United States
Environmental Protection
Agency
Office of
Research and
Development
Office of
Energy. Minerals and Industry
Washington. D.C. 20460
EPA-600/7-77-037
April 1977
           WATER REQUIREMENTS FOR
           STEAM-ELECTRIC POWER
           GENERATION  AND SYNTHETIC
           FUEL PLANTS IN THE
           WESTERN UNITED  STATES
           Interagency
           Energy-Environment
           Research and Development
           Program Report

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                RESEARCH REPORTING SERIES

Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into 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.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.

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                                        EPA Report Number 600/7-77-037

                                        February,  1977
            WATER REQUIREMENTS FOR STEAM-ELECTRIC
         POWER GENERATION AND SYNTHETIC FUEL PLANTS
                IN THE WESTERN UNITED STATES
                              by
         H.  Gold, D.J. Goldstein,  R.  F.  Probstein,
                   3. S.  Shen and  D.  Yung
               Water Purification  Associates
                  Cambridge, Massachusetts
     A Subcontract Report to the University of Oklahoma
           Science and Public Policy Program for:

Technology Assessment of Western Energy Resource Development

               EPA Contract Number 68-01-1916
                       Project Officer
                      Steven E. Plotkin
           Office of Energy, Minerals and Industry
                   Washington, D.C.  20460
           Office of Energy, Minerals and Industry
             Office of Research and Development
            U.S. Environmental Protection Agency
                   Washington, D.C.  20460

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                                   DISCLAIMER
     This report has been reviewed by the Office of Energy,  Minerals and Industry,
U.S. Environmental Protection Agency, and approved for publication.   Approval does
not signify that the contents necessarily reflect the views  and policies of the
U.S. Environmental Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
                                         11

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                                    FOREWORD
     The authors of this report were given the assignment of determining the
water requirements of several fossil fuel energy conversion technologies at
six sites in the Western United States.   It is known that the magnitude of
such requirements is dependent upon plant design;  thus,  a critical assumption
of the study is that the water use systems are designed  by engineers operating
simultaneously as cost-minimizing businessmen and water  conservationists.   These
two roles are not mutually exclusive in  the West,  since  water is hardly a free
good.  However, the price of  water to the facilities in  question is not so high
that the water requirements presented in the report should be viewed as "minimum"
requirements.  Outright  shortage of water, substantial increases in water cost,
or restrictive legislation could force the water requirements of the conversion
plants still lower.

     The effect of water consumption by  energy development on the environment,
lifestyle and economy of the  arid American West is a critical issue facing
local, State and national policymakers.   It is one of the key issues addressed
by the Office of Energy, Minerals and Industry's "Technology Assessment of
Western Energy Resource  Development," a  three year study addressing the impacts -
and means of relieving those  impacts - of energy development in the Western
United States.  The study is  being conducted by the Science and Public Policy
Program of the University of  Oklahoma, under the management of Professor Irvin
L. (Jack) White.  This document is a subcontractor's report to the study, and
will be formally appended to  the study's Final Report.  Because of our desire
to disseminate important research results to the public  as quickly as possible,
we are publishing this report as a separate document.
                                  StepHfen J. Gage
                          Deputy Assistant Administrator
                        for Energy, Minerals, and Industry
                                      111

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                                   ABSTRACT
     The study describes the procedures for the detailed determination of the
water consumed for mining and processing coal and oil shale, and for determining
the residuals generated.  The processes considered are Lurgi, Synthane, and
Synthoil for coal conversion, TOSCO II for shale conversion, coal-fired steam
electric power generation and slurry pipeline.  In addition, determinations are
also made of the water consumed for process cooling, flue gas desulfurization,
revegetation of mined land, solids disposal and by evaporation and other uses
within the mine-plant complex.  In these determinations it is assumed that there
is no discharge to receiving waters and that there is a reasonably high level of
recycle and reuse of process effluent waters.  Wasteful evaporation of waste-
water is not permitted.  Economic studies of water treatment are not included
in this assessment except for some of the process cooling studies.

     The consumptive water use and solids residuals are determined for a total
of 21 plant-site combinations.  The sites are:  Beulah, North Dakota; Colstrip,
Montana; Gillette, Wyoming; Kaiparowits/Escalante, Utah; Navajo/Farmington,
New Mexico; and Rifle, Colorado.  A detailed breakdown by consumptive water
use category is presented in tabular form for each plant-site combination.
Approximately twenty water use categories are considered.  Results are also
presented for three energy development scenarios focused on the Powder River
and Rocky Mountain Regions.
                                      iv

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                               CONTENTS
FOREWORD                                                     iii
ABSTRACT                                                     iv
FIGURES                                                      viii
TABLES                                                       x
CONVERSION TABLE                                             xv
ACKNOWLEDGEMENTS                                             xvii

1.  INTRODUCTION AND SUMMARY                                 1

     1.1  Introduction                                       1
     1.2  Summary, of Findings and Conclusions                4

2.  COAL CONVERSION PROCESSES                               17

     2.1  SynthoiJ. Process                                  17
     2.2  Process Water Streams                             33
     2.3  Cooling Water                                     38
     2.4  Lurgi Process                                     45
     2.5  Synthane Process                                  48
     References                                             54

3.  SHALE CONVERSION                                        56

     3.1  Underground Mining and Surface Processing         56
     3.2  TOSCO II Process                                  57
     3.3  Water Streams for Retorting                       61
     3.4  Water Streams for Upgrading                       66
     3.5  Process and Cooling Water Consumption             68
     References                                             69

4.  STEAM ELECTRIC GENERATION                               70

     4.1  Costs of Cooling Systems                          70
     4.2  Comparison of Dry and Evaporative Cooling         78
           Systems Not Including the Costs of Water
     4.3  Costs of Water                                    89
     4.4  Costs of Wet-Dry Cooling Systems                 101
     4.5  Water Consumed and Solid Residuals Generated     108
     References                                            114

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5.   SLURRY PIPELINE

          References


6.   FLUE GAS DESULFURIZATION                                             119

          6.1  Particulate and Sulfur Removal                             119
          6.2  Water in Flue Gas                                          120
          6.3  Water in Waste Solids                                      124
          6.4  Comparison of Present Approach                             127
          References                                                      129


7.   MINING                                                               130

          7.1  Categories                                                 130
          7.2  Coal and Shale Mining Rates                                130
          7.3  Road, Mine and Embankment Dust Control                     134
          7.4  Handling and Crushing Dust Control                         137
          7.5  Mine Personnel                                             138
          7.6  Sanitary and Potable Water                                 141
          7.7  Service and Fire Water                                     143
          7.8  Revegetation                                               143
          7.9  Coal Washing                                               145
          References                                                      147


8.   EVAPORATION, SOLIDS DISPOSAL AND OTHER USES                          149

          8.1  Categories                                                 149
          8.2  Bottom Ash and Spent Shale Disposal                        149
          8.3  Fly Ash and Shale Dust Disposal                            153
          8.4  Plant Dust Control                                         154
          8.5  Plant Personnel                                            155
        ,  8.6  Plant Sanitary and Potable Water                           156
          8.7  Plant Service and Fire Water                               156
          8.8  Settling Basin Evaporation                                 157
          8.9  Reservoir Evaporation                                      160
          References                                                      161


9.   MUNICIPAL WATER REQUIREMENTS AND RESIDUALS                           162

          Reference                                                       163
                                   VI

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10.  SITE-SPECIFIC RESULTS
                                                           Page

                                                           164
11.  FINDINGS

          11.1
          11.2
          11.3
 Total Site-Specific Water Consumption and Residuals
 Site-Specific Water Consumption and Residual Breakdowns
 Regional Water Consumption and Residuals
187

187
191
204
APPENDIX A.
COAL ANALYSES
206
APPENDIX B.
WATER ANALYSES AND PRECIPITATION AND EVAPORATION RATES
209
APPENDIX C.
LOAD FACTORS
215
APPENDIX D.    TOTAL WATER CONSUMED AND RESIDUALS GENERATED FOR
               THREE ENERGY SCENARIOS BY STATE AND COUNTY
                                                           217
APPENDIX E.    STATE TOTALS OF WATER CONSUMED AND RESIDUALS
               GENERATED FOR THREE ENERGY SCENARIOS
                                                           245
                                        vii

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                                FIGURES
Number                                                                    Page

1-1    Breakdown of net annual water consumption and wet solid residuals
       generated in the production of 250 x 10 scf/stream day of
       synthetic natural gas' by the Lurgi arid Synthane- processes at
       different Western sites	-.-..'	    9

1-2    Breakdown of net annual water consumption and wet solid residuals
       generated in the production of 100,000 bbl/stream day of fuel oil
       by the Synthoil process at different Western sites and by the
       TOSCO II oil shale process at Rifle, Colorado.	   10

1-3    Breakdown of net annual water consumption and wet solid residuals
       generated in the production of 3,000 MWe/stream day of electricity
       by coal-fired steam-electric generating plants at different
       Western sites	;	   11

1-4    Regional net annual water consumption and wet solid residuals
       generated in the Western coal and oil shale areas between the years
       1980 and 2000 for three levels of energy development	  15

2-1    Synthoil process	  19

2-2    Hydrogen production train	  25

3-1    TOSCO II retort flow diagram for upgrading shale oil output of
       50,000 bbl per stream day with feed of 35 gallon per ton oil shale.  58

3-2    Flow diagram for TOSCO II shale oil upgrading refinery	  60

3-3    TOSCO II process water streams for upgrading shale oil output of
       50,000 bbl per stream day with feed of 35 gallon per ton oil
       shale	   62

41    Cooling tower nomenclature	   72

4-2    Annual evaluated cost of dry cooling system as a. function of the
       initial temperature difference for Navajo/Farmington, New Mexico..   81

4-3    Annual evaluated cost of evaporative cooling system as a function
       of cooling range for Navajo/Farmington, New Mexico	   81

4-4    Wet/dry cooling system	  104

4-5    Total annual evaluated costs of wet/dry cooling system as a
       percentage of evaporative loss of all evaporative cooling system
       at Navajo/Farmington, New Mexico	  107
                                      vtii

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FIGURES (continued)

Number;                                                                    Page

11-1   Breakdown of net annual water consumption and wet solid residuals
       generated in the production of 250 x 1C)6 scf/stream day of
       synthetic natural gas by the Lurgi and Synthane processes at
       different Western sites	   192

11-2   Breakdown of net annual water consumption and wet solid residuals
       generated in the production of 100,000 bbl/stream day of fuel oil
       by the Synthoil process at different Western sites and by the
       TOSCO II oil shale process at Rifle, Colorado	   193

11-3   Breakdown of net annual water consumption and wet solid residuals
       generated in the production of 3,000 MWe/stream day of electricity
       by coal-fired steam-electric generating plants at different
       Western sites	   194

11-4   Regional net annual water consumption and wet solid residuals
       generated in the Western coal and oil shale areas between the
       years 1980 and 2000 for three levels of energy development	   205
                                     ix

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                                 TABLES
Number                                                                    Page

 1-1   Unit size plants and ratio of operating or stream days to
       calendar days in a year (load factor)	    2
 1-2   Summary of net annual water consumption and wet solid residuals
       generated at each site	,
 1-3   Net water consumed for Western coal sites per million Btu of
       heating value in product	
 2-1   Material balance on Synthoil plant exclusive of hydrogen
       production for Colstrip, Montana	   20

 2-2   Material balance on Synthoil plant exclusive of hydrogen
       production for Beulah, North Dakota	   21

 2-3   Material balance on Synthoil plant exclusive of hydrogen
       production for Gillette, Wyoming.	   22

 2-4   Material balance on Synthoil plant exclusive of hydrogen
       production for Navajo/Farmington,  New Mexico	   23

 2-5   Water equivalent hydrogen balance of Synthoil plant at four sites.   27

 2-6   Approximate total heat load of Synthoil plant at four sites	   29

 2-7   Gas compressor energy and interstage cooling requirements for
       Synthoil and Synthane plants	   31

 2-8   Approximate thermal efficiencies of Synthoil plants	  32

 2-9   Ultimate disposition of unrecovered heat in Synthoil plants	   34

 2-10  Water lost in condensate water treatment	   35

 2-11  Demineralizer water treatment waste	   37

 2-12  Water evaporation rates for wet cooling	   42

 2-13  Cooling water treatment waste	   44

 2-14  Water equivalent hydrogen balance of Lurgi plant at four sites....   47

 2-15  Assumptions and calculations on thermal efficiency of Lurgi
       plants	   49

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TABLES (continued)

Number

 2-16  Water equivalent hydrogen balance for the Synthane process
       using Wyodak coal	    50

 2-17  Approximate thermal efficiency for Synthane plant at Wyoming	    52

 2-18  Approximate disposition of unrecovered heat in Synthane plant
       at Wyoming	    53

 3-1   Determination of TOSCO II retort water streams for upgrading
       shale oil output of 50,000 bbl per stream day with feed of
       35 gallon per ton shale, on basis of water balance for combined
       retorting and upgrading steps	.	    64

 3-2   Compilation of TOSCO II refinery water streams for upgraded
       shale oil output of 50,000 bbl per stream day with feed of
       35 gallon per ton shale, on basis of water balance for combined
       retorting and upgrading steps	    67

 4-1   Summary of unit price data	    79

 4-2   Summary of design conditions for optimized cooling systems at
       Navajo/Farmington,  New Mexico	    83

 4-3   Summary of capital  costs for optimized cooling systems
       (lO^ Dollars) at Navajo/Farmington,  New Mexico	    84

 4-4   Summary of energy and power quantities for optimized cooling
       systems at Navajo/Farmington, New Mexico	    85

 4-5   Breakdown of annual evaluated costs  for optimized cooling system
       at Navajo/Farmington, New Mexico (106 dollars/yr)	    87

 4-6   Comparison of total annual evaluated costs of optimized cooling
       systems and breakeven water costs	    88

 4-7   Control limits for  cooling tower circulating water composition....    91

 4-8   Flow diagram, circulating water concentration and estimated costs
       for Navajo/Farmington, New Mexico cooling tower	    96

 4-9   Summary of annual evaluated costs of water treatment and
       blowdown disposal	    97

 4-10  Pipeline data	    99

 4-11  Evaluated costs of  supplying water	   100

 4-12  Summary of evaluated water costs	   102
                                     XI

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TABLES (continued)

Number                                                                    page

 4-13  Total annual evaluated costs for optimum wet/dry cooling systems
       at Navajo/Farmington, New Mexico	   106

 4-14  Water evaporated and heat dissipation rates for cooling towers....   109

 4-15  Residuals generated at each site	   110

 4-16  Drift rates	   112

 4-17  Demineralizer residuals	   113

 6-1   Moles of water vapor per mole of dry gas at saturation	   120

 6-2   Determination of total moles of dry flue gas per unit weight of
       coal or char as fired	   122

 6-3   Element weights per unit weight of coal or char and makeup water
       requirements per unit weight of coal or char for coals and char
       of present study	   123

 6-4   Weight of CaS04-2H20 and CaSC^-^O, and water of hydration
       per unit weight of sulfur	   124

 6-5   Weight of slurry water per unit weight of sulfur for a 40 wt.%
       solids concentration	 .   125

 6-6a  Weight of components of lime sludge (dry) and corresponding
       weights of sulfur and water of hydration	   125

 6-6b  Weight of components of limestone sludge (dry) and corresponding
       weights of sulfur and water of hydration	   126

 6-7   Weight of solids and water of hydration per unit weight of
       sulfur in lime and limestone sludges	.	   126

 6-8   Weight of sulfur and makeup water requirements per unit weight
       of coal for coals of present study and with 40 wt.% solids in
       slurry		   128

