 1,582
   456

 2,649
	89

 6,651

15,081
Indirect Costs - First-Yea_r

Overheads
  Plant and administrative

     Total first-year operating  and maintenance cost

Levelized capital charges  (14.7% of
 total capital investment)

     Total first-year annual  revenue requirements

Levelized first-year operating and maintenance
 costs (1.886 first-year 0 and M)

Levelized capital charges  (14.7% of
 total capital investment)

     Levelized annual revenue requirements
First-year annual revenue requirements
Levelized annual revenue requirements
             31.89
             47.11
Mills/kWh

  11.60
  17.13
                                   32,398


                                   14,714

                                   47,112
Basis
  Midwest plant location,  1984  revenue requirements.
  Remaining life of power  plant,  30 years.
  Power unit onstream time,  5,500 years.
  Coal burned, 1,116,500 ton/yr,  9,500 Btu/kWh.
  Total direct investment,  $50,094,000; total fixed investment,  $76,517,000; and
   total capital investment, $100,096,000.

                                       227

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         TABLE  68.   HIGH-SULFUR EASTERN COAL  CASE

                   ANNUAL REVENUE  REQUIREMENTS

                   LIMESTONE SCRUBBING  PROCESS
              (500-MW  new coal-fired power unit, 3.5% S in  coal;
                  89.6% S02 removal; onsite solids disposal)

Direct Costs - First-Year
Raw materials
Limestone
Total raw material cost
Conversion costs
Operating labor and supervision
FGD
Solids disposal
Utilities
Steam
Fuel
Process water
Electricity
Maintenance
Labor and material
Analysis
Total conversion costs
Total direct costs
Annual
quantity


132,600 tons



43,860 man-hr
32,546 man-hr

532,000 klb
254,562 gal
188,194 kgal
65,613,193 kWh


4,988 man-hr


Unit Total annual
cost, $ cost, k$


8.50/ton



15.00/man-hr
21.00/man-hr

2.50/klb
1.60/gal
0.14/kgal
0.037/kWh


21.00/man-hr




1,127
1,127


658
683

1,330
407
26
2,428

4,404
105
10,041
11,168
     Levelized annual revenue  requirements
                                              M$    Mills/kWh
Indirect  Costs - First-Year

Overheads
  Plant  and administrative


     Total first-year operating and maintenance  costs

Levelized capital charges  (14.7% of
 total capital investment)

     Total first-year annual  revenue requirements

Levelized first-year operating and maintenance
 costs (1.886 first-year 0 and M)                                     27,266

Levelized capital charges  (14.7% of
 total capital investment)
First-year annual revenue requirements          32.38    11.78
Levelized annual revenue requirements           45.19    16.43


Basis
  Midwest plant location, 1984 revenue requirements.
  Remaining life of power plant,  30 years.
  Power unit onstream time,  5,500 hr/yr.
  Coal burned, 1,116,500 tons/yr, 9,500 Btu/kWh.
  Total direct investment, $67,080,000; total fixed investment, $95,360,000; and
   total capital investment,  $121,953,000.

                                         228

-------
Comparison

     The first-year and the levelized annual revenue requirements for
each of the FGD processes are shown in Table 69.  The lime spray dryer
process is approximately 2% lower in cost (11.60 mills/kWh versus 11.78
mills/kWh for the first-year) than the limestone scrubbing process in
both first-year costs annual revenue requirements.  However in terms of
levelized annual revenue requirements the lime spray dryer is about 4%
higher than the limestone scrubbing process.  This is due to the higher
ratio of operating and maintenance costs to capital charges in the lime
spray dryer process.  When levelized the costs for the lime spray dryer
process are increased proportionally more than those of the limestone
process.
                TABLE 69.  HIGH-SULFUR EASTERN COAL CASE

          FIRST-YEAR AND LEVELIZED ANNUAL REVENUE REQUIREMENTS
                           First-year  annual       Levelized annual
                         revenue requirements   revenue requirements
Process
Lime spray dryer
Limestone scrubbing
M$
31.89
32.38
Mills/kWh
11.60
11.78
M$
47.11
45.19
Mills/kWh
17.13
16.43
   Basis:  TVA design and economic premises
     Table 70 compares the various component costs of the first-year
revenue requirements for both processes.  The major cost differences are
the capital charges and raw materials.  However, the raw materials cost
difference, in which the lime spray dryer process is about $7.3M higher,
is somewhat balanced by the difference in levelized capital charges, in
which the limestone scrubbing process is about $3.2M higher.  Other
significant differences are the costs for maintenance, overheads, steam,
and electricity.  The limestone scrubbing process has higher costs for
all three.  Maintenance costs are calculated as a percentage of direct
investment (which is higher for the limestone scrubbing process).  The
limestone scrubbing process involves grinding the makeup limestone and
handling and recirculating large quantities of an erosive limestone
slurry.  The lime spray dryer process involves only slaking the lime and
pumping the resulting slurry to the spray dryer.  There are no large
recirculating pumps handling large quantities of slurry.  This lack of
large recirculating pumps for the lime spray dryer process is also the
primary reason that the electrical cost is much lower in the lime spray
dryer process.  Since the overheads are charged based on the operating
labor and maintenance costs and the maintenance costs for the limestone
scrubbing process are much higher than for the lime spray dryer process,