 6-9   Comparison of flue gas desulfurization makeup water requirements
       for Kaiparowits coal from design estimates of Ref.  2 and present
       approximate formulation	   128

 7-1   Process heat requirements for 250 x 10  scf/stream day
       Lurgi plant	   131

 7-2   Mine and process requirements for coal conversion plants	   132

 7-3a  Coal tonnage requirements for unit size plants in tons
       per calendar day	   133

                                     xii

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TABLES (continued)

Number                                                                    Page

 7-3b  Coal and shale tonnage requirements for unit size plants in
       tons per calendar day	  133

 7-4   Coal yields per acre	  134

 7-5   Annual pond evaporation rates	  135

 7-6   Area strip mined annually in acres per year	  136

 7-7a  Number of mine personnel for specific mines integrated with
       coal conversion plants and a slurry pipeline.	  140

 7-7b  Number of mine personnel for an underground and surface mine
       integrated with a steam-electric plant and for an underground
       oil shale mine integrated with a shale oil plant	  140

 7-8   Sanitary and potable water usage per man-shift and percent of
       usage consumed	  141

 8-1   Temperature of bottom ash on removal and ash temperature drop
       on quenching	  150

 8-2   Ash quantities in tons per day.	  152

 8-3   Plant personnel at all sites	  156

 8-4   Evaporation rates without and with evaporation control and
       need for settling basin	  159

 9-1   Municipal water requirements in gallons per capita per day	  163

10-1   Summary of total water consumed and residuals generated at
       each site	  165

11-1   Summary of net annual water consumption and wet solid residuals
       generated at each site	  188

11-2   Net water consumed for Western coal sites per million Btu of
       heating value in product	  190

11-3   Weight of water as a percent of total weight of wet
       solid residuals	  201

 A-l   Coal analyses	  208

 B-l   Source of feed water	  212

 B-2   Source water quality	  213

 B-3   Precipitation and evaporation data (inches/year)	  214

                                      xiii

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TABLES (continued)

Number                                                                    Page

 C-l   Load factors	  216

 D-l   Base quantities assumed for water consumed and residuals
       generated for standard size plants in each state of western
       region	  219

 D-2   Location of results for specific scenarios by region, energy
       demand, and year	  220

 E-l   Location of results for specific scenario by region and facility..  246
                                       xiv

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                                   CONVERSION  TABLE
                  LENGTH
 English to Metric

 1 mile - 1.609 kilometers   1609 mecer*
 1 yard - .9144 meter - 9144  centemecers
                                                                            PRESSURE
English to Metric

1 pound per square  inch (pel) - .06804
    atmosphere - 703.1 ktlograas per
    square meter
                 ARA
EnlIsh Equivalent

1 square mile  640 acre*

English to Metric

1 square mile " 2.590 square kilometer* -
    259.0 hectares - 2,590,000 square Mtera
1 acre - .004047 square  kilometer 
    .404? hectares - 4047  square meter*
                                                                           FLOW RATE
English to Metric

1 cubic foot per second  4488 gallons per
    minute - 723.8  acre per year  .02832
    cubic meters per  second
1,000,000 acre feet per year - 3,9126
    3.9126 cubic meters per second
                 WEIGHT
English Equivalent

1 ounce (avoirdupois) - 437,5 grains  (troy)

English to Metric

                             .9066 matrlc tons
 1  short ton  (2,000 pounds)
    - 906.6  kilograms
 1  pound -  .4536 kilogram
 1  ounce -  2.8349 grams
                                                                        VOLUME AND CAPACITY
 English Equalivant

 1  acre-foot - 43,560 cubic feet -
     325,900 gallons
 1  cubic yard  202 gallons (liquid)
 1  cubic foot  7.481 gallons (liquid)

 English to Metric

 1  cubic yard  ,7646 cubic meter* 
     764.6 liters
 1  cubic foot  .02832 cubic meters 
     28.32 liters
                                                XV

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                                      CONVERSIONS OF UNITS
      VOLUMETRIC FLOW RATES







1 gallon per minute




1 million gallons per day




1 cubic foot per second




1 acre foot per year
  mgd
 cfs
                                                                                      acre  ft/yr
1
694
448

0.619
1.44

0

8.91
x 10
1
.645
4
x 10
2.23 x 10
1.55
1
5
1.38 x 10
1.614
1,120
723

1
         MASS FLOW RATES







1 ton per day               =




1 ton per year              **




1 pound per hour            =




1 gallon water per minute*  =
                                       ton/day
ton/yr
Ib/hr
                                                                                      gpm of H?O
1 365
2.74 x 10~3 1
0.012 4.38
6.00 2.19 x 103
83.3 0.167
0.228 4.56 x 10~4
1 2.00 x 10~3
500 1
*I gallon of water =8.33 pounds

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                                ACKNOWLEDGEMENTS
     The authors wish to express their most sincere thanks to Steve Plotkin
of the Office of Energy, Minerals and Industry, U.S. Environmental Protection
Agency and Professor Irvin L. (Jack) White of the University of Oklahoma,
Science and Public Policy Program for their many suggestions during -the course
of the work and for their untiring efforts to ensure the success of the program.
                                       xvii

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                   1.   INTRODUCTION AND  SUMMARY









1.1  Introduction




     Two important aspects of any assessment of  the potentials for




utilizing the abundant  coal and oil shale resources in  the Western United




States are first the local and regional  environmental problems associated




with the large consumptive use of water  required for mining and proces-




sing these resources, and second the problem of  disposal of the large




quantities of solid residuals that 'leave the mine-plant complex.  In




some western locales, where coal and oil shale can be economically mined,




surface and groundwater is in short supply.  Moreover,  in the West there




is frequently keen competition between agricultural, power producing,




municipal, industrial, recreational and  other users for allocations of




the available water supply.  The problems cited  could hamper efforts to




utilize the nation's western coal and oil shale  resources.




     As a first step in estimating the impact of water supply and'avail-




ability on the development of these fossil fuel  resources, it is neces-




sary to make an accurate determination of the water consumed for mining




and processing, together with a determination of the residuals generated.




In this study, the consumptive water requirements and solid residuals are




determined for the unit size plant-mine  complexes and load factors




indicated in Table 1-1.




     The coal input rates are about the  same for the Lurgi and Synthane




gasification plants,  although more coal  is mined for the Lurgi plant




because the fines cannot be used and must be sold off.   Compared with




the unit size gasification plant the coal input  to a 3,000 MWe generating




plant is about 30% more, to the unit size Synthoil plant about 2 times

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as much, and to the slurry pipeline about 3 times as much.  The input
to the shale oil plants is not directly comparable, but we would note
that the raw shale tonnage for a 100,000 bbl/day surface retort shale
oil plant is 3 times the coal tonnage for a 100,000 bbl/day Synthoil
plant.
     Table 1-1.  Unit size plants and ratio of operating or stream
                 days to calendar days in a year (load factor).
                                                        Load Factor
                              Nominal Output      (stream day/calendar day)
  Slurry Pipeline         25 x 10  tons coal/year           1.0
  Lurgi                  250 x 10  scf/stream day           0.9
  Synthane               250 x 10  scf/stream day           0.9
  Synthoil                 100,000 bbl/stream day           0.9
  Electrical Generation      3,000 MWe @ 35% eff.           0.7
  Electrical Generation      1,000 MWe @ 35%'eff.           0.7
  Oil Shale, TOSCO II       50,000 bbl/stream day           0.9
  Oil Shale, TOSCO II      100,000 bbl/stream day           0.9
     For each process, detailed calculations are carried out on the quanti-
ties of water consumed for the following purposes:
     (1)  the energy conversion process itself,
     (2)  evaporation for process cooling,
     (3)  flue gas desulfurization, if required,
     (4)  the mining operation and any revegetation of mined land,
     (5)  solids disposal, evaporation and other uses within the mine-plan
          complex.
     In our determinations we assume zero discharge to receiving waters.
We also assume water treatment facilities based on available technology

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to provide for a reasonably high level of recycle and reuse of process




effluent waters.  Wasteful evaporation of wastewater is not permitted.




The water treatment procedures that can be used are given.  Economic




studies of water treatment are not included in this assessment except




for some of the process cooling studies.  For example, the choice of




wet, wet/dry, or dry cooling for steam electric generating plants is




made on economic considerations.  The choice of cooling in the process




plants is also made on the basis of economic considerations from other




ongoing studies, although the detailed cost breakdowns are not incorpo-




rated in this report.




     The water consumption and solid residuals generated for the unit




size mine-plant complexes noted are determined at a number of different




locations.  The locations considered are:




          Beulah, North Dakota




          Colstrip, Montana




          Gillette, Wyoming




          Kaiparowits/Escalante, Utah




          Navajo/Farmington,  New Mexico




          Rifle, Colorado




Not every plant is sited at each location.  In particular, the slurry




pipeline is sited only at Gillette, while shale oil production is sited




only at Rifle.  At Kaiparowits only electric power generation is con-




sidered, with the coal source an underground mine, as distinct from the




other sites, where all coal is taken to be surface mined.   A total of




21 plant-site combinations is examined.

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     Regional consumptive water requirements and solid residuals




generated are determined, based on the site-specific results and on




an assumed distribution of plants and different levels of energy




development from the present to the year 2000.  The aggregated or




regional scenarios focus on the Powder River Region, which includes




the states of Montana, North Dakota and Wyoming, and the Rocky Mountain




Region which includes the states of Colorado, New Mexico and Utah.




Three levels of Western energy development are considered for the years




1980, 1985, 1990 and 2000 based on the Stanford Research Institute




energy model.









1.2  Summary of Findings and Conclusions




     A preliminary assessment has been made of the minimum water con-




sumption and the solid residuals generated in synthetic fuel plants




and coal-fired steam-electric generating plants sited in the West.




Approximate regional estimates and projections have been made based on




three different levels of energy demand.  The results show some esti-




mated plant water consumptions as much as a factor of three below the




lowest published design estimates.  It is indicated that with more




detailed study of optimized water treatment and use large reductions




in water consumption and residual discharge are possible.  Under these




conditions there will be larger variations in water consumption with




site, and these should be studied.  The results also point up that




detailed regional environmental impacts cannot be properly assessed




without further determinations of local and regional water supply and




demand data and residual disposal methods.

-------
     The study findings and conclusions are presented below on the


basis of total site-specific water consumption and residuals, a break-


down of these quantities, and regional water consumption and residuals.



     Total Site-Specific Water Consumption and Residuals


     Table 1-2 summarizes the study findings on the net annual water


consumption and wet solid residuals generated at each site for the unit


size mine-plant complexes assumed to be located there.  Table 1-3


summarizes the net water requirements in terms of gallons per million Btu


of fuel produced (gal/10  Btu) with no distinction made as to consumption


between the sites but with overall ranges given instead.


     Some of the major but necessarily tentative conclusions of this


study are the following:


     1.   Lurgi gasification facilities have the largest variation in


net water consumption as a function of site, ranging from

            3
3.3-5.6 x 10  acre-ft/yr,  principally as a consequence of differences


in coal moisture at the different locations.


     2.   The variations in water consumption with site for the Synthane


and Synthoil facilities are found to be relatively small being no more,


respectively, than 13% and 16%.   However,  for the steam electric power


generating plants a maximum difference in water consumption of 25% is


noted.   These same findings do not hold for the residuals.


     3.   Synthane facilities use from 1.5-2.3 times the water that a


Lurgi facility does at the same site partly because the Lurgi process


accepts wet coal and utilizes the moisture,  although at a cost.   This


same moisture could in principle be recovered in Synthane plants in coal


drying, and this should be studied.

-------
         Table 1-2.   Summary  of net annual water consumption and  wet solid residuals generated at each site.
FACILITY
SLURRY PIPELINE (25 x 106 tons/yr 8 100% load factor)
NET WATER CONSUMED - 103 ACRE-FT/YR*
WE? SOLID RESIDCALS  10s TONS/YR
LURGt (250 x 106 scf/stream day @ 90% load factor)
NET WATER CONSUMED - 103 ACRE-FT/YR
WET SOLID RESIDUALS - 106 TONS/YR
SVMTHANE (250 x 106 set/stream day @ 90% load factor)
NKT WATER CONSUMED - 103 ACRE-FT/YR
'.XT SOLID RESIDUALS - 106 TONS/YR
SYNTUOIL (100,000 bbl/stream day g 90% lead factor)
NET MATED CONSUMED - ID3 ACRE-FT/YR
WCT SOLID RBSIDUALS - 106 TOMS/YR
ELECTRICAL GENF.RATION (3,000 HWe ? 35% et, 70* load factor)
KET V.'ATER CONSUMED -- 103 ACRE-FT/YR
WET SOLID RESIDUALS  106 TONS/YR
ELECTKICAL GENt-'HATION (1,000 M*e S 35* eff, 70 load factor)
NET WATER CONSUMED - 103 ACKB-FT/YR
WET SOLID RESIDUALS - 10s TONS/YR
OIL SHALE (50,000 bbl/stream day 8 90% load factor)
NET WATSB CONSUMED - 103 ACRE-FT/YR
WET SOLID RESIDUALS - 106 TONS/YR
OIL SIIALE (100,000 bbl/stream day 8 90% load factor)
Ni.T WATER CONSUMED - 103 ACRB-FT/YR
WET SOLID RESIDUALS - 106 TONS/YR
BEULAH,
NORTH DAKOTA

3.31
1.20
7.67
1.08
10.09
2.00
23.88
2.65



COLSTHIP,
MONTANA

4.62
1.27
7.81
1.12
10.30
2.07
26.66
3.01



GILLETTE,
WYOMING
19.17
4.21
0.72
7.78
0.71
9.23
1.23
25.84
1.32



KAIPAROWITS/
ESCALANTE,
UTAH




29.82
5.30



NAVAJO/
FARMINGTON,
NEW MEXICO

S.64
3.00
8.67
2.84
11.75
5.31
29,21
5.00



RIFLE,
COLORADO





9.49
0.38
6.48
20.40
12.92
40.81
To convert 103 acre-ft/yr to 1Q6  tons/yt multiply by 1.36,
 to convert 10^ acre-ft/yr to 10&  gal/day multiply by 0.894.

-------
          Table 1-3.  Net water consumed for Western coal sites
                      per million Btu of heating value in product.
                                         Net Water Consumed
                 Facility                  (gal/lQ6 Btu)
                 Lurgi                          14-24
                 Synthane                       32-36
                 Synthoil                       15-19
                 Oil Shale                       23
                 Slurry Pipeline                 14
                 Electric Generation            43-54*
                 *gal/10  Btu of heating value of input coal.
     4.   The net water consumption of Synthoil and TOSCO II oil shale
facilities producing the same output of 100,000 bbl/day are roughly the
                                 3
same at between 9.2 and 12.9 x 10  acre-ft/yr, with the oil shale con-
sumption at the upper end of the range.
     5.   With the design procedures used in this study and with proper
water treatment design the Lurgi, Synthoil,  oil shale and slurry pipeline
water requirements are roughly the same with s. mean around 18 gal/10  Btu
when expressed per unit of heating output.  The slurry pipeline require-
ment is at the lower end of the spread, while oil shale is at the upper
end.  The Synthane facilities require about 2 times more water.  The
water for electric power generation is by far the largest requiring
2.5 times mor,e water, as measured in terms of the heating value of the
input coal.
     6.   For a given facility the quantity of solid residuals is very
site dependent.  For all the coal-to-fuel and electric generating
                                 7.

-------
processes the largest variation between sites is more than a factor




of 4, with a range for surface mined coal of 2.8-5,0 x 10  tons of wet




solids per year at Navajo, New Mexico to a corresponding range of




0.7-1.3 x 10  tons/yr at Gillette, Wyoming.  The large quantity of




solid residuals at Navajo is associated with the high ash content of




the coal.




     7.   Outstripping all the coal conversion residuals by an order




of magnitude are those from surface oil shale processing; where the




primary residual is the wet spent shale amounting to 41 x 10  tons/yr




for a 100,000 bbl/day plant,





     Site-Specific Water Consumption and Residual Breakdowns




     Figures 1-1 to 1-3 show breakdowns of the consumed water by use




and of the wet solid residuals by type.  The breakdowns are given in




Fig. 1-1 for the production of 250 x 10  scf/day of synthetic natural




gas by the Lurgi and Synthane processes; in Fig. 1-2 for the production




of 100,000 bbl/day of synthetic fuel oil by the Synthoil process and




from oil shale by the TOSCO II process; and in Fig. 1-3 for the genera-




tion of 3,000 MWe of electricity by coal-fired steam generation.  The




sites indicated correspond to those called out in Table 1-2.




     As noted in the Introduction, five separate categories of water




consumption were calculated in some detail.  For clarity of graphical




presentation, these categories and their subcategories are combined




into three major use groups: (1) process and flue gas desulfurization




(FGD), (2) cooling and (3) solids disposal, mining and other.  Although




in the detailed analyses solids disposal is broken down into a large




number of categories, for simplicity of presentation they are here

-------
                      250X|06SCF/DAY
(Or
  SYNTHANE
                     WATER 
-------
                       100,000 BBL/OAY
14
12
10
   SYNTHOIL
                     WATER (I03ACRE-FT/YR)
                        MINING. DISPOSAL,
                           ,OTHER-
                                         SYNTHOIL
               SYNTHOIL
                                         PROCESS
                                                     OIL SHALE
                                                         ui
                                                         o
                                                         o
                                                         a:
                                                         a.
BEULAH
 6r
 4 
                -)
               COLSTRIP
                            GILLETTE
                                          NAVAJO
                   WET SOLIDS  (I06TONS/YR)
               y/A
               'ASH J
                             / /
                                                    RIFLE
                                                             40



                                                             38

                                                             6
   BEULAH


 Fig. 1-2.
               COLSTRtP
                        GILLETTE
NAVAJO
RSFLE
             Breakdown of net annual water consumption and
             wet solid residuals generated in the production
             of 100,000 bbl/stream  day of fuel oil by the
             Synthoil process at different Western sites and
             by the TOSCO II oil shale process at Rifle,
             Colorado.
                                   10

-------
32 r
28 -
20
 16
 12
                          3,000 MWe

                      WATER (103ACRE-FT/YR)
                   DISPOSAL, MINING,OTHER
                 FGD
                                           FGD
   BEULAH
COLSTRIP
GILLETTE
KAIPAROWITS
NAVAJO
    7]
                    WET SOLIDS  (I06TONS/YR)
                ft
   6D
 SLUDGE
     I
                                           'w :
                                            u-';v.'i
                                           ,'K;"
   BEULAH
COLSTRIP
GILLETTE
KAIPAROWfTS
NAVAJO
  Fig. 1-3.  Breakdown of net  annual water consumption and
             wet solid residuals generated in the production
             of 3,000 MWe/stream day of electricity by coal-
             fired steam-electric generating plants at differ-
             ent Western sites.
                               11

-------
combined into the following main groups:  (1) ash, (2) flue gas




desulfurization (FGD) sludge, (3) spent shale, (4) coal refuse and




(5) other wastes.  In the groups of Figs. 1-1 and 1-3, generally only




two types of waste are indicated and in Fig. 1-2 only one type,




because the contributions of the remaining types are negligibly small




on the scales of the figures.




     The major conclusions of this phase of the study are the following:




     1.   The largest quantity of water consumed in all facilities,




except oil shale, is the water evaporated for cooling.  These water




requirements are highest for electric power generation when compared




to the other processes, because for the same energy input the genera-




tion of electricity has the lowest thermal efficiency.




     2.   Cooling is needed to dissipate about 75% of the unrecovered




heat in the fuel-to-fuel and electric generating plants.  Whether to use




wet cooling, dry cooling or wet/dry cooling depends on the cost of water,




including any necessary treatment, although at least 25-50% of the




unrecovered heat in the fuel plants- should be dissipated by dry cooling.




     3.   For electric generation at Navajo, New Mexico when water




costs about $2.20/1000 gal, partial dry cooling is more economical than




all wet cooling.  For this water cost at all other sites, all evaporative




cooling systems are preferable if sufficient water is available.




     4.   Estimates for the Synthoil and Synthane plants are based on




all wet cooling of turbine condensers.  Cooling water requirements for




the Lurgi plants are taken from existing designs and are about 2/3 that




for Synthane except at Navajo, New Mexico where it is about 1/2.  Wet/dry




cooling was not examined but could reduce the cooling water requirement
                                   12

-------
 to  about  25%  of  that  used and  probably  becomes  economically viable




 when  cooling  water  costs  $1  to $1.50/1000  gallons  evaporated  for  cool-




 ing,  although this  would  have  to be  checked  in  a future  study.




      5.   Wet scrubbing of stack gases  for sulfur  removal  represents




 a large fraction of process water  usage in Lurgi and  Synthane plants




 and is a  large consumer of water in  electric generating  plants.   The




 largest quantity .of this  water leaves as saturated vap.or in the flue




 gas and the amount  depends critically on the flue  gas saturation




 temperature.




      6.   Most of the solid residuals leave  the plant boundaries wet




 and for the Lurgi,  Synthane and Synthoil facilities, with  surface




 mined coal,  the greatest part of this solid waste is ash  with  a weight




 percent water  averaging around  25%.  For electric  power  generation,




 except for the high ash Navajo coal, about half of the residuals is




 the sludge generated by flue gas desulfurization and the other half




 is ash.  The combined weight percent of water averages around 38%.  In




 underground mining  the largest fraction of the solid waste is coal




 refuse with a  30% weight of water.




     7.   In surface mining the largest use of water is  for dust




 control,  except when water is required for mined land revegetation,




which for the sites examined is only necessary at Navajo, New Mexico.




The actual quantities of water are quite site dependent.   In under-




ground mining, examined only at Kaiparowits,  the largest  quantity of




water is required for coal washing.




     8.   In oil shale processing,  where the tonnage mined and the




solid residuals generated are the largest of  all the processes,  the
                                 13

-------
                             3
water consumption is 1.8 x 10  acre-ft/yr for mining and

        3
4.1 x 10  acre-ft/yr for solids disposal and other uses.


     9.   Although the principal solid residuals from coal conversion


and processing are generally harmless, they do contain trace quantities


of harmful elements and compounds.  It is possible that the disposal of


the large quantities of wet residuals identified could lead to a


collective problem in the dispersion of the hazardous materials, but


this must be examined.



     Regional Water Consumption and Residuals


     Fig. 1-4 summarizes the study findings on the aggregated net


annual water consumption and wet solid residuals generated in the


region of the West in which energy development is focused.  The three


levels of energy development are based on the Stanford Research


Institute energy model with low end-use demand, nominal end-use demand


and low nuclear availability.


     The major findings and conclusions are:


     1.   For all levels of energy development considered, the aggregated


net\regional $ater consumption in the Western coal and oil shale areas


increases by a. factor of 9-10 between the years 1980 and 2000, while


during the same period the wet solid residuals increase by a factor of


75-100.  This large increase in residuals is associated with the role of


surface oil shale processing and the need to dispose of the spent shale.


     2.   On the basis of the quantities of water consumed and residuals


generated, Colorado appears to be the state most affected by energy develop-


ment in the Rocky Mountain Region.  This is due principally to the pro-


jected rapid growth of a surface processing oil shale industry.  Montana
                                 14

-------
2600 r
2200
 1800
 1400
 tooo
 600
                       WATER (IQ3ACRE-FT/YR)
 200
    LOW  DEMAND

[~~] NOMINAL  DEMAND

[771 LOW  NUCLEAR
     X
        I960
1985
                               1990
 240
  160
  80
                     WET SOLIDS  (!06TONS/YR)

        	SPENT SHALE             -_
                      \
        1980
   Fig.  1-4.
1985
                               1990
2000

                                                            2000
                                                     1600
                                                     800
                                                    400
2000
      Regional net  annual water consumption and wet
      solid residuals  generated in the Western coal, and
      oil shale areas  between the years 1980 and 2000
      for three levels of energy development.
                               15

-------
is the most affected state in the Powder River Region, principally




because of the projected growth of slurry pipeline development and




coal-fired steam-electric power generation.




     3.   The actual environmental impacts of siting synthetic fuel




and electric power generation facilities cannot be properly assessed




without an appropriate determination of local and regional water




supply and demand data, and residual disposal methods.
                                 16

-------
                    2.  COAL CONVERSION PROCESSES



     In this section are described the methods used to determine the process


water and cooling water requirements for the Synthoil, Lurgi and Synthane


coal conversion processes.  Because different information is available for


each process the details of the procedures differ from process to process.


However in each case the same broad outline was used: (i) First the hydrogen


balances around the plant were made to determine net process water require-


ments (in some of the plants using a very moist coal there is a net production


of water).  (ii) Current designs were used to determine the cooling water


requirements for the Lurgi process.  (iii) For the Synthoil and Synthane


processes the plant thermal efficiency and the quantity of unrecovered heat


were estimated.  We then determined how this unrecovered heat was lost to the


atmosphere, whether directly as up a stack, or through a heat transfer surface.


Finally, for that heat which was lost through a heat transfer surface we


determined, by economic considerations, whether the heat exchanger could be


directly air cooled or whether evaporative water cooling was required.  The


discussion on cooling together with the relationship between heat lost and


water evaporated is given in Section 2.3.



2.1  Synthoil Process


     The Synthoil process for hydrogenating coal to a heavy oil has been

                                                                            *
described in many publications by  the Bureau of Mines including References 1


to 4.  The only integrated plant design (including hydrogen production) which
*  References are given at the end of each section.
                                  17

-------
we have seen  is  that  of Ref.  3 made  for a Wyoming  coal and made  specifically
for  cost estimating purposes.  For the purpose of  estimating water require-
ments we have  chosen  to make  our own, somewhat simplified design, using
the  block diagram from Ref. 3 reproduced as Fig. 2-1 in a form suitable
for  present purposes.  The overall material balances, not including hydrogen
production, were made using the following rules and are presented in
Tables 2-1 to  2-4.
     (a)  Overall material balances
          1.   100,000  bbl/stream day of oil equals 1.4 x 10  Ib/stream hr
(Ref. 3) and the oil  is assumed to be 90 wt. % carbon, 8.5 wt. % hydrogen
and  1.5 wt. %  oxygen, nitrogen and other elements.
          2.   We assume that 5 barrels of oil are produced from each ton
of carbon in the coal.  This  is the average of published results:

               Ref. No.               bbl oil/ton carbon in coal
                 1                             5.3
                 2                             5.0
                 3                             4.7
          used in this work                    5.0

The feed to the reactors (streams 2 and 5) must, therefore, contain
1.67 x 10  Ib/stream hour of carbon.  Coal is assumed dried to 0.5 wt. % moisture.
This moisture is assumed to remain in the product oil,
3.   Hydrogen requirements have been given as:

              Ref. No.                  scf H2/bbl oil
                 1                           4200
                 2                           4730
                 3                           4830
          used in this work                  4700
                                  18

-------
COAI
Q.
                     ^
                    1
                 WATER
                 VAPOR
COAL
PREPARATION
& DRYING
                       HYDROGEN
                HYDROGEN
                PRODUCTION
                S
                COMPRESSION
       STEAK   OXYGE!.1  WATER
         &             CONDENSATE
                                                         RECYCLE OIL
COAL
SLURRY
PREPARATION
230F
             HEAT
          ' EXCHANGER

           I
           I
                                    RECYCLE  GAS
                                    PURIFICATION
                                                                               800F
                                                    PHASE
                                                    SEPARATION
                                                      WATER
                                               CON DENS ATE <1 -V
                                                   CHAR
                                                                 CHAR
                                                                 DE-OILING
                                      Fig.  2-1,   Synthoil process.
                                                                                           REACTOR
                                                                                                      OIL
                                                                                        GAS
                                                                                              -* SALES GAS

                                                                                              -> PLANT FUEL

-------
    Table 2-1.  Material balance on Synthoil plant exclusive of
                   hydrogen production for Colstrip, Montana.
Units: 10  Ib/stream hr
Stream
2
4
5
6
7
8
9
No.
Coal, as received
Water lost in drier
Coal, dry
Make-up hydrogen
Oil
Gas
Char
Total -Moisture C H
3303 816 1670 105
816 804
2500 12 1670 105
148 19 103
1490 12 1340 127
246 51
103
0
324

324
26



  13      Water from phase
            separation
296
30   266
                                 20

-------
    Table 2-2.  Material balance on Synthoil plant exclusive of
                 hydrogen production for Beulah, North Dakota.
Units: 10  Ib/stream hr
Stream No.
Total     Moisture    C     H
2
4
5
6
7
8
9
Coal, as received 4130
Water lost in drier 1473
Coal, dry 2657
Make-up hydrogen 148
Oil 1490
Gas
Char
1486 1670 112 492
1473
13 1670 112 492
19 103 26
13 1340 127
246 36
103
  13      Water from phase
            separation
 464
52   412
                                  21

-------
    Table 2-3.   Material balance on Synthoil plant exclusive of
                   hydrogen production for Gillette,  Wyoming.
Units: 10  Ib/stream hr
Stream No.
Total     Moisture    C      H     0
2
4
5
6
7
8
9
Coal, as received 3381
Water lost in drier 935
Coal, dry 2446
Make-up hydrogen 148
Oil 1490
Gas
Char
947 1670 115 432
935
12 1670 115 432
19 103 26
12 1340 127
246 46
103
  13      Water from phase
            separation
 408
45   363
                                  22

-------
    Table 2-4.  Material balance on Synthoil plant exclusive of
             hydrogen production for Navajo/Farmington, New Mexico
Units: 10"" Ib/stream hr
Stream No.
Total     Moisture    C     H
          Coal, as received
3532
438    1670   122   338
          Water lost in drier
 422
422
          Coal,  dry
3110
 16    1670   122   338
   6      Make-up hydrogen
 148
         19   103    26
          Oil
   8      Gas
1490
 16    1340   127


        246    63
          Char
                     103
  13      Water  from phase
            separation
 313
               35    278
                                  23

-------
The hydrogen in stream 6 is, therefore 5.16 x 10  moles/stream hr or

        3
103 x 10  Ib/stream hr.  Stream 6 is taken to be 97% H2 and 3% CO.


          4.   The carbon in the char has been given as:



       Ref. No.                Carbon in char as % of carbon in coal

          1                                     6


          3                                 about 6^3


   used in this work                           6.2


                                        3
so the char (stream 9) contains 103 x 10  Ib/stream hr of carbon; the


hydrogen and oxygen are assumed to be negligible.


          5.   The oxygen in the coal is assumed converted as follows:


                     10^ to gas and oil.

                            3
                     26 x 10  Ib/stream hr reacts with CO in stream 6 to


                          yield CO- which remains in the gas.


                     The balance is converted to water, stream 13.


          6.   The balance of the carbon and hydrogen appear in the gas.



     b.   Hydrogen production


          There are many ways to make hydrogen: (i) The gas can be put through


a steam reforming reaction (this is quite efficient but necessitates burning


char and coal for plant energy and both char and coal contain sulfur) .


(ii) The char, with added coal, can be partially oxidized (gasified) to make


synthesis gas which can be converted to H~ by the shift reaction (this pro-


cedure yields the sulfur as HUS which can be readily removed; the gas produced


in the oil plant is also stripped of H2S and is then burnt as a char fuel).