                                  229

-------
the overhead costs for the limestone scrubbing process are significantly
higher ($1.2M).  Steam costs are higher in the limestone scrubbing process
because of the need for full stack gas reheat.
              TABLE  70.  HIGH-SULFUR EASTERN COAL CASE

           SUMMARY  OF FIRST-YEAR ANNUAL REVENUE REQUIREMENTS


                                         Total cost, k$

Raw
Opei
Item
materials
rating labor and
Lime
spray dryer
process
8,430
1,202
Limestone
scrubbing
process
1,127
1,341
           supervision
          Electricity                     1,582       2,428
          Steam                             -         1,330
          Maintenance                     2,649       4,404
          Overheads                       2,097       3,289
          Levelized capital charges      14,714      17,927
          Other annual costs              1,218         538_

             Total first-year annual     31,892      32,384
              revenue requirements
          Basis:  TVA design and economic premises
HIGH-SULFUR EASTERN COAL CASE—SENSITIVITY ANALYSIS

Sensitivity to Absorbent Prices

     The sensitivity of the first-year annual revenue requirements for
the lime spray dryer process and the limestone scrubbing process to the
delivered absorbent cost was calculated for the range of absorbent costs
listed in Table 71.  The results of this sensitivity analysis are shown
in Figure 39.

     The lime spray dryer process is more sensitive than the limestone
scrubbing process to changes in the delivered cost of the absorbent.
Depending on the lime cost assumed the lime spray dryer process can have
first-year annual revenue requirements which are lower, the same, or
higher than the limestone scrubbing process.  For example, a 20% decrease
in the delivered cost of lime results in a 5.3% decrease in the first-
year annual revenue requirements for the lime spray dryer process, which
are then about 7% less than the first-year annual revenue requirements
for the base case limestone scrubbing process.  For a 40% increase in
                                    230

-------
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-------
the delivered cost of lime,  the first-year annual revenue requirements
for the lime spray dryer process increase 10.7% and are about 9% higher
than the limestone scrubbing process.
                TABLE 71.  HIGH-SULFUR EASTERN COAL CASE

           DELIVERED UNIT RAW MATERIAL COSTS ASSUMED FOR THE

                          SENSITIVITY ANALYSIS



        Process          Raw material   Variation    $/ton   % change
Lime spray dryer Lime


Limestone scrubbing Limestone


Low
Base
High
Low
Base
High
60.00
75.00
105.00
7.00
8.50
12.00
-20
-
+40
-20
-
+40

     The limestone scrubbing process,  'due to the low unit cost of limestone,
is essentially insensitive to the delivered cost of limestone.  A 40%
increase in the cost of limestone results in only a 1.4% increase in the
first-year annual revenue requirements for the limestone scrubbing
process.

Sensitivity to Absorbent Stoichiometry

     Since the lime spray dryer process technology has only been demon-
strated on a pilot-plant scale and then primarily with low-sulfur
coals, the assumed Stoichiometry in the spray dryer could change as the
spray dryer technology is developed further.  In addition,  the required
lime Stoichiometry for two 3.5% sulfur coals could change depending on
the actual coal being burned.  Therefore, a sensitivity analysis, showing
the changes in total first-year revenue requirements as the absorbent
Stoichiometry has been included.

     Table 72 lists both the base case and the alternative stoichiom-
etries used in the sensitivity analysis.  (The raw material stoichiom-
etries are given as moles of alkali per mole of S02 absorbed.)  The
range of stoichiometries for the lime  spray dryer process is 1.62 (-10%)
to 2.16 (20%).  The results are shown  in Figure 40.