We have assumed that gasification is used and the hydrogen production train is


shown in Figure 2-2.  Extrapolating from Ref. 3 the following rules were used


to calculate the various water streams of Figure 2-2.


                                    24

-------
COAL
& CHAR
I


GASIFIER
1800F
450 psig
STEAM
ACID GAS
REMOVAL
1
' to


^ 300P



QUENCH
t
WATER
WASTE
HEAT
RECOVERY
i /mp /"A
0 kf A/




500 F
410

psig
i
95F ^
	 	 " 	 \ / V '
r

FIRST
STAGE
SHIFT
(950F)
1

r
SECOND
STAGE
SHIFT
(550F)

HYDROGEN
COMPRESSION
900F ^

DIRT
COND
{ 	 STEAJ


>
f

HEAT
EXCHANGER
i
/ ^
2NSATE
<
r
^



300F


<
|

f
ACID GAS
REMOVAL
^

f
IRON OXIDE
&
CHAR TOWER


*-
                            cw
 V    	
CLEAN
CONDENSATE
                         Fig.   2-2.   Hydrogen  production  train..

-------
          1.   The gasifier is pressurized aad yields hydrogen at 390 psig



which is compressed to 4000 psig for use in the Synthoil reactor.



          2.   The gasifier off-gas comes off at 1800F and contains


         4                                   4
2.22 x 10  moles/stream hour H2 and 3.10 x 10  moles/stream hr CO.  At



Beulah, North Dakota more synthesis gas is produced as explained in rule



No. 8.  After shift reaction this stream will give stream 6.



          3.   The gasifier is supplied with 0.5 Ib of steam/lb  of  carbon



fed to the gasifier.



          4.   Enough coal is added to the char so that when the material



balance is complete the gasifier will be in thermal balance.  The coal carbon



required varies with moisture in the coal.



          5.   The carbon in the coal plus char appears as CO + C0~ which



gives the CO,, rate.



          6.   The water in the off-gas satisfies the hydrogen balance.



          7.   The oxygen fed satisfies the oxygen balance.



          8.   In one case, Beulah, North Dakota, extra HL + CO are made and



used as fuel because there is not enough energy in the Synthoil gas to drive



the plant.



          9.   The gases leave the first shift reactor in equilibrium at



750F and the second shift reactor in equilibrium at 550F.  The gasifier



off-gas is quenched by direct addition of water.  This, in fact, proved to



yield a surplus of steam for the shift reaction and a waste heat recovery



unit would improve the plant efficiency.



     Total hydrogen balances are presented in Table 2-5.
                                  26

-------
               Table 2-5. Water equivalent hydrogen balance of Synthoil plant at four sites.
                          IN
Moisture in as-received coal to liquefaction
Water equiv. of hydrogen in as-received coal to liquefaction
Moisture in as-received coal to gasifier
Water equiv. -of hydrogen in as-received coal to gasifier
Total steam to hydrogen production
Quench water to hydrogen production
                                                       Total

                          OUT
From drying coal to liquefaction
Total dirty process condensate
Clean process condensate
Water equiv. of hydrogen in product oil
Moisture in product oil
Water equiv. of hydrogen and moisture in gas produced
                                                       Total
10 lb/ stream hr
Cols trip ,
Hont.
816
945
170
197
495
712
3335
804
785
144
1143
12
459
3347
Beulah ,
N.D.
1486
1008
399
270
467
670
4300
1473
1101
96
1143
13
*
465
4291
Gillette,
Wyo.
947
1035
178
194
511
528
3393
935
759
132
1143
12
414
3395
Navajp ,
N.M.
438
1098
83
207
529
581
2936
422
635
139
1143
16
567
2922
* Includes the surplus synthesis gas produced in gasifier and burned as plant  fuel.

-------
     c.   Plant energy requirements




          An estimate of the energy needed to drive the plant was obtained




by adding the following requirements:






                 coal




                 slurry pump




                 slurry and hydrogen heating




                 char  deoiling




                 oxygen production




                 hydrogen plant steam




                 hydrogen plant waste heat recovery




                 hydrogen plant CCL  removal




                 gasifier lock hoppers




                 hydrogen compression




                 plant electricity




                 water treatment and other low




                      temperature energy consumers




                 stack gas losses






These are the principal, but not all the energy loads in the plant.  The




approximate heat loads of the plant are shown in Table 2-6.  Since all the




energy requirements may not have been found, the stated efficiencies may be




high.  This will not affect the cooling water.  Much the most important




difference from plant to plant is the energy consumed in drying coal.  This




is low enough in Navajo/Farmington, New Mexico, that the product sold includes




quite a lot of gas.  Drying coal consumed so much energy in Beulah, North




Dakota, that some gasifier off-gas had to be burnt.






                                   28

-------
                  Table 2-6. Approximate total heat load of Synthoil plant at four sites.
N>
Drying coal to liquefaction




Slurry pumps




Heat exchanger and phase separator




Char deoiling




Coal and char feeding to hydrogen production




Acid gas removal in hydrogen production




Waste heat recovery in hydrogen production




Hydrogen compression




Oxygen production




Electricity generation




Water treatment and other low level uses




Boiler stack gas loss




                      Approximate total heat load
10 Btu/stream hr
Co Is trip ,
Mont.
0-.90
0.36
0.80
0.45
0.03
1.00
(-0.76)
0.97
0.92
0.32
0.50
0.61
6.10
Beulah ,
N.D.
1.65
0.39
0.82
0.45
0.04
1.04
(-0.94)
0.97
1.16
0.32
0.50
0.72
7.12
Gillette ,
Wyo.
1.05
0.36
0.79
0.45
0.03
0.93
(-0.56)
0.97
0.72
0.32
0.50
0.62
6.18
Navaj o ,
N.M.
0.47
0.45
0.89
0.45
0.03
0.93
(-0.54)
0.97
0.76
0.32
0.50
0.58.
5.81

-------
     In  calculating  Table  2-6 we  used  the  following  procedures.   The  slurry


contains two pounds  of oil per pound of  coal  and  the pumps were  70% efficient.


The heat loads to  the dissolver heating  section and  char  deoiling section


were estimated using the detailed design of Ref.  3.   Coal and  char are


assumed  fed to the gasifier using a lock hopper;  lock hopper compressor

                              t-
requirements were  scaled from Ref. 5.  The acid gas  removal system was


assumed  to be the  Benfield hot potassium carbonate system ,  Compressor


energies are listed  in Table 2-7  which includes other compressors needed for


the Synthane plant.  The heat rate to  all  turbine drives was 11,700 Bfu/kw-hr.


The energy needed  to drive an oxygen plant is  the energy to compress  air to


90 psia  plus the energy to compress oxygen from 20 psia to gasifier pressure.


The electricity plant produces 27,000  kw.  The low level uses  of heat are an


arbitrary addition.  The boiler stack  gas  loss is 10% of the fuel burnt.


     The approximate plant thermal efficiencies are  shown in Table 2-8.



     d.   Ultimate disposal of unrecovered heat


          The plants must be in thermal  balance.  That part of the energy


in the feed coal which is  not sold as  oil or gas must leave the plant in


some unrecoverable low level form.  To determine whether cooling water is


needed we estimated  the low level heat that leaves the plant (i) directly


through  stacks (including water vapor) by  convection, etc.,  and  (ii) by transfer


to water in a cooling tower.  One big  load, the condensers in  the regenerators


of a Benfield CO^ removal  system, is dry cooled (as  is currently practiced in


selected cases)  which accounts for about 2/3 of the  dry cooling load-.


Evaporative cooling was used for all compressor interstage coolers and the


condensers on all steam driven turbines  for all plant moving machinery and


electrical generation.   This accounts  for about 2/3  of the evaporative cooling


and could,  in extreme water short areas,  be replaced by dry cooling.


                                  30

-------
Table 2-7.  Gas compressor energy and interstage cooling requirements
                         for Synthoil and Synthane plants.
     Conditions:  Stage entry temperature 95F; polytropic efficiency 77%

     Basis:       2000 Ib gas/hr
       Gas
Pressures (psia)
 Inlet     Exit
         No. of
         Stages
 Drive
Turbine
  (kw)
 Interstage
   Coolers

(103 Btu/hr)
     Air
   15
  90
    59
                                                                     200
     Oxygen
   20
 465
    92
                                                                     240
     Oxygen
     Hydrogen
   20
  405
1015
4015
   120
  1115
                                                                     340
                                                                    2880
                                                                        ***
     *     4.32 Ib air yield I Ib oxygen.

     **    Aftercooler  to 95F included.

     ***   Forecooler, 140 to 95 included.
                                      31

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     Table 2-8.  Approximate thermal efficiencies of Synthoil plants,
                                   10  Btu/stream hr

                     Colstrip ,    Beulah,     Gillette,    Navajo,
                     Montana       N.D.       Wyoming       N.M.
Heating value of
   coal feed
34.4        35.8
             33.9        34.8
Heating value of
  product oil
26.2        26,2
             26.2        26.2
Heating value of
  gas sold
 0.6
              0.2
             1.7
Unrecovered heat        7.6
             9.6
              7.5
             6.9
                       34.4        35.8
                         33.9        34.8
Overall thermal
  efficiency
78%
73%
78%
80%
                                  32

-------
      The  results  are  shown  in Table  2-9.   Direct  losses  are  caused by  coal




drying, boiler  stack  losses,  char  deoiler  stack losses,  electricity  used,




pump  and  compressor losses  and an  allowance  for convection losses.   At




Beulah, North Dakota,  some  gasifier  off-gas  is burnt for fuel  and as this is




wet the stack losses  are higher than at other sites.  The air  cooling  losses




are the Benfield  acid  gas removal  regenerator condenser  and  cooling  of gas,




oil and hydrogen  from 300 to  140F,  At Beulah, North Dakota,  the recovery of




condensed water from  the Benfield  system increases the cooling load  over




other sites.  The remaining losses have been assigned to wet cooling so as




not to understate the  water requirements.  As discussed  in Section 2.3, all




turbine condensers and compressor  interstage coolers are wet cooled.






2.2   Process Water Streams




      The water  consumed for the process is shown  in the  summary tables of




Section 10 and was calculated from the process description as  follows.




      (i)  The dirty plant condensate (which  is about half from the oil




section of the plant and about half  from the gasification section of the




plant) was assumed sent to water treatment where  about 1.8%  of the water




was lost  (see Table 2-10).  The sludge produced in Tjiotreatment, which is




80% moisture, is  0.75% of the weight of the  treated water; Che water in the




sludge is 0.6% of the  weight of the  treated  water.




      (ii) Clean process condensate was not sent to treatment.




      A sample calculation for the  Synthoil process at Colstrip, Montana follows:
                                  33

-------
Table 2-9. Ultimate disposition of unrecovered heat in Synthoil plants.
                                 10  Btu/stream hr
Points of load
Coal drying
Stack loss, including
char deoiling
Electricity used, slurry
pump loss
Other direct losses
Subtotal - direct loss
Acid gas removal regen-
erator condenser
Air cooling in phase
separator and other
process streams
Subtotal - dry cooling
Turbine drive condenser
Compressor interstage
cooling
Additional wet cooling
load
Subtotal - wet cooling
Total unrecovered heat
Cols trip ,
Montanta
0.90
0.81
0.20
0.19
2.1
1.00
0.40
1.4
1.82
0.58
1.70
4.1

7.6
Beulah ,
N.D.
1.65
1.02
0.21
0.22
3.1
1.44
0.46
1.9
2.02
0.65
1.93
4.6

9.6
Gillette ,
Wvomine
1.05
0.82
0.20
0.13
2.2
0.93
0.47
1.4
1.68
0.51
1.71
3.9

7.5
Navajo ,
N.M.
0.47
0.78
0.23
0.22
1.7
0.93
0.47
1.4
1.77
0.53
1.62
3.8

6.9
                                34

-------
 Table 2-10.  Water lost in condensate water treatment
Basis: 10  Ib water treated.
                                     Gas plant
Oil plant
Ib NH~ in wastewater*
Ib water lost with NH3
in 40% solution
Ib BOD*
Ib wet sludge (80% moisture) **
Ib water in sludge
Total water lost , with ammonia
& in sludge
3
5
13
6.5
5
10
14
21
17
8.5
7
28
  *  Typical analysis.




 **  0.1 Ib dry sludge/lb BOD removed,  Ref.  7.
                                  35

-------
                                               10  Ib/stream hr



Stream and quench water fed (Table 2-5)              1207



Clean condensate recovered                          (-144)



Dirty water to treatment                            (-785)



Lost in treatment                                      14



     Net process water consumed                       292






      .    ~3    Ib        1 gal    0.9 stream hr    1 calendar hr

                stream hr   8.33 Ib    calendar hr    60 calendar min




                      = 526 gal/calendar min .





Water in condensate treatment sludge =





            ,Q,   ,^3    Ib       O.Q06 Ib water in sludge
            785 x 10  -'	T x 		.
                      stream hr       Ib water treated





                        n nm o gals/calendar min   ~   ,/-,,
                      x 0.0018 & ,,  . 	r	 = 9 gals/calendar mm .
                                 Ib/stream hr        6




     The boiler makeup water has been taken to be 100 gal/calendar min more



than the steam quantity shown in Table 2-5.  The demineralizer waste is taken



to be 50% moisture and to have a solids content of 1.6 times the total



dissolved solids in the makeup water.  This corresponds to complete



deionization of the makeup water and a regenerant usage of 160% of the



stoichiometric values.  The makeup water is usually source water but may be



treated process condensate if this has not all been used for cooling.



Table 2-11 was used to calculate demineralizer waste.   A sample calculation



to estimate boiler demineralizer waste at Colstrip, Montana follows:
                                  36

-------
    Table 2-11.  Demineralizer water treatment waste.
                                      tons wet sludge (50% moisture)
                                      per 1000 gal water evaporated
Colstrip, Montana
0.0053
Beulah, North Dakota
0.0057
Gillette, Wyoming (Yellowstone)
0.0053
Gillette, Wyoming (North Platte)
0.0055
Rifle, Colorado
0.0032
Navajo/Farmington, New Mexico
0.0040
Kaiparowits/Escalante, Utah
0.0077
Treated process condensate
0.0096
                                  37

-------
Steam makeup:





               ,3    lb       0.0018 gal/calendar min  . ,nn     gal
       495 x 10

                 stream hr        lb/stream hr             calendar min
                      = 991 gal/calendar min  .
Wet sludge:
         991 gal      0.053 tons   1440 min   _ _,      ,  ,   ,    ,
       ;j	~ x TAOA *i x j	 = '.56 tons/calendar day
       calendar min   1000 gals      day
Dry solids:
           0.50 x Wet sludge = 0.5 x 7.56 , fcns  . =3.78 tons/calendar day
                                          calendar day
Water in waste:
       7.56 tons wet sludge   0.5 tons water   2000 Ib/ton     1 gal

         calendar day          tons sludge     1440 min/day   8.33 lb




                -, cs           ,  ,   .  ,   ,    ,      00/  gal water/calendar min
              = 7.56 tons wet sludge/calendar day x 0.0834 -*	n  ,   ,:;	3	1
                                                           tons sludge/calendar day




              = 0.6 gal/calendar min .
2.3  Cooling Water



     Some of the heat not recovered in coal conversion plants is lost  to  the



atmosphere through a heat transfer surface.  This surface  can be directly



cooled by air  (which is called dry or air  cooling) or it can be cooled by



circulating cooling water which is itself  cooled in an evaporative  cooling



tower  (which is called wet or evaporative  cooling).  In general wet cooling



requires a lower capital investment than dry cooling, can  cool to a lower
                                  38

-------
temperature, but does require  water.  Water is not free.  It costs about


2c to move one thousand gallons of water one mile through a horizontal


pipeline.  It costs $0.50 to $1.00/thousand gallons of water evaporated to


treat water in a circulating cooling system and to dispose of the solid

        8
residues .  The decision as to whether to use wet or dry cooling will depend


on the cost of water and its treatment, and will be different for each point


of cooling in the plant.

                                                            9
     The cooling of plant process streams has been evaluated  and based on


that evaluation all process streams have been assumed to be cooled to 300 F


with waste heat recovery, from 300  to 140 F by dry cooling, and below


140 F by wet cooling.  The cooling water requirement depends on the tempera-


ture to which the stream must be cooled.  The cooling water required for


process cooling is very low and this is corroborated in many actual plant designs.


     The gas purification system regenerator condenser cooler, which is a


very large load, is discussed in Ref. 9.  This will be dry cooled by using a


hot potassium carbonate system for the Synthoil and Synthane processes.


     The gasifier off-gas in the Synthane process is quenched to 270 F by


direct water contact.  As discussed in Ref. 9 the circulated water is cooled


in a dry cooler.


     Much the most important use of wet cooling is for the condensers.on


steam turbine drives used to drive gas compressors, slurry pumps, electric


generators and other mechanical loads on the plant.  For this type of steam


turbines, the thermal efficiency reaches its maximum when the exhaust pressure


is between 3 and 5 inches Hg.' absolute.  The corresponding condenser tempera-


tures are 115 and 134F.  Typical turbine inlet steam conditions are tempera-


ture  in the range from 700 to 900F and pressure in the range from 715 to 915 psia.
                                  39

-------
Based on  these  inlet  conditions,  a  typical  turbine  efficiency  of  80%,  and




a bearing efficiency  of  97.5%,  the  heat  rate  to  the turbine per kw power




output is about 11,700 Btu/hr when the  condenser  temperature is 115 F,  and




goes up linearly  to about 12,200 Btu/hr when the  temperature is 134 .   The




corresponding heat rejection rates  in  the condenser for  these  two  temperatures




are about 8,200  Btu/hr and 8,700  Btu/hr.   The thermal efficiency of  the  cycle




when the  condenser temperature  is between 115  and 134 F  is therefore




approximately 30%.




     The  economics of whether dry cooling or wet cooling should be used




have been analysed in a  manner  similar to Ref. 9 for the following four sites:




Colstrip, Montana; Beulah, North  Dakota; Gillette,  Wyoming; and Navajo/Farmington,




New Mexico.  In the dry  cooling calculations,  the condenser is designed to




operate in the  temperature range  from  115 to 134 F.  The condenser is  sized




for a maximum dry bulb temperature which would  not be exceeded  for  more than




10 hours  a year.  In  the winter time when the  temperature is lower, the




cooling fans are gradually shut off by automatic control of blade  pitch




so that the condenser temperature does not  drop below 115 F.   This saves




fan energy.




     In the wet cooling  tower calculations, the condenser is designed  to




operate at the  lowest  temperature,  115 F.   The circulating water is designed




to be between 80 and  105 F, and the wet tower  is designed for  the  highest




wet bulb  temperature  in  the summer.  In the winter  time when the entering air




is dryer  and colder and  evaporation is more efficient , part of the circulating




cooling water can be  bypassed from  the tower allowing part of  the  cooling




tower to  be shut off.  This saves fan  energy and water.  Tower calculations




were made using Ref.  10  based on  the optimization of both dry  and  wet  towers.
                                    40

-------
If the fan energy is assumed to be 2$ per kw-hr, the breakeven cost for


water is only about $1.10 to $1.20 per 1000 gallons evaporated for these


four sites.  The water consumption rate, which ranges from 5.2 Ib/kw-hr


to 5.7 Ib/kw-hr, is shown in Table 2-12, expressed in Btu/lb of water


evaporated.  In our calculations, we have taken the heat rate to the tur-


bines to be 11,700 Btu/kw-hr and the condenser load to be 8,200 Btu/kw-hr.


     Although there will be circumstances^ when water costs more than


$1.20/thousand gallons and dry cooling will be economical, we have, through-


out this study, assigned all turbine condenser cooling loads to wet cooling.


     The derivation of the cooling water requirement shown in the summary


charts can be seen from the following example for a Synthoil plant at


Colstrip, Montana:


                                             9
        Wet cooling load (Table 2-9) 4.1 x 10  Btu/stream hr  T



             1500 Btu/lb water evaporated (Table 2-12)  x



             0.0018 S^/calendar min  =        gals/calendar min .
                      Ib/stream hr



     Treatment of cooling water yields waste sludges which are about 50%


moisture.  These sludges are (i) derived from lime-soda softening and (ii)


derived from evaporation of the final blowdown water.  For estimating pur-


poses we did not use cooling tower blowdown for any other water requirement.


We assumed sidestream softening to remove hardness with clarification to


remove, dirt introduced from the air.  At all the sites the underflow from the


sidestream clarifier was enough blowdown to prevent excessive chloride in the


circulating water (see Ref. 8).  This underflow is what has been called the
                                41

-------
Table 2-12.  Water evaporation rates for wet cooling.









           Location                     Btu/lb water evaporated






       Colstrip, Montana                          1500






       Beulah, North Dakota                       1576






       Gillette, Wyoming                          1488






       Navajo/Farmington, New Mexico              1436
                                 42

-------
Insoluble cooling treatment waste in Table 2-13.  When the makeup water was

treated process condensate water (assumed to have 200 mg/1 Cl~) a liquid

blowdown was required in addition.   The solids dissolved in this liquid

blowdown formed what we have called the soluble cooling treatment waste in

Table 2-13.

     In the coal conversion plants treated process condensate was used as

makeup to the cooling tower.  In some cases there was too much condensate

and the additional water was assumed used for boiler feed.  In other cases

source water had to be added to the condensate to supply enough makeup.

When a mixed water source was used for the cooling tower we calculated the

sludges individually for the two sources separately and not for a blended water.

     The wastes produced at each site are shown in Table 2-13.  An example

of the calculation follows for cooling water treatment waste in a Synthoil

plant at Colstrip, Montana:

                                      3
                                    10  Ib/stream hr       gal/calendar min

Dirty water to treatment (Table 2-5)      785

Less: water lost in treatment
  1.8% of entry                            14

Treated water                             777

Clean condensate                          144

Total condensate evaporated in
  cooling tower                           921                      1658

Source water evaporated in
  cooling tower                                                    3261

Total water evaporated in
  cooling tower                                                    4919
                                  43

-------
      Table 2-13.   Cooling water treatment waste.
              Water
Colstrip, Montana
Beulah, North Dakota
Gillette, Wyoming (Yellowstone)
Gillette, Wyoming (North Platte)
Navajo/Farmington, New Mexico
Treated process condensate
tons wet sludge (50% moisture)
per 1000 gal water evaporated
  insoluble
    waste


   0.0060


   0.0070


   0.0072


   0.0078


   0.0065


   0.0049
                                                                soluble
                                                                 waste
0.0067
*   Used for power plant and gas plants.

**  Used for oil plant.
                                  44

-------
Insoluble waste =
               gals     0.0060  tons    1440 min
                     .X.   -i /*i /-I /\    i    A    * "~
              c. mm     1000 gal        day
                              gals     0.0049  tons    1440 min
                                 .   X   - f\f\f\        ^    ,  "
                             c. min     1000 gal        day
                     = 40  tons wet  sludge/calendar  day
Soluble waste =





         T/-CO  gals    0.0067 tons    1440 min    , -            -,-,/,,,
         1658 : x  ., nnn	:	 x  	 =  16  tons wet  sludge/calendar day 
              c. mm    1000 gal        day                       6              J







     The makeup water to the cooling  tower was arbitrarily taken to  be



1.03 times the water evaporated corresponding to  a  nominal 34  cycles of



concentration.  The makeup not evaporated or lost in sludge  was  assigned to



drift or leakage.





2.4  Lurgi Process



     a.   Process streams



          The Lurgi process for the production of substitute natural gas



is a proprietary process for which not all details are available.  However



complete plant designs have been made for four plants (Refs. 11  through  16).



We have examined these published designs and from them made  various  rules



from which to derive the water requirements at the  four sites  of the present study.
                                  45

-------
          To derive process water streams the following rules were used:



          1.   Product gas has a composition of 93 voli % methane and



4 vol. % hydrogen, and a heating value (HV) of 950 Btu/scf.  The molecular



weight of the product gas is 16.2 Ib/lb mole and the scale of the plant


                      6                          9
production is 250 x 10  scf/stream day = 9.9 x 10  Btu/stream hr.



          2.   HV of product gas/HV of gasifier feed coal = 0.678.  Therefore


                                                            9
the HV of the as-received coal to the gasifier is 14.60 x 10  Btu/stream hr.



          3.   Ib of 02 to gasifier/lb of carbon and hydrogen in as-received



coal to gasifier = 0.455.



          4.   Ib of steam feed to gasifier/lb of carbon and hydrogen in



as-received coal to gasifier = 1.80.



          5.   Water decomposed by chemical reaction to supply hydrogen =


        3
775 x 10  Ib/stream hr.



          6.   Purification is accomplished by the Rectisol process.  Steam


                  3                          3
needed is 128 x 10  Ib/stream hr and 124 x 10  Ib/stream hr of process



condensate is discharged from the purification stage.



          7.   Methanation water discharged is at 17.4% of the steam fed



to gasifier.



          8.   All sulfur and nitrogen in coal are converted to HS and NH,



respectively and purged out during purification.



These rules give  the hydrogen balances shown in Table 2-14.  Using the



procedure of Section 2.2 for a gas plant  (1.0 wt. % of dirty condensate



is lost in biotreatment and water in the sludge is 5 wt. % of the treated



water) the process water entries in the summary tables have been calculated.



As with Synthoil, 100 gal/calendar min  has been added to  the boiler makeup



water shown in Table 2-14.
                                  46

-------
        Table 2-14. Water equivalent hydrogen balance of Lurgi plant at four sites.
                                                               10  lb/stream hr
             IN

Moisture in as-received coal

Water equiv. of hydrogen in coal

Steam to gasifier and purification
             OUT

Dirty process and purification condensate

Clean condensate from methanation
Water equiv, of hydrogen in byproduct,,ELS,
  and NH3

Water equiv. of hydrogen in product gas
Coal feed to gasification

Higher heating value of as-received coal  (7^)

Moisture in as-received coal (%)
Colstrip,
Montana
419
488
1672
2579
1313
269
45
945
2572
1695
tU^ 0 -, -,
Ib } 86U
24.7
Beulah ,
N.D.
770
520
1790
3080
1782
289
42
945
3058
2140
6822
35.0
Gillette,
Wyoming
484
529
1770
2783
1476
286
20
945
2727
1728
8449
28.0
Nava j o ,
N.M.
218
547
1732
2497
1172
279
35
945
2431
1756
12.

-------
     b.   Cooling


          Because of the proprietary nature of the Rectisol gas purification


system and other parts of the plant we could not determine the auxiliary


heat loads to drive the plant.  Instead we used the design efficiency from


Refs. 11, 12, 14 and 15 together with the design cooling water systems as


used in the Navajo area.  Although much more cooling water is used in the


design of Ref. 14, we can not justify this.


          The assumptions and results are given in Table 2-15. The assumed


thermal efficiencies are taken from the references.  The higher efficiency in


New Mexico is mostly caused by the lower coal moisture.  The by-product


heating value comes from the references.  The total product heating value

                            9
includes the gas at 9.9 x 10  Btu/stream hr.  From the plant efficiency the


total plant coal feed can be calculated and so can the coal fed as fuel.  The


coal burnt as fuel requires stack gas scrubbing discussed in a later section.


The heat lost to wet cooling is taken to be 28% of the unrecovered heat as


used in the designs in New Mexico.  From this heat the water evaporated for


cooling was calculated using Table 2-12 and the summary sheets were completed


using the procedure of Section 2.3.



2.5  Synthane Process


     A design, for cost estimating purposes, has been made for the Synthane


process  .  From it we have taken the hydrogen balance shown in Table 2-16,


Because we do not have enough information to distinguish between coals fed


to the Synthane process,Table 2-16 was used at all four sites and the process


streams calculated according to Section 2.2 for gas plants are shown in detail


at all sites.
                                   48

-------
Table 2-15.  Assumptions and calculations on thermal efficiency
                            of Lurgi plants.
                                       Colstrip,  Beulah,  Gillette,  Mavaj o ,
                                       Montana     N.D.       Wyo.
Assumed thermal efficiency (%)            65        65        65        70
Byproduct heating value as
  % HHV of gas                            13        12        13        20


Total product HV (109 Btu/stream hr)      11.19     11.09     11.19     11.88


Plant coal feed HV (109 Btu/stream hr)    17.22     17.06     17.22     16.97


Fuel coal feed HV (109 Btu/stream hr)      2.62      2.46      2.62      2.37


Fuel coal feed (103 Ib/stream hr)        304       361       310       285


Unrecovered heat (109 Btu/stream hr)       6.03      5.97      6.03      5.O9
Heat lost to wet cooling
  (109 Btu/stream hr)                      1.69      1.67      1.69      1.43
                                  49

-------
Table 2-16.  Water equivalent hydrogen balance for the Synthane
                         process using Wyodak coal.
Coal feed: 1,605,000 lb/stream hr of Wyodak seam subbituminous coal
     (4.3 wt. % of moisture and 4.1 wt. % of hydrogen, heating value of
     10,640 Btu/lb) used for gasifiers.

Product pipeline gas: 250 x 10  scf/stream day with heating value of
     940 Btu/scf (92.3 vol. % methane and 1.8 vol. % hydrogen),


               IN                                         103 Ib/stream hr

Moisture in coal fed to gasifier                                  69

Water equiv. of hydrogen in coal                                 592

Steam to gasifiers                                               978

Steam to shift converter                                         540

Makeup water to scrubber                                         476

                                                               2,655
              OUT

Dirty process condensate from scrubbing and cooling            1,069

Dirty condensate from shift converter                            411

Dirty condensate from purification                                20

Clear condensate from methanation                                142

Water equiv. of hydrogen in H?S and NH~                            3

Water equiv. of hydrogen in product gas                          921

Water equiv. of hydrogen in char and tar from gasifier            42

                                                               2,608
                                  50

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     Ref. 17 is not satisfactory for estimating cooling water requirements


so we made our own thermal efficiency and cooling water calculations as


shown in Tables 2-17 and 2-18.  The thermal efficiency of 62% may be low

                                                              9
but the unrecovered heat that is lost to wet cooling, 2.7 x 10  Btu/hr or


42% of the unrecovered heat, is certainly the maximum reasonable wet cooling


load and could be lower.  In the Synthane plant all the coal is fed to the


gasifier and char is recovered and burnt to provide fuel for the plant.


To calculate the water required for flue gas desulfurization the char


production was taken to be 205.2 tons/stream hr with the composition:



                        C      63.64%


                        H       1.04%


                        0       1.43%


                        N       0.38%


                        S       0.26%


                       Ash     33.29%


                       HHV     9800 Btu/lb



     The wet cooling load was taken to be invariant from site to site.