     Since many of the processing areas that are dependent on the absorbent
flow rate contribute only minor amounts to the capital investment, a 20%
increase in absorbent flow rate increases the capital investment only

                                  232

-------
N3
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                                  TABLE 72.  HIGH-SULFUR EASTERN COAL CASE


                            COMPARISON OF CAPITAL INVESTMENT AND FIRST-YEAR UNIT


                            REVENUE REQUIREMENTS FOR THE LIME SPRAY DRYER PROCESS


                                   AT VARIOUS RAW MATERIAL STOICHIOMETRIES

Raw material
stoichiometry
Process
Lime spray dryer
Limestone scrubbing
Variation
Low
Base
High
Base
Valuea
1.62
1.80
2.16
1.30
% change^3
-10
20
-
Total First-year unit
capital investment revenue requirements
$/kW
196.9
200.2
206.6
243.9
% changeb mills /k¥h % changeb
-1.65 11.18 -3.62
11.60
3.20 12.47 7.50
11.78

          a.  Raw material stoichiometry is defined as mols  of  alkali  per mol of  S02  absorbed.
          b.  Change  is  calculated relative to the base-case value.

-------
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-------
about 3%.  The annual revenue requirements for the lime spray dryer
process are somewhat more sensitive to the stoichiometry than to the
absorbent cost.  For example, a 20% increase in the stoichiometry results
in a 7.5% increase in first-year revenue requirements, which are then
5.5% more than the base case limestone scrubbing process.
DISCUSSION OF RESULTS

     The capital investments for the soda ash and lime spray dryer
processes and the limestone scrubbing process are summarized in Table 73.
The corresponding first-year and levelized annual revenue requirements
are summarized in Table 74.

     The soda ash process is evaluated for only the low-sulfur western
coal case.  This application is chosen because it is expected to be
the only potential application where the technical problems  (i.e., the
high solubility of the sodium waste) could be minimized and the economic
factors would be optimum (i.e., the delivery cost for soda ash would be
low).  As is apparent from these tables, the soda ash spray dryer process
economics are not favorable even under the most optimistic conditions.
In fact in a previous evaluation for a high-sulfur coal application
(44), the process economics showed the soda ash spray dryer process to
be prohibitively expensive.

     The lime spray dryer and the limestone scrubbing processes are
evaluated for all four coal applications.  In overall capital investment
the lime spray dryer process is 12% to 23% lower than the limestone
scrubbing process, the difference being greatest for the lignite case
and least for the low-sulfur western case.  The major cost area for the
limestone scrubbing process is S02 absorption, representing nearly one-
third of the direct capital costs.  This cost increases about 44% as the
coal sulfur content increases from 0.7% to 3.5%.  In contrast, the S02
absorption costs for the lime spray dryer process are about one-half
those of the limestone scrubbing process for the low-sulfur coal cases
and they increase only 23% in going to the 3.5% sulfur case.  These S02
absorption costs are the major cause of the capital investment cost
differences between the processes.

     In other areas, the two processes have similar capital costs.  The
limestone scrubbing process has moderately higher gas handling costs,
very slightly higher costs for solids separation (thickening and filtering)
compared with particulate handling  (pneumatic conveying and silo storage)
and slightly lower disposal costs because of the higher bulk density of
the gypsum waste.  Materials handling costs for the limestone scrubbing
process are lower because the limestone can be simply stockpiled.
Limestone grinding costs greatly exceed lime slaking costs, however,
making the sum of costs for handling and preparing absorbents similar.
                                  235

-------
                                          TABLE 73.   CAPITAL  INVESTMENT  SUMMARY
Lignite

Direct Costs
Material handling
Feed preparation
Gas handling
S02 absorption
Stack gas reheat
Particulate collection
Particulate handling
Solids separation
Total, k$
Other Costs
Solids disposal
Disposal site construction
Land
Other capital costs
Total, k$
Total, $/kW
Lime
spray dryer

1,778
765
10,665
7,336
-
12,091
2,163
-
34,798

867
3,756
960
42.246
82,627
165.25
Limestone
scrubbing

1,291
2,406
13,249
17,357
-
15,076
-
2,268
51,647

790
3,690
920
50.313
107,360
214.72
Low-sulfur western
Soda ash
spray dryer

461
91
9,088
9,208
-
11,523
750
-
31,121

725
7,228
1,146
39.228
79,448
158.90
Lime
spray dryer

1,691
680
10,030
7,366
-
11,523
2,057
-
33,347

719
2,520
770
39.757
77,113
154.23
coal
Limestone
scrubbing

1,009
1,923
11,646
15,054
-
11,688
-
1,828
43,148

616
2,158
670
41.472
88,064
176.13
Low-sulfur eastern coal
Lime
spray dryer

1,762
909
9,770
7,336
-
11,523
753
-
32,053

855
2,939
905
38,551
75,303
150.61
Limestone
scrubbing

1,011
1,944
11,665
15,597
1,225
11,688
-
1,846
44,976

743
2,625
795
43,478
92,617
185.23
High-sulfur eastern coal
Lime
spray dryer

5,014
2,438
11,456
9,018
-
11,235
2,114
-
41,275

1,443
4,899
1,520
50,959
100,096
200.19
Limestone
scrubbing

2,518
4,618
13,653
21,625
3,325
9,998
-
3,350
59,087

1,007
3,441
1,070
57.348
121,953
243.91
Basis:  TVA Design and Economic Premises

-------
                                  TABLE  74.   ANNUAL REVENUE REQUIREMENTS SUMMARY
Lignite
Lime Limestone
spray dryer scrubbing
Direct Costs
Absorbent
Operating labor and
supervision
Fuel
Electricity
Steam
Other utilities
^ Maintenance
OJ Analysis
— i
Total direct, k$
Indirect Costs
Overheads
Total 0 and M, k$
Capital charges
Total, k$
Total, mills /kWh
Levelized
Total, k$
Total, mills /kWh
1,663
1,025
335
1,617
20
2,232
88
6,980
1,794
8,774
12.146
20,920
7.61

28,694
10.43
227
1,212
297
1,986
20
3,851
70
7,663
2,872
10,535
15.782
26,317
9.57

35,651
12.96
Low-sulfur western
Soda ash
spray dryer
2,661
846
265
1,523
10
1,863
88
7,256
1,475
8,731
11,679
20,410
7.42

28,146
10.23
Lime
spray dryer
1,030
972
262
1,464
12
2,136
88
5,964
1,717
7,681
11,336
19,017
6.92

25,822
9.39
coal
Limestone
scrubbing
150
1,140
215
1,508
17
3,219
70
6,319
2,467
8,786
12.945
21,731
7.90

29,515
10.73
Low-sulfur
eastern coal
Lime Limestone
spray dryer scrubbing
848
1,022
329
1,458
21
2,058
88
5,824
1,688
7,512
11.070
18,582
6.76

25,238
9.18
156
1,175
242
1,518
234
18
3,355
70
6,768
^563
9,331
13,615
22,946
8.34

31,213
11.35
High-sulfur eastern coal
Lime
spray dryer
8,430
1,202
653
1,582
456a
20
2,649
89
15,081
2,097
17,178
14,714
31,892
11.60

47,111
17.13
Limestone
scrubbing
1,127
1,341
407
2,428
1,330
26
4,404
105
11,168
3,289
14,457
17.927
32,384
11.78

45,193
16.43
a.  Boiler heat loss in lieu of reheat

-------
     In the lignite case, the lime spray dryer has lower first-year
annual revenue requirements than the limestone scrubbing process (7.61
mills/kWh versus 9.57 mills/kWh).   With the exception of absorbent costs,
where the lime costs are significantly higher than the limestone costs,
and the fuel charges, where the differences are insignificant, the lime
spray dryer process has lower annual costs in each category than the
limestone scrubbing process.  The much higher costs for maintenance,
overheads, and levelized capital charges for the limestone scrubbing
process easily overcome the absorbent cost advantage of using limestone.

     In the low-sulfur western coal case, the soda ash spray dryer
process has first-year annual revenue requirements of 7.42 mills/kWh,
compared with 6.92 and 7.90 for the lime spray dryer and limestone
scrubbing processes respectively.   For the spray dryer processes the
difference is almost entirely the result of absorbent costs, almost
1 mill/kWh for soda ash and 0.4 mill/kWh for lime.  Other minor differences
account for the remaining cost difference.  For the limestone scrubbing
process, absorbent costs are minor, less than 0.1 mill/kWh, but maintenance
costs are, in general, more than 50% higher than those of the spray
dryer processes.  The indirect costs, overheads and levelized capital
charges, account for the remaining cost difference between the limestone
scrubbing process and the spray dryer processes.

     For the low-sulfur eastern coal case a similar relationship prevails.
Most costs differ insignificantly from those of the low-sulfur western
coal case, in spite of the different flue gas bypass conditions.  The
lime spray dryer costs are slightly lower, primarily because of the
lower lime cost in the East.  The limestone scrubbing process costs are
slightly higher, a result of general cost increases stemming from the
lower flue gas bypass ratio.  The small amount of flue gas reheat
required for the limestone scrubbing process has little effect on the
costs.  Overall, for each process some cost differences occur for the
low-sulfur western and eastern coal processes as a result of different
flue gas bypass rates and raw material costs.