The thermal efficiency will vary with the moisture in the coal but this will


not affect the wet cooling load.  The cooling water calculations were made


according to Section 2.3 and entered in the summary charts.
                                  51

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Table 2-17.  Approximate thermal efficiency for Synthane plant
                             at Wyoming .
                                               9
                                             10  Btu/stream hr
                  Coal feed                          17.1



                  Gas product                         9.8



                  Byproducts                          0.8



                  Unrecovered                         6.5


                                                     17.1





                  Approximate thermal efficiency = 62%
                                  52

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   Table 2-18.  Approximate disposition of unrecovered heat
                       in Synthane plant at Wyoming.
                                              10  Btu/stream hr
                                  Direct loss     Dry cooling     Wet cooling
Coal drying
0.6
Stack loss (10% of char
  burnt)
0.4
Gasifier off-gas scrubber
                 1.4
Gas purification
  regenerator condenser
                 1.3
Lock hopper compressor
                                 0.1
Oxygen plant compressors
                                 1.1
Electricity (37,000 kw)
                                 0.3
Process cooling and
  unaccounted
                                 1.2
                                     1.1
                 2.7
2.7
                                  53

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References

 1.  Akhtar, S., Mazzocco, N.J., Weintraub, M. and Yavorsky, P.M.,
     "SYNTHOIL Process for Converting Coal to Non-Polluting Fuel Oil,"
     presented at 4th Synthetic Fuels from Coal Conference, Oklahoma
     State University, Stillwater, Oklahoma, May 1974.

 2.  Akhtar, S., Lacey, J.J., Weintraub, M., Rezik, A.A., and Yavorsky,
     P.M., "The SYNTHOIL Process - Material Balance and Thermal Efficiency,"
     presented at 67th AIChE Annual Meeting, Washington, B.C., December
     1974.

 3.  Bureau of Mines, "Economic Analysis of Synthoil Plant Producing
     50,000 Barrels per day of Liquid Fuels from Two Coal Seams: Wyodak
     and Western Kentucky," Report No. ERDA 76-35, U.S. Dept. of the
     Interior, November 1975.

 4.  Akhtar, S., Friedman, S., and Yavorsky, P.M., "Environmental Aspects
     of Synthoil Process for Converting Coal to Liquid Fuels," in
     Second Symposium on Environmental Aspects of  Fuel Conversion
     Technology, pp.  179-182, EPA Report No. EPA-600/2-76-149, June 1976.

 5.  Bureau of Mines, "An Economic Evaluation of Synthane Gasification
     of Pittsburgh Seam Coal at 1,000 psia Followed by Shift Conversion,
     Purification, Single-Stage Tube Wall Methanation and Pollution
     Control, Pittsburgh Seam Coal," Report No. 74-31, U.S. Dept. of
     Interior, June 1974.

 6.  McCrea, D.H., "The Benefield Activated Hot Potassium Carbonate Process:
     Commercial Experience Applicable to Fuel Conversion Technology," in
     Second Symposium on Environmental Aspects of  Fuel Conversion Technology,
     pp. 217-223, EPA Report No. EPA-600/2-76-149, June 1976.

 7.  Kastenbader, P.D. and Flecksteiner, J.W., "Biological Oxidation of
     Coke Plant Weak  Ammonia Liquor," JWPCF 41, No. 2, 199-207, 1969.

 8.  Gold, H., Goldstein, D.J., and Yung, D., "The Effect of Water Treat-
     ment on  the Comparative Costs of Evaporative  and Dry Cooled Power
     Plants," ERDA Report No. COO-2580-1, June 1976.

 9.  Goldstein, D.J.  and Probstein, R.F., "Water Requirements for an
     Integrated SNG Plant and Mine Operation," in  Second Symposium on
     Environmental Aspects of Fuel Conversion Technology, pp. 307-330,
     EPA Report No. EPA-60012/76-149, June 1976.

10.  Kelly's Handbook of Crossflow Cooling Tower Performance, Neil W.
     Kelly  &  Associates, Kansas City, Missouri.
                                 54

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11.  El Paso Natural Gas Company, "Second Supplement to Application of
     El Paso Natural Gas Company for a Certificate of Public Convenience
     and Necessity," Federal Power Commission Docket No. CP73-131, 1973.

12.  Western Gasification Company, "Amended Application for Certificate
     of Public Convenience and Necessity," Federal Power Commission
     Docket No. CP73-211, 1973.

13.  Wyoming Coal Gas Co. and Rochelle Coal Co., "Applicant's Environ-
     mental Assessment for a Proposed Gasification Project in Campbell
     and Converse Counties, Wyoming," prepared by SERNCO, October 1974.

14.  North Dakota Gasification Project for ANG Coal Gasification Co.,
     "Environmental Impact Report in Connection with Joint Application
     of Michigan Wisconsin Pipe Line Co. and ANG Coal Gasification Co.
     for a Certificate of Public Convenience and Necessity," Woodward-
     Clyde Consultants,  Federal Power Commission Docket No.  CP75-278,
     Vol. Ill, March 1975.

15.  Batelle Columbus Laboratories, "Detailed Environmental Analysis
     Concerning a Proposed Gasification Plant for Transwestern Coal
     Gasification Co., Pacific Coal Gasification Co., Western Gasifica-
     tion Co., and the Expansion of a Strip Mine Operation Near Burnham,
     New Mexico Owned and Operated by Utah International Inc.," Federal
     Power Commission, February 1, 1973.

16.  Moe, J.M., "SNG from Coal via the LURGI Gasification Process,"
     IGT Symposium on Clean Fuels from Coal, Institute of Gas Technology,
     Chicago, Illinois, September 1973.

17.  Bureau of Mines, "Synthane Gasification at 1000 psia, Followed by
     Shift Conversion, Purification,  Single-Stage Tube Wall Methanation
     and Pollution Control.  Wyodak Seam Coal," Report No. 75-15, U.S.
     Dept. of the Interior, November 1974.
                                  55

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                        3.  SHALE CONVERSION






3.1  Underground Mining and Surface Processing




     The analysis of shale conversion in the present assessment is restricted




to the TOSCO II process by the program guidelines.  In the TOSCO II process the




oil shale is mined underground and then processed on the surface.  The surface




processing operation involves crushing the shale and then heating (retorting)




it to produce the shale oil.  The retorted shale oil is too viscous to be




piped, and too high in nitrogen and sulfur to be used as normal refinery




feedstock so that it must also be put through a refinery upgrading process,




normally by hydrocracking.  In addition, it is necessary to dispose of the




spent shale from the retorting, equal to about 80 to 85 percent by weight of




the originally mined shale with a volume before compaction averaging 50 percent




greater than its in-place volume, and even after maximum compaction at least




12 percent greater.




     The water requirements for the mining and crushing of the raw shale will




be considered in Section 7 along with the same requirements for coal,  since




the operations are quite the same as in the underground mining of coal, and




differ only in some details and in the quantities handled.  Similarly  the




water requirements for spent shale disposal will be considered in Section 8,




along with the water requirements for the solids and ash disposal in the coal




conversion processes.  In this same section evaporation losses, plant  dust




control and service and potable water needs will also be evaluated,  since




they too agree in kind with those for the coal conversion processes.




     It will be assumed that needed auxiliary electric power will be pur-




chased and not generated onsite.  This is consistent with the TOSCO II
                                 56

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design in which the process steam needed in the plant is generated by




burning fuel gas generated in the shale conversion.






3.2  TOSCO II Process




     In the TOSCO II retorting scheme  shown schematically in Fig. 3-1,




crushed shale of minus 1/2 inch size is preheated by pneumatically conveying




the shale upward through a vertical pipe concurrently with hot flue gases




from the ball heater.  The flue gas is cooled during this process and the




cooled gas is passed through a venturi wet scrubber to remove shale dust before




venting to the atmosphere at a temperature of about 125 to 130  J.




     The ball heater is a vertical furnace whose purpose is to heat up




ceramic balls of about a 1/2 inch in diameter.  After the balls are heated




they are fed along with the preheated shale, which has been separated from




the flue gas in settling chambers and cyclones, into a horizontal rotating




kiln where the pressure is slightly above atmospheric.  The mixture of balls




and shale flows through the kiln and the shale is brought to a retorting




temperature of about 900F through conductive and radiative heat exchange




with the balls.  The resulting hydrocarbon and water vapors are drawn off and




fractionated leaving behind a mixture of balls and processed shale.




     The ceramic balls are size-separated from the spent shale, which is




a fine powder, by passage through a trommel (a heavy duty rotating cylinder




with many small holes punched in its shell).  Warm flue gas is used to remove




residual dust from the ball circulation system.  The dust is removed from




the flue gas with a venturi wet scrubber.  The balls are then circulated back




to the ball heater, by-means of a bucket elevator, for reheating by burning




some of the product gas.
                                 57

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             FLUE GAS  6606PM PREHEAT SYSTEM
           TO ATMOSPHERE   i       STACK
                 290 SPM
                  WATER

                  r^u-1
                                                              ISO GPM
                                                              FOUL WATER TO
                                                              rOUL WATER
            PREHEAT SYSTEM
          (INCLUDES  INCINERATOR]
                             * ALL SCRUBBER SLUDGE STREAMS
                               TO PROCESSED SHALE DISPOSAL

                            ** TO GAS RECOVERY AND
                               TREATING  UNIT
Fig.  3-1.
TOSCO II  retort  flow diagram  tor upgrading shale  oil
output of  50,000  bbl per stream day  with  feed of  35
gallon per  ton oil shale.
                                                                                     COVERED PROCESSED
                                                                                     SHALE  CONVErOR
MOISTURIZED PROCESSED
SHALE TO DISP05L
-------
     The processed shale is cooled in a rotating drum steam generator.  One of




the  important features of the process is that the cooled spent shale is then




moisturized  to approximately 14 percent moisture content in a rotating drum




moisturizer, after which it is transported by a conveyor belt for disposal.




The  steam and processed shale dust produced in the moisturizing process are




passed through another venturi wet scrubber to remove the dust before




discharge to the atmosphere.




     The importance of the moisturizing is that addition of the water to the




TOSCO type processed shale, at a predetermined shale temperature, appears to




lead to cementation of the shale after proper compaction.  More importantly,




the  cemented shale appears to "freeze" in the moisture which has been added.




Samples taken from a two year old spent shale embankment at depths of four




to six feet have indicated no change in moisture content from that existing




at the time of compaction, which amounted to about 12 percent, 2 percent hav-




ing  evaporated during transportation .  The shale seems to become effectively




impermeable and to resist percolation, so that soluble salts are not leached




out  .




     In the upgrading process the gas, oil and water vapors which are drawn




off are fractionated into gas, naptha, gas oil, bottoms oil, and foul water




streams (see Fig. 3-2).  The gas oil produced by the retorting process is a waxy




oil which is high in nitrogen, contains a good deal of sulfur and is not pumpable.




A clean, pumpable oil with reduced nitrogen and sulfur levels is produced by a




proprietary hydrotreating process.  The pour point of the bottoms oil is first




reduced by delayed coking prior to hydrotreating.   Most of the gas which is produced




will be used as fuel for the production of process steam, although some of the
                                 59

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  PYROLYSIS
OIL AND GAS
                   GAS
             FRACTIONATOR
                             NAPTHA
                             GAS OIL
                    BOTTOMS
                                   COKER
                                                                                     SULFUR
                                                                                     LPG SPECIAL
                                                           GAS  TREATING
                                                               AND
                                                          SULFUR RECOVERY
                                                                                     LIQUID C  's
                                         FUEL GAS
                                                                                HYDROGEN
                                                                                  PLANT
GAS
           NAPTHA
        KYDROTREATER
          GAS OIL
         HYDROTREATER
                       IJ
                                                                                          AMMONIA
  AMMONIA
SEPARATION
                                                                               LOW SULFUR FUEL OIL
                                                                                         DIESEL FUEL
                                                     COKE
              Fig. 3-2.  Flow diagram for TOSCO II shale oil upgrading  refinery

-------
higher heating value  gas  is  used  as  feed material  for  the  production  of  the


hydrogen  needed  in  the  upgrading.  Before  the  retort gas is  burned  hydrogen


sulfide would be removed  with  subsequent sulfur  recovery.  Ammonia  will  be


separated out and recovered  as a  liquid from the sour water  produced  in  the


hydrotreating, while  the  sulfur will be recovered  from the hydrogen sulfide


which is  drawn off  as a gas.   The upgrading and  cleaning process described


for the TOSCO II refinery resembles    standard refinery processing  procedure.



3.3  Water Streams  for Retorting


     In this section, we  consider the  retort water streams for the  specific


conceptual design discussed  in Ref.  1  of a plant retorting 35 gallon  per ton


shale with a 50,000 bbl per  stream day output  of upgraded  shale oil.  On


Fig. 3-1, reproduced from Ref. 1 with  some small changes,  we have summarized


our derived values of the water streams, with  all  figures  in gallons  per stream


minute (gpm).  To obtain  the corresponding-streams for  a 100,000 bbl/day


plant, it-is sufficient to simply double all the input  and output figures.


The water quantities shown in  Fig. 3-1 were derived from the water  flow  chart


of Fig. 3-3-, which was taken from Ref. 1 and to  which some clarifications

           ft
were added.   It  is not completely straightforward to distinguish the retort-


ing and upgrading streams in Fig. 3-3.  Moreover, of particular importance in


the TOSCO process is the feature noted earlier that the wastewater fed into


the moisturizer which is not vaporized is sealed into the processed shale.


     It can be seen from Fig.  3-3 that the only  specifically noted water


addition to the retorting step is the  90 gpm leaving the crusher dust sup-


pression unit that is added to the raw shale.   All of the other dust suppression
* Personal communications with TOSCO personnel.
                                 61

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        -350
                              RAW SHALE SURFACE
                                                 PYROLYSIS
                                                   AND
                                               OIL  RECOVERY
                                                   UNIT
                                                                 25
                                                           STRIPPED WATER
                                                           PURGE FROM
ft = RIVER WATER SUPPLY
    ALL  BATES IN 6PM
 * = WILL INCREASE TO 700 GPM
    IN  It YEARS
TOTAL RIVER WATER SUPPLY =
FOR YEARS I - II : 4970 GPU
FOR YEARS 12-20^ 5600 6PM
FOR DESIGN PURPOSES, NO CREDIT
TAKEN  FOR SURFACE  RUNOFF.
                                                PROCESSED  AMMONIA SEPARATION
                                                  SHALE
                                               MOISTURI2ING
Fig.  3-3.   TOSCO  II process  water streams for  upgrading  shale oil  output of  50,000 bbl
             per  stream day with feed  of 35 gallon per ton oil shale

-------
water  totaling 110 gpm s  sent  directly to the  moisturizer.   The only  water


noted  to  be specifically coming out  of  the retorting is  150  gpm listed as


water  of  retorting,which we take to  leave  as  foul  water  on the  retorting diagram


of  Fig. 3-1.   This amount  of retort  condensate  water equals  3.27 gallons per


ton of shale processed,  which compares  favorably with the "typical" value of


2 to 5 gallons per ton of  shale given in Ref. 3.


     Next we indicate  how  our estimates were  made  for the amounts of water


which  are put  into the preheat  system and  ball  circulation system stack gas


scrubbers,  along with  how  much  water leaves in  the sludge from  these scrub-


bers.   This water  stream will be  tabulated again in  Section  8 in connection


with the water leaving with the disposed solids.   Together with  the previous


two  streams we have discussed,  this  makes  up  the total imported  and exported


retort  streams.  Table 3-1 is a tabulation of the  streams from Fig. 3-3


put  together in a  manner designed to provide  estimates on the scrubber


streams.  The  assumptions  it  was necessary to make along with the various


dry  tonnage flow rates  taken  from Ref.  1 are  indicated.directly  in the table,


which  is reasonably self-explanatory.  We  emphasize  that the estimates we


have arrived at can be no more  accurate  than our interpretations of the


streams given  in Fig.  3-3.  We  note  further, that  some divergences do exist


between the flow rates of Fig.  3-3 and  those deduced from typical data pro-

                *
vided in Ref.  1.   Therefore, we would emphasize that the figures given in


Fig. 3-1 are to be treated  as estimates and not precise values.


     We have shown on Fig.  3-1  the stream flows we deduced that  are associated


with the moisturizer unit.  We do not consider the water leaving with the spent


shale  chargeable to the  retort  section, but rather we treat this stream as part


of  the spent shale disposal system and as  such we will discuss it in Section 8.
* For example, Tables 3 and 21.


                                  63

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      Table 3-1.  Determination of TOSCO II retort water streams for
                  upgrading shale oil output of 50,000 bbl per stream
                  day with feed of 35 gallon  per ton shale, on basis
                  of water balance for combined retorting and upgrading
                  steps 1.
                                               Individual   Total   Makeup
                                                  gpm        gpm      gpm_
Water out in cumulative sludge from scrubbers                100
   Water in to processed shale moisturizing from
   retorting and upgrading                       1,350
   Moisture out in processed shale
   (.14 x 53,625 tpd)                           (1.250)
                                                   100
Vapor out in preheat and ball circulation stacks             660
   Assumed sources of vapor in stacks:
   Water of combustion                             280
   Natural shale surface moisture                   75
   Moisture on shale from dust suppression          9Q
   Makeup water                                    215
                                                   660
Water in to preheat and ball circulation scrubbers           310      310
   Makeup water (from vapor calculation)           215
   Sludge water* ([.3B/.62][925]  tpd)               95
                                                   310
Water in to moisturizer scrubber                              15       15
   Makeup water (same ratio to sludge as above)     10
   Sludge water* ([.3S/.62] 43 tpd)                 	5
                                                    15
   Total  clarifier sludge  equals  968  tpd  (925 tpd from preheat  and ball
   circulation  scrubbers plus  43  tpd  from moisturizer scrubber), while net
   water  in  the cumulative sludge equals  100  gpm or  600 tpd.  Solids  there-
   fore represent 62% of sludge.   Approximate split  shown  in Fig. 3-1
   between preheat and ball circulation scrubbers is based on same relative
   ratios of water to dry  solids.

                                    64

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 Table  3-1  (continued)
                                                Individual   Total   Makeup
                                                   gpm
 Water in to moisturizer                                    1,740
    Moisture out in processed shale               1,250
    Water out in moisturizer scrubber sludge          5
    Vapor out In moisturizer stack                  500
    Water in to  moisturizer scrubber                (15)
                                                  1,740
   Assumed sources of water in to moisturizer:
   Cooling tower blowdown                           300
   Utility boiler blowdown                          130
   Regenerant wastes from deionizer                 100
   Dust collection                                  110
   Stripped water                                   580
   Stripped water from ammonia unit                 25
   Makeup water                                  _ 495                495
                                                 1,740
Foul water out of pyro lysis and upgrading                    370
   Water of retorting                              150
   Steam used in upgrading                         220
             Total assumed to leave as foul water  370
                                 Total water makeup from river         820
      The  95  gpm of water in  the effluent sludge from the preheat  and  ball
 circulation  scrubbers,' when  added  to  the 150  gpm retort  effluent  condensate,
 constitutes  the exported water  stream.   The influent streams  to the scrubbers
 of  310  gpm plus the 90 gpm put  into the  raw shale feed makes  up the imported
 stream  which is seen to amount  to  about  half  of the  820  gpm makeup water.

                                   65

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3.4  Water Streams for Upgrading


     From Fig. 3-2 it is seen that the major operations of the upgrading


process are fractionation, delayed coking, hydrotreating, and gas cleanup


and recovery.  It is evident that the major water needs in such a system


are the cooling waters required for the fractionator and coker and the water


required for the production of hydrogen by steam reforming.  The principal


effluents will be the cooling tower and boiler blowdowns and the sour


water generated in the hydrotreating and gas treating units.


     In evaluating the water streams from the overall flow diagram of


Fig. 3-3, the quantity most difficult to determine is the amount of steam


consumed in the hydrogen plant.  In Fig. 3-3, there is 920 gpm shown as


steam consumed.  As an upper limit we can assume that all of this amount


represents steam consumption in the hydrogen plant.  An alternate estimate

                                 *
obtained from steam usage figures  is 279,000 Ib/hr or 558 gpm.  Table 3-2,


which is a compilation of the influent and effluent streams for the refining op-


eration;  lists both figures.  We have carried out a water equivalent hydrogen


balance for upgrading shale oil and find a minimum net consumption of about


40 Ib H.O/ton of shale or somewhat less than half of the lower of the two


figures.  This makes the 558 gpm figure the more probable value.


     All of the stream quantities shown in Table 3-2 are self-explanatory


and for the most part have been taken directly from Fig. 3-3.  The exception


is the 220 gpm of steam, which was assumed in our retort calculation to be


used in the upgrading and to be converted to foul water (cf. Table 3-1).


We would note here, that we have carried out an approximate overall heat


balance for the TOSCO II retorting and upgrading process.  The raw shale




* Fig. 38, p. 151, Ref. 1.



                                  66

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                                                 ft
was taken to have a heating value of 3,070 Btu/lb .  The net output of

materials of significant heating value not used in the 50,000 bbl/day plant

was taken to be 47,000 bbl/day of fuel oil, 4,330 bbl/day of .liquified

petroleum gas and 800 tons/day of coke .  In addition, about 5% of the heating

value of the shale was assumed to be unused, consistent with the amount of

carbonaceous residue that remains with the spent shale in the TOSCO process.
     Table 3-2.  Compilation of TOSCO II refinery water streams for
                 upgraded shale oil output of 50,000 bbl per stream
                 day with feed of 35 gallon per ton shale, on basis
                 of water balance for combined retorting and upgrading
                 steps .
     Imported

        Steam used in upgrading

        Wash water to gas treating unit

        Steam to coker

        Cooling tower makeup

        Steam consumed in hydrogen plant
                                                     Total
     Exported

        Foul water converted from steam used in upgrading

        Foul water out of gas treating unit

        Foul water out of coker

        Cooling tower blowdown

        Boiler blowdown

                                                     Total
  220

  180

   30

1,300

  558 -   920

2,288 - 2,650




  220

  180

   30

  300

  130

  860
                                   67

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Assuming 1,200 Btu removed per pound of water evaporated, it was found that




the 1,000 gpm of water evaporated in the cooling tower corresponds to a




heat loss of about 20 to 25% of the total heat dissipated in the plant.  The




upper limit assumes additional unaccounted losses of about 5%.  This would




indicate a well designed cooling system that is probably not too far off




optimum.






3.5  Process and Cooling Water Consumption




     From the water stream quantities detailed in the preceding two sections,




the net process and cooling water consumption for the TOSCO II plants can




be specified in a format consistent with that for the coal conversion




processes.




     The net consumption of retort water associated with a 50,000 bbl per




stream day plant can be determined from Table 3-1.  The retort water con-




sumption is made up of the 215 gpm of makeup water and 90 gpm of dust sup-




pression water leaving in the preheat and ball circulation stacks plus the




net of 490 gpm leaving as vapor out the moisturizer stack.  The net consump-




tion is  therefore 795 gallons per stream minute or 716 gallons per calendar




minute with a 90% load factor.  Although the vapor leaving in the moisturizer




stack is charged to the retort, the processed shale moisture and scrubber




sludge waters are charged to solids disposal and as such are considered in




Section  8.




     From Table 3-2 the net water consumption in the refining is seen  to range




between  428 and 790 gpm, after subtracting  the 1,000 gpm evaporated in the




cooling  towers.  From our discussion  in Section 3.4 the lower value is the




more probable one but we have  taken the average of 609  gallons per stream




minute  to ensure the  presentation of  a conservative water  consumption  estimate.




With a  90% load factor  this  corresponds to  548 gallons  per calendar minute.





                                  68

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     We have already discussed in Section 3.4 the evaporated cooling water

rate of 1,000 gpra.  We assume that this figure also includes the drift and

leakage losses.  For consistency with our own detailed cooling calculations

the drift and leakage losses are taken at 3% of the amount evaporated.  In

that case, at a 90% load factor we would have a total of 900 gallons per

calendar minute lost in the cooling towers with 845 gpm evaporated and

26 gpm lost to drift and leakage.

     As noted earlier the corresponding water rates for a nominal 100,000 bbl/day

plant are obtained by doubling the rates discussed.


References
1.  Colony Development Operation, "An Environmental Impact Analysis for a
    Shale Oil Complex at Parachute Creek, Colorado, Part 1 - Plant Complex
    and Service Corridor," Atlantic Richfield Company, Denver, Colorado, 1974.

2.  Metcalf & Eddy Engineers, "Water Pollution Potential from Surface Disposal
    of Processed Oil Shale from the TOSCO II Process," Vol. I, a report to
    Colony Development Operation, Atlantic Richfield Co., Operator, October 1975.

3.  U.S. Department of the Interior, "Final Environmental Statement for the
    Prototype Oil Shale Leasing Program," Vol. I, U.S. Gov't. Printing Office,
    Washington, D.C., 1973.

4.  Hendrickson, T.A. (editor), Synthetic Fuels Data Handbook, p.  30,
    Cameron Engineers, Inc., Denver, Colorado, 1975.
                                 69

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             4.   STEAM ELECTRIC GENERATION






     In this section are described the methods used to determine the choice




between evaporative (wet), dry or wet-dry cooling for a  coal-fired    steam




electric generating plant at the six sites considered.  The makeup water




requirements and residuals generated for evaporative or wet-dry cooling




towers are also specified.  The consumptive water requirements (and total




residuals generated) for flue gas desulfurization, mining, and evaporation,




solids disposal and other uses for   coal-fired  steam electric generating




plants are discussed in Sections 6 through 9.




     At each site dry cooled steam electric generating plants with mechanical




draft towers are compared to evaporative cooled plants using mechanical draft




towers.  Only at Navajo/Farmington, New Mexico are wet-dry mechanical draft




towers compared to both dry and evaporative towers.  The choice of a particular




cooling system is made on an economic basis, that is, by comparing the total




annual evaluated costs of dry, wet-dry and evaporative cooling systems.  In




the cases of wet-dry and evaporative cooling systems the cost of water has




been included.  The cost of water comprises the cost of supplying the makeup




water, the cost of treatment of the makeup and/or the circulating water in




the tower, and the cost of treatment and disposal of the blowdown in an




environmentally acceptable manner.






4.1  Costs of Cooling Systems




     In an evaporative cooling  tower the hot water from the condenser is cooled




by direct contact with air.  The lowest possible temperature  to which the hot




water  can be cooled~~corresponds to  the wet bulb temperature of the air.  This




is not a practical limit  since  an infinitely tall cooling  tower would be
                                 70

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required.  The difference between  the temperature of  the water  leaving  the




tower (or entering the condenser)  and the wet bulb  temperature  is  called  the




approach temperature in an evaporative cooling  tower.   Since most  evaporative




cooling towers operate over the same range the 'approach temperature determines




the size of the tower.  For a given cooling range (difference between hot




water and cold water'temperatures) the smaller  the  approach temperature the




larger the tower with concomitant  higher capital costs.  This,  and other




nomenclature, is shown in Fig. 4-1.




     In a dry cooling tower the initial temperature difference  primarily




determines the size and capital cost of the tower.  The initial temperature




difference is defined as the difference in temperature between  the tempera-




ture of the circulating cooling water entering  the  tower and the entering




air temperature (Fig. 4-1).  The cooling range  is the amount by which the




circulating water is cooled as it  passes through the tower and  is equal to




the temperature rise across the condenser.  The larger the initial tempera-




ture difference, the less air-cooled area is required to reject a given amount




of heat, and the less the capital  cost of the cooling system.   However,




increasing the initial temperature  difference increases the turbine exhaust




pressure which results in lower efficiency and a loss of generating capacity.




In dry cooling systems the cooling range is normally specified  as a percentage




of the initial temperature difference, and for the  purposes of  this study was




taken to be 50 percent of the initial temperature difference.   In the case of




surface condensers the capital cost of the cooling  system and the performance




obtained with this system is also dependent on the  terminal temperature




difference,which is the difference between the saturation temperature corres-




ponding to the turbine back pressure in the condenser and the circulating water







                                71

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                                                                      AIR
      STEAM
                        CONDENSER
                                            CONDENSATE
                                                                      AIR
                                       Evaporative

                                         Cooling
                              Dry

                            Cooling
Range
     T  - T
      3    2
Approach
T_ - T. (wet bulb)
 2    4
Initial Temperature Difference
                                 (dry bulb)
Terminal Temperature Difference
     (Sat.) -
(Sat.)  -
             Fig. 4-1. Cooling  tower nomenclature.
                                   72

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leaving the condenser (Fig. 4-1).  The greater the terminal temperature




difference the less condenser heat transfer surface area required to reject




a given amount of heat, and the lower the capital cost of the condenser.




     Since the performance of a power generating plant is dependent upon




the temperature of the steam condensing in the condenser, the lower the




condensate temperature the higher the plant efficiency.  A cooling system




that is designed for a small range and a small approach for the cooling




tower would be very large with concomitant higher capital costs and capital




related charges and would allow the power generating plant to operate at




lower turbine back pressures (lower condensing temperatures) with lower heat




rates and concomitant lower fuel costs.  Conversely, a cooling system designed




for a large range and a large approach for the cooling tower would be rela-




tively small with concomitant lower capital costs and lower capital related




charges; however the power generating plant would have to operate at a higher




turbine back pressure (higher condensing temperatures) with higher heat rates




and concomitant higher fuel costs.  Economic evaluations of cooling systems




must therefore account for the effect of the size of the cooling tower on




the efficiency of the power generating plant.  Loss of plant capacity due to




higher heat rates must be charged against the cooling system as a penalty




cost.  The economic optimum design or minimum cost operation is dependent on




the climate and will vary from location to location.




     Since only differences between wet and dry cooled systems are of interest




here, only those costs associated with the choice and design of the cooling




system are included in the analysis.  The factors considered in an economic




optimization procedure include the size and annual capital charges of the




cooling system, annual performance of the turbine generator including loss of
                                73

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generating capability at higher ambient temperatures, annual fuel costs,




annual cost of auxiliaries, and annual operating and maintenance costs.




These factors are discussed in detail in Refs. 1, 2, 3 and 4 and will be




briefly discussed here together with the input pricing data used for the




numerical calculations.




     In order to make a direct comparison it was assumed that the dry cooled




plant produced the same nominal generating output as the evaporative cooled




plant with which it was compared.  At all sites but Rifle, Colorado, it was




assumed that a nominal 3000 MWe was generated; at Rifle, Colorado, a nominal




1000 MWe was assumed to be generated.  It was further assumed that the




turbines operated at a constant throttle "full-load" condition during all




hours of operation except when the turbine generator was throttled back to




a part-load condition to avoid exceeding the specified turbine back pressure




limit.  The load factor was taken to be 70 percent.  The total annual hours




of operation was 6132 based on full operation during each month except for




the month of March, when the plant was completely shut down for maintenance,




and the month of April, when the plant was partially shut down for maintenance.




Energy was credited as an excess, or penalized as a deficit, if the plant




produced more or less energy than the nominal generating output.






Capital cost of cooling system.  The capital cost includes the capital expen-




diture for installation and materials necessary to construct the cooling




system.  The major components of the cooling system include the condensers,




the cooling tower (evaporative, dry or wet-dry) and associated equipment, and




circulating water facilities including piping, valves, pumps, pump drives




and storage tanks.  For dry cooling systems, additional capital costs are also




included.  These are associated with a supplemental mechanical-draft evaporative






                                 74

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cooling system used for auxiliary cooling, the added cost of a turbine


generator suitable for operation at high exhaust pressures, and the addi-


tional steam supply required by the high exhaust pressure turbine in order


to produce its rated output.