     For the high-sulfur eastern coal case, somewhat different conditions
prevail.  The difference in cost between the lime spray dryer process
and the limestone scrubbing process decreases from a 12% to 21% advantage
for the lime spray dryer process,  to only about 2% for the high-sulfur
eastern coal case.  The increase in cost for both the lime spray dryer
process and the limestone scrubbing process in going from the low-sulfur
eastern coal case~ to the high-sulfur eastern coal case is about 42%
while the increase for the lime spray dryer process is about 70%.  The
salient cost factor is absorbent cost.  Absorbent costs for the limestone
scrubbing process increase about sevenfold.  Absorbent costs for the
lime spray dryer process increase about tenfold.  For the lime spray
dryer process, however, this increase results in absorbent costs totaling
27% of the total first-year annual revenue requirements; for the limestone
scrubbing process only 3%.  Other costs increase little in comparison
and in general the increases are similar for both processes.  A significant
requirement for flue gas reheat also appears in both processes, one in
the form of steam, the other in the form of hot flue gas.

                                 238

-------
     The previously discussed first-year annual revenue requirements do
not include the effects of inflation or the time-value of money on the
annual direct costs (such as raw materials, operating labor, etc.)-  The
levelized annual revenue requirements (shown in Table S-6), however, do
take these factors into consideration.  As is apparent from Table S-6,
levelizing the annual revenue requirements results in a significant
increase in the magnitude of the costs.  For the lignite and the low-
sulfur coal cases where annual direct costs are minor relative to the
capital charges, levelizing the revenue requirements does not change the
relative economics of the lime spray dryer and the limestone scrubbing
processes.  However, for the high-sulfur coal case, where the direct
costs for the lime spray dryer process are significantly higher than
those for the limestone scrubbing process, levelizing the annual revenue
requirements results in a reversal whereby the lime spray dryer becomes
4% higher in cost than the limestone scrubbing processes.  In fact using
the results of this study over the 30-year life of the FGD system, the
limestone scrubbing process is $60M less expensive than the lime spray
dryer process.

     The lime spray dryer process economics are relatively insensitive
to both the cost and stoichiometry of lime for the low-sulfur coal
applications and only moderately sensitive for the high-sulfur coal
case.  For a 40% increase in the delivered price of lime, the first-year
revenue requirements increase about 2% for the low-sulfur coal cases and
nearly 11% for the high-sulfur coal case.   For a 20% increase in the raw
material stoichiometry,  the first-year revenue requirements increase
about 2% for the low-sulfur coal cases and about 7% for the high-sulfur
coal case.
                                  239

-------
                                 REFERENCES
 1.  K. Masters, Spray Drying, 2nd Edition, John Wiley & Sons, New York,
    1976.

 2.  Chemical Engineers Handbook, R. H. Perry and C. H. Chilton, eds. ,
    5th Edition, McGraw-Hill, New York, 1973.

 3.  W. Downs, W. J. Sanders, and C. E. Miller, Control of S02 Emissions
    by Dry Scrubbing, paper presented at the American Power Conference,
    Chicago, Illinois, April 21-23, 1980.

 4.  J. L. Getter, H. L. Shelton, and D. A. Furlong, Modeling the Spray
    Absorption Process for SC>2 Removal, Journal of the Air Pollution
    Control Association, Vol. 29, No. 12, pp. 1270-1274, 1979.

 5.  GAI Consultants, Inc., Fly Ash Structural Fill Handbook, EPRI EA-1281,
    Electric Power Research Institute, Palo Alto, California, 1979.

 6.  H. M. Ness, E. A. Sondreal, and P. H. Tufte, Status of Flue Gas
    Desulfurization Using Alkaline Fly Ash From Western Coals, U.S.
    Energy Research and Development Administration, Grand Forks, North
    Dakota, 1979.

 7.  T. A. Burnett and W. E. O'Brien, Preliminary Economic Analysis of a
    Lime  Spray Dryer FGD System, EPA-600/7-80-050, U.S. Environmental
    Protection Agency, Washington, D.C., March 1980.

 8.  D. C. Gehri, Rockwell International, Canoga Park, Calif., Personal
    Communication with T. A.. Burnett, June 1979.

 9.  K. E. Janssen and R. L. Eriksen, Basin Electric's Involvement with
    Dry Flue Gas Desulfurization, Proceedings:  Symposium on Flue Gas
    Desulfurization, Vol. 11, Las Vegas, Nevada, EPA-600/7-79-167b,
    U.S.  Environmental Protection Agency, Washington, D.C., pp. 629-653,
    March 1979.

10.  J. B. Martin, W. B. Ferguson, D. Frabotta, C-E Dry Scrubber Systems;
    Application  to Western  Coals, paper presented  at  the American Power
    Conference,  Chicago, April  21-23,  1980.

11.  S. M. Kaplan  and K. Felsvang, Spray Dryer Absorption of  S02 From
    Industrial Boiler Flue  Gas, paper  presented at  86th National Meeting,
    AIChE, Houston, April  1-5,  1979.

12.  L. M. Pruca,  Interest in Baghouses on Upswing, Power, Vol.  124,
    No.  2, pp.  86-88,  1980.

13.  F.  J. Miller,  et  al.,  Size  Consideration for  Establishing  a Standard
     for  Inhalable Particles, Journal of  the  Air Pollution Control
    Association,  Vol.  29, No.  6,  pp.  610-615,  1979.


                                     240

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14.  R. W. Mcllvaine, Installed Cost Projections of Air Pollution
     Control Equipment in the U.S., Proceedings:  Symposium on the
     Transfer and Utilization of Particulate Control Technology,
     Volume 2.  Fabric Filters and Current Trends in Control Equipment.
     EPA-600/7-79-044b, U.S. Environmental Protection Agency,
     Washington, D.C., February 1979.

15.  S. J. Lutz and C. J. Chatlynne, Dry FGD Systems for the Electric
     Utility Industry, Proceedings:  Symposium on Flue Gas Desulfurization
     Vol. 1, EPA-600/7-79-167a, Las Vegas, Nevada, March 1979.

16.  Bechtel Corporation, Evaluation of Dry Alkali for Removing Sulfur
     Dioxide from Boiler Flue Gases, EPRI FP-207, Electric Power Research
     Institute, Palo Alto, Calif., 1976.

17.  R. A. Davis, et al., Dry 807 Scrubbing at Antelope Valley Station,
     paper presented at the American Power Conference, Chicago, Illinois,
     April 23-25, 1979.

18.  A History of Flue Gas Desulfurization Systems Since 1850, Journal
     of the Air Pollution Control Association, Vol. 27, No. 10, pp.
     948-961, 1977.

19.  T. N. Beard and J. W. Smith, In-Place Recovery of Multiple Products
     From Colorado's Saline-Mineral-Bearing Piceance Basin, Oil Shales
     and Tar Sands, J. W. Smith and M.  T. Atwood, eds. , AIChE Symposium
     Series, Vol. 72, No. 155, 1976.

20.  E. Rau, Sodium Carbonate, Kirk Othmer Encyclopedia of Chemical
     Technology, 2d Ed., Vol. 18, Interscience Publishers, New York,
     pp. 458-468, 1969.

21.  S. J. Lutz, et al., Evaluation of Dry Sorbents and Fabric Filtration
     for FGD, EPA-600/7-79-005, U.S. Environmental Protection Agency,
     Research Triangle Park, North Carolina, January 1979.

22.  V. Rajaram, I. P. Nielsen, and H. D. Raymond, A Plan for Mining
     Nahcolite in the Piceance Basin, Colorado, Mining Engineering,
     Vol. 31, No. 12, pp. 1699-1703, 1979.

23.  Mining Combo May^ Produce Oil, Dry  Scrubbing Compound, Engineering
     News Record, Vol. 203,  No. 20, p.  16, November 29, 1979.

24.  J. M. Dulin, Toxic and  Hazardous Waste Disposal,  Volume 1,
     Ann Arbor Science, Ann  Arbor, Michigan, pp. 363-400,  1979.

25.  S. V. Tomlinson, et al., Definitive S0y Control Process Evaluations:
     Limestone,  Double Alkali, and Citrate FGD Processes,  EPA-600/7-79-177,
     U.S.  Environmental Protection Agency, Research Triangle Park,
     North Carolina,  August  1979.
                                     241

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26.   L.  J.  Muzio, J.  K.  Arand,  and N.  D.  Shah,  Bench-Scale  Study of  Dry
     SO? Removal with Nahcolite and Trona,  paper presented  at  the Second
     Conference on Air Quality  Management in the Electric Power  Industry,
     Austin, Texas, January 22-25, 1980.

27.   T.  G.  Brna and M. A.  Maxwell, EPA's  Dry SC^ Control Program,
     paper presented at the Second Conference on Air Quality Management
     in the Electric Power Industry, Austin, Texas,  January 22-25, 1980.