     The small supplemental mechanical draft evaporative cooling system


is used to supply cooling water for the plant auxiliary equipment during


hot weather when the temperature of the cooling water leaving the dry tower


exceeds 95 F, the present standard temperature for auxiliary cooling water.


The supplemental evaporative cooling system was designed with a heat rejec-


tion capacity of 1.3% of the condenser heat load.  The heat rejection capa-


city of the supplemental cooling system is 195 x 10  Btu/stream-hr for the


3000 MWe plants, and 65 x 10  Btu/stream-hr for the 1000 MWe plant.  The


total evaporative water loss for the supplemental cooling system was


calculated to be not more than 70 x 10  gallons per year.  This is to be

                                                        9
compared to an evaporative water loss of 7.0 to 7.8 x 10  gallons per year


from  an all evaporative cooling system for a 3000 MWe fossil fuel


generating plant (see Table 4-6).  This corresponds to a supplemental cooling


system requirement for the dry cooling system of not more than one percent


of the 3000 MWe wet cooling system evaporation loss.  Although the capital


cost of the supplementary evaporative cooling system as well as the power


costs were included in the capital and annual evaluated costs of the dry


cooling system the costs of water supply, treatment, and blowdown disposal


for the supplemental tower were not included in the total annual evaluated


costs of the dry cooling system.  These water costs have been assumed to be


negligible.
                                 75

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     Dry cooling tower costs are based on the latest pricing information




furnished by Hudson Products Corporation for their "Power Tower" module




and are an update of the pricing data incorporated in the computer program




described in Ref. 3.  Capital costs and fan power requirements for the




evaporative cooling system are based on the results presented in Ref. 4.




The costs presented in Ref. 4 for the so-called "Middletown" site are




January 1, 1973 national average costs and have,  in the present study, been




escalated to mid-1975, in accordance with the Handy-Whitman Index for




miscellaneous power plant equipment, to correspond to the Hudson dry cooling




tower cost data.  Pricing data for other components of the evaporative and




dry cooling systems are described in Ref. 1.  The condenser tubes for both




the dry and evaporative cooling systems are made either of corrosion-resistant




Admiralty brass with an outside diameter of 1.0 inch and a wall thickness of




18 BWG, or of stainless steel,at the same cost.  Single pressure operation




was assumed for the surface condensers.  All costs are based on 1975 dollars.




Construction was assumed to be initiated in early 1975 with start-up of the




cooling tower scheduled by the end of 1977.






Annual capital cost;  An annual fixed charge rate is applied to the  capital




cost of the cooling system to determine the annual cost of interest, amor-




tization  and other charges incidental to the acquisition and use of  the initial




capital expense.  An annual fixed charge rate of 15 percent was used in the




present study.






Annual cost of operation and maintenance:  This is the cost of operating and




maintaining the  cooling system and  is figured as a percentage of the capital
                                 76

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cost of the cooling system.  In the present study, annual operating and




maintenance costs were taken to be one percent of the capital cost of




the cooling system.






Annual credit for excess power generation: As noted above the annual




operating profile assumed 6132 hours of operation per year at constant




throttle full-load conditions except when the turbine-generator was throttled




back to a part-load condition to avoid exceeding the specified back pressure




limit of the unit.  At some ambient temperature conditions the cooling system




may operate at a lower turbine exhaust pressure and generate a greater output




than the nominal generating output of 1000 MWe or 3000 MWe.  The annual credit




for excess power generation is the product of the average fuel cost per kwh




and the excess energy generated.  The unit cost of fossil fuel was taken




to be $0.50 per 10  Btu; with an assumed heat rate of 10,000 Btu/kwh for the




conventional turbine generator, the fuel cost is 5 mills/kwh .






Annual cost of replacement energy: For each cooling system sufficient peaking




capacity must be installed to make up the difference in generator energy




output between the unit and the nominal output when the nominal output is not




obtained.  It is assumed that the nominal capacity need not be met for the




ten highest temperature hours of the year.  The'cutoff temperature for peaking




generation was taken to be 82F (27.8C); above this temperature replacement




energy is assumed to come from installed gas turbine units at a fuel cost of




35 mills/kwh and below this temperature replacement energy is assumed to be




provided by excess capability available elsewhere on the utility system at




a fuel cost of 6 mills/kwh.  The capital cost of replacement capacity was




assumed to be $175/kw based upon the maximum kw; the annual replacement capacity




cost is calculated on the basis of an annual fixed charge of 15 percent.




                                 77

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Annual cost of auxiliary power: This is the cost of the power necessary to

run the cooling system.  The auxiliary power consists of the fan power

necessary to maintain air circulation through the cooling tower, and the

pumping power necessary to maintain water circulation through the cooling

system.  The energy cost for the auxiliaries is based on the fuel cost for

the plant, and, as noted above, is taken to be 5 mills/kwh for a conventional

turbine generator, with an allowance of 0.2 mills/kwh for operation and

maintenance.  The incremental cost of sufficient additional plant capacity

to provide the auxiliary power required is assumed to be $400/kw based on

the maximum auxiliary power; the annual cost of auxiliary power is calculated

on the basis of an annual fixed charge of 15 percent.


Annual fuel cost: As noted previously the unit cost of fuel is $0.50 per

10  Btu; with an assumed heat rate of 10,000 Btu/kwh for the conventional

turbine generator the fuel cost is 5 mills/kwh .

     A summary of the unit price data is found in Table 4-1.


4.2  Comparison of Dry and Evaporative Cooling Systems Not Including the Costs
     of Water

     Two comprehensive computer programs developed at R. W. Beck and Associates

were used to facilitate the optimization analyses of the dry and evaporative

cooling systems.  The general elements of the computer program for the dry

cooling system are described in Ref. 1; a detailed updated version of this

program is described in Ref. 3.  The description of the computer program

developed by R. W. Beck and Associates for the evaporative cooling system has

not been published in  the literature.  Comparable input pricing data was used

for each  computer program in order  to obtain a meaningful comparison between

the dry and evaporative cooling systems at each site.
                                  78

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         Table 4-1.  Summary of unit price data.
   Annual Fixed Charge Rate (percent)                 15
   Unit Fuel Cost ($/106 Btii)                          0.50
   Replacement Capacity Charge Above
        82F ($/maximum kw)                          175
   Replacement Capacity Charge Below
        82F ($/maximum kw)
   Replacement Energy Cost At and Above
        82F (mills/kwh)                              35
   Replacement Energy Cost Below
        82F (Mlls/kwh)
   Auxiliary Power Capital Cost
        ($/maximum kw)                               400
   Auxiliary Energy Cost                               *


   Interest During Construction (percent)              8


   Construction Period (years)                         2


   Scheduled Start-up (year)                        1977
*  Based on average fuel cost plus operation and maintenance.
   O&M is 4% of average fuel cost.
                                 79

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     The meterological data at five of the six sites were obtained from




either the Decennial Census of United States Climate' (Summary of Hourly




Observations) or from the National Climatic Center of the National Oceanic




and Atmospheric Administration, Asheville, North Carolina.  This data con-




sists  of 10-year average data of the mean annual dry-bulb temperature




over the range of relative humidities and the frequency of occurrence at




five degree intervals of dry-bulb and wet-bulb temperatures.   Meterological




data for Kaiparowits/Escalante, Utah were based upon data gathered from




Southern California Edison Company at Nipple Beach, a plateau located in




Kane County, Utah, near the site of the proposed plants.  This data was




collected over a three year period from November 1971 to February  1975.




     At each site the dry cooling systems were optimized and evaluated




with high back pressure turbine-generators, that is, turbines limited to




15.0 inches Hg absolute exhaust pressure, as well as turbine generators of




conventional design, that is turbines limited to 5.0 in Hg absolute.  Dry




cooling systems with high back pressure turbine-generators are generally smaller




in size, with concomitant smaller capital costs than those utilizing conven-




tional turbine generators; however, they are not as thermally efficient and




result in higher fuel costs.  The evaporative cooling systems were optimized




and evaluated with turbines of conventional design.  The results that are




presented in this section for the evaporative cooling system do not include




the costs of water.  The water costs will be detailed in Section 4.3.




     Figure 4-2 presents the annual evaluated costs for the dry cooling




system with high back pressure turbine-generators as well as turbine-generators




of conventional design at Navajo/Faraington, New Mexico as a function of the




initial temperature difference.  Similar results have been obtained at the
                                 80

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  ta

  8

  13
  11
  CO


  W
  a

  e
     135
120
                          /  Conventional Turbine Generators
                             High  Back Pressure  Turbine
          f Optimum  Design
        20
                 30
                     40
50
60
70
                   80
                                                                         90
                                 Temperature (  F)



       Fig. 4-2.  Annual evaluated cost of  dry  cooling  system as  a  function

            of the initial temperature difference for Navajo/Farmington,  New  Mexico.
o
o

a
w
p
  M
  X
>
W
     93
     90
                           I    I
                                              I    I
             I     I    I    1
       20
                              25
                                                            I    I     t
                                                       30
                                Range  (  F)



       Fig.  4-3.   Annual evaluated cost of evaporative cooling system as a

                 function of cooling range  for  Navajo/Farroington,  New Mexico.
                                       81

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other five sites.  The total annual evaluated cost of the cooling system




Is the algebraic sum of the annual capital  cost, the annual cost of opera-




tion and maintenance, the annual cost of replacement energy and capacity,




the annual cost of auxiliary power and  the  annual fuel cost, with credit




given for excess power generation.  The optimum design corresponds to the




minimum annual evaluated cost.  As expected, with the relatively low fossil




fuel costs the dry cooling system evaluated better with the high back




pressure turbine-generators in all cases.




   The annual evaluated costs for evaporative cooling systems are presented




in Figure 4-3 as a function of the cooling  range for a turbine-generator of




conventional design for the Navajo/Farmington, New Mexico site.  The curve




has already been optimized relative to the approach temperature.  For a




given design back pressure the lowest cooling range considered generally




resulted in the lowest annual evaluated cost.  The curves are essentially




flat at the minimum range and therefore this condition can reasonably be




accepted as the optimum design condition.  Similar results were obtained at




the other five sites.




   The optimized results for the Navajo/Farmington, New Mexico site are given




in Tables 4-2 through 4-4.  Table 4-2 presents a summary of design conditions




for the optimized dry and evaporative cooling systems.   Table 4-3 gives a




summary of the capital costs for the optimized cooling systems while a summary




of the energy and power quantities are given in Table 4-4.  It has been assumed




that the overall thermal efficiency of the power plant with conventional




turbines is 35 percent with approximately 48 percent of the heat dissipated




to either the wet tower or the dry tower.  Of the 17 percent remaining heat,
                                 82

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Table 4-2.  Summary of design conditions for optimized cooling systems at Navajo/Farmington,  New Mexico.

Average Annual Dry-Bulb Tempera ture,F
Average Annual Wet-Bulb Temperature,F
Design Wet-Bulb Temperature,0?
Ambient Temperature for Determination of
Peaking Capacity Requirement, P
Initial Temperature Difference,P
Design Cooling Range, F
Design Approach Temperature , F
Design Terminal Temperature Difference,F
Design Inlet Temperature, F
Turbine Exhaust Pressure, in Hga
Total Tower Heat Load, 106 Btu/stream hr
Condenser Duty, 10 Btu/stream hr
Circulating Water Flow, 103 gallons per
stream min.
Condenser
Surface Area, 103 sq.ft.
Number of Tubes, 103
Tube length, ft.
Velocity through tubes, ft/sec.
Dry Cooling
Conventional Turbine
51



97
31
15.5

6.0
79.6
2.0
13939.8
13761.0

1782

1653
129
49
6.95
Dry Cooling
High Sack
Pressure Turbine
51



97
67
33.5

5.0
85.0
3.8
15637.2
15438.3

912

1357
136
38
6.73
Evaporative
Cooling
51
40
64



26.4
28.0
7.0
92.0
3.5
14166.0
13983.0

1072

1314
156
32
6.81

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        Table  4-3.  Summary  of capital  costs  for  optimized  cooling  systems  (10   Dollars)  at Navajo/Farmington, New Mexico-

Cooling Tower
Circulating Water Facilities
Electrical
Condenser
Suplemental Evaporative Cooling
System for Auxiliary Cooling
Interest During Construction
Additional System Supply Required
by High Exhaust Pressure Turbine
Total Cooling System Erected
Capital Cost
Incremental Plant Capacity to
Provide Auxiliary Power
Replacement Capacity for Peaking
Total Capital Investment
Dry Cooling
Conventional Turbine
142.466
14.418

16.774
.751
27.141

201.550
37.533
15.192
254.275
i*xy ^ouxxn^
High Back
Pressure Turbine
75.979
7.237

12.125
.751
14.967
8.094
119.153
20.363
16.867
156.383
Evaporative
Cooling
11.911
7.492
2.477
11.824

4.968

38.672
7.703
6.750
53.125
CO
.e-

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      Table 4-4. Summary of energy and power quantities for optimized cooling systems at Navajo/Farmington, New Mexico.

Gross Annual Energy Generation
of Plant, Mwh
Excess Energy Generation, Mwh
Replacement Energy
Above 82F, Mwh
Below 82F, Mwh
Maximum Replacement Capacity
Above 82F, kw
Below 82F, kw
Auxiliary Energy, Mwh
Maximum Auxiliary Power, kw
Dry Cooling
Conventional Turbine
18,602,334
215,790

9,765
0

78,870
-7,980
441,825
103,491
Dry Cooling
High Back
Pressure Turbine
18,631,773
255,096

19,629
0

104,445
6,939
306,339
55,506
Evaporative
Cooling
18,414,933
47,403

10,872
12,840

38,571
13,674
118,080
19,257
00
Ul

-------
approximately 10 percent is  dissipated through the stack gases,  3 percent




to reheat the fuel gas  after desulfurization,  and approximately  4 percent



is dissipated through in-plant  losses.




   A breakdown of the annual evaluated costs for the optimized cooling




systems are presented in Table  4-5  for Navajo/Farmington, New Mexico.  The




principal cost difference between the three systems considered is due to




the size or capital cost of  the cooling tower, followed by the difference




in the cost of the auxiliary power  arid energy.  The annual plant fuel cost




is substantially higher for  the dry cooling system with the high back




pressure turbine generator as compared to the other two systems.  These




trends were found for the five  other sites studied.




   Table 4-6 compares the total evaluated costs of the optimum dry cooling




system with high back pressure  and  conventional turbines, with those of the




optimum evaporative cooling  system  at each of the sites.  It is  to be




emphasized that the cost of  water is not included in the evaporative cooling




costs.  The difference in the annual evaluated cost between the  optimum dry




cooling system and the optimum  evaporative cooling system is also shown in




the table.  As noted previously the difference is due primarily to the




difference between the annual capital costs of the two systems.   The break-




even water costs, expressed  as  $/1000 gallons of evaporated water, are also




shown in Table 4-4.  This quantity  is the ratio of the difference in the




total evaluated costs between the optimum dry and evaporative cooling system




to the total quantity of water  evaporated in a year from the evaporative




cooling tower.  The breakeven water cost represents the total cost of water




for which the total annual cost of  an evaporative cooling system  (including




the costs of water) is equal to the total annual cost of a dry cooling system.
                                 86

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          Table  4-5.   Breakdown  of  Annual  Evaluated  Costs  for Optimized
              Cooling System at Navajo/Farmington,  New Mexico (10^  dollars/yr),
                                      Dry Cooling

                          Conventional          High Back          Evaporative
                            Turbine          Pressure Turbine        Cooling