28.   D.  C.  Gehri and J.  D. Gylfe,  Pilot Test of Atomics  International
     Aqueous Carbonate Process  at  Mohave  Generating  Station, Final
     Report AI-72-51, Rockwell  International, Canoga Park,  Calif., 1972.

29.   Pertinent information on the  Babcock & Wilcox process  was obtained
     from the following:  T.  A.  Burnett,  Meeting Notes  at B&W, June  28,
     1979;  T. B. Hurst,  Dry Scrubbing  Eliminates Wet Sludge, paper
     presented at the Joint Power  Generation Conference, Charlotte,
     North Carolina,  October 7-11, 1979;  W. Downs, W. J. Sanders, and
     C.  E.  Miller, Control of SO?  Emissions by  Dry Scrubbing,  paper
     presented at the American  Power Conference, Chicago, Illinois,
     April 21-23, 1980;  and W.  De  Priest, Personal Communication with
     T.  A.  Burnett, April 1980.

30.   Pertinent information on the  Buell-Envirotech/Anhydro, Inc., process
     was obtained from the following:  T. A. Burnett, Meeting  Notes  at
     Buell, June 29,  1980; D. A. Furlong, Personal Communications with
     T.  A.  Burnett, March 1980;  and W. T. Langan, Personal  Communication
     with T. A. Burnett, October 1980.

31.   Pertinent information on the  Carborundum Environmental Systems
     process was obtained from  the following:  H. Madjeski, Personal
     Communication with T. A. Burnett, March, June,  and August 1980.

32.   Pertinent information on the  Combustion Engineering process was
     obtained from the following:   J.  B.  Martin, W.  B.  Ferguson, and
     D.  Frabotta, C-E Dry Scrubber Systems:  Application to Western
     Coals, paper presented at  the American Power Conference,  Chicago,
     Illinois, April 21-23, 1980,  and  K.  M. Malk, Personal  Communication
     with T. A. Burnett, June 1980.

33.   Pertinent information on the  Ecolaire Systems,  Inc., process was
     obtained from the following:   T.  A.  Burnett, Meeting Notes  at
     Ecolaire, May 22, 1979, and T. A. Burnett, Trip Report (unpublished),
     March 1980.

34.   Pertinent information on the  Joy  Manufacturing/Niro Atomizer, Inc.,
     process was obtained from the following:  T. A. Burnett,  Meeting
     Notes at Joy Manufacturing, June  14, 1979; S. M. Kaplan  and K.
     Felsvang, Spray Dryer Absorption  of  SO,., from Industrial  Boiler  Flue
     Gas, paper presented at the 86th  National Meeting, AIChE, Houston,
     April 1-5, 1979; J. A. Meyler, Personal Communication  with  T. A.
     Burnett, February, April,  and June  1980; and G. Steele,  Personal
     Communication with T. A. Burnett, June 1980.

                                     242

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35.  Pertinent information on the Research-Cottrell process was obtained
     from the following:   T.  A.  Burnett,  Meeting Notes at Research-Cottrell,
     May 23, 1979, and K.  N.  Parikh,  Personal Communication with T.  A.
     Burnett, March and April 1980.

36.  Pertinent information on the Rockwell International/Wheelabrator
     Frye, Inc., process  was obtained from the following:  V.  F.  Estcourt,
     et al., Tests of a Two-Stage Combined Dry Scrubber/S02 Absorber Using
     Sodium or Calcium, paper presented at the American Power  Conference,
     Chicago, Illinois, April 26, 1978; T. A.  Burnett, Meeting Notes at
     Rockwell International,  June 13, 1979; 0. B. Johnson, et al., Coyote
     Station - First Commercial Dry  FGD System, paper presented at  the
     American Power Conference,  Chicago,  Illinois, April 23-25, 1979;
     R. B. Crowe, J. F. Lane, and V. J. Petti, Early Operation of the
     Celanese Fibers Company Coal-Fired Boiler Using the Dry Flue Gas
     Cleaning System, paper presented at  the American Power Conference
     of Chicago, Illinois, April 21-23, 1980;  and K. C. Lang,  Personal
     Communication with T. A. Burnett.

37.  Machine Readable Data Format^ of FERC FORM 67 Data, 1969-1973,
     Applied Data Research,  1976.

38.  New Stationary Sources  Performance Standards; Electric Utility Steam
     Generating Units, Federal Register,  Vol.  44, No.  113, pp.  33580-33624,
     June 11, 1979.

39.  J. A. Cavallaro, et  al., Sulfur Reduction Potential of the Coals
     of the United States, Bureau of Mines Report of Investigation RI
     8118, U.S. Bureau of Mines, Washington, D.C,, 1976.

40.  D. C. Gehri, Rockx/ell International, Canoga Park, Calif.,  Personal
     Communication with T. A. Burnett,  June 1979.

41.  Technical Assessment Guide, EPRI PS-866-SR, Electric Power Research
     Institute, Palo Alto, Calif., June 1978.

42.  P. H. Jeynes,  Profitability and Economic Choice, 1st Ed., The Iowa
     State University Press,  Ames, Iowa,  1968.

43.  Economic Indicators, Chemical Engineering, Vols.  83, 84,  85, and
     86, 1976, 1977, 1978, and 1979.

44.  T. A. Burnett and W. E.  O'Brien, Economics of Spray Dryer FGD Systems:
     The Two-Stage Open-Loop Processes, Draft  Report for EPRI  (RP 1180-7),
     October 1979.
                                     243

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                               TECHNICAL REPORT DATA
                         (Please read Instructions on the reverse before completing)
 REPORT NO.
:PA-600/7-81-Q14
                          2.
                                                     3. RECIPIENT'S ACCESSION-NO.
. TITLE AND SUBTITLE
Technical Review of Dry FGD Systems and Economic
 Evaluation of Spray Dryer FGD Systems
                                 5. REPORT DATE
                                  February 1981
                                 6. PERFORMING ORGANIZATION CODE
. AUTHOR(S)
T.A.  Burnett and K. D. Anderson
                                 8. PERFORMING ORGANIZATION REPORT NO.

                                  EDT-127
. PERFORMING ORGANIZATION NAME AND ADDRESS
TVA, Division of Energy Demonstrations and
  Technology
Office of Power
Muscle  Shoals, Alabama 35660
                                                     10. PROGRAM ELEMENT NO.
                                  1NE827
                                 11. CONTRACT/GRANT NO.

                                 EPA IAG-D9-E721-BI
 2. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC  27711
                                 13. TYPE OF REPORT AND I
                                  Final; 5/79-11/80
                                                                      PERIOD COVERED
                                 14. SPONSORING AGENCY CODE
                                   EPA/600/13
 5.SUPPLEMENTARY NOTES JERL-RTP project officer is Theodore G. Brna, MD-61, 919/541-
2683.
 e. ABSTRACT
              repOr{. gjves results of an extensive study of dry flue gas desulfuriza-
tion (FGD) systems, involving dry injection of absorbents or spray drying. (The
study was undertaken because they appear to have both process and economic advan-
tages over wet FGD. )  Design concepts  (e.g. , type of absorbent and atomizer, ap-
proach to flue gas saturation temperature, and particulate collection method) re-
main to be demonstrated at full scale.  Most vendors prefer a lime slurry system
with rotary atomizers and fabric filter particulate collection, while all systems now
under contract to utilities  apply to low-sulfur coal. SO2 removal efficiencies suffi-
pieiit for high-sulfur coal applications at stable operating conditions and economi-
6ally feasible absorbent utilization rates have not yet been demonstrated.  In concep-
tual design cost comparisons based on a new 500-MW utility power generation unit, a
lime spray dryer/fabric filter combination had lower capital investments and annual
revenue requirements for  0. 7% sulfur western coal and both 0. 7 and 3. 5% sulfur
eastern coal than a wet limestone scrubbing process. With lignite fuel, similar cost
advantages were evident for dry (relative to wet) FGD.  The capital investment advan-
tage of dry over wet FGD increased with increasing coal sulfur content.
17.
                             KEY WORDS AND DOCUMENT ANALYSIS
                DESCRIPTORS
                                          b.IDENTIFIERS/OPEN ENDED TERMS
                                                COS AT I Field/Group
Pollution
Flue Gases
Desulfurization
Spray Drying
Sorbents
Calcium Oxides
Slurries
Dust
Aerosols
Filtration
Fabrics
Coal
Calcium Carbonates
Pollution Control
Stationary Sources
Dry Processes
Rotary Atomizers
Particulate
Fabric Filters
13 B
21B
07A,07D
13H
11G       HE
07B      21D
18. DISTRIBUTION STATEMENT
 Release to Public
                      19. SECURITY CLASS (ThisReport)
                      Unclassified
                        21. NO. OF PAGES
                         280
                      20. SECURITY CLASS (Thispage)
                      Unclassified
                                                                  22. PRICE
EPA Form 2220-1 (9-73)
                                         244

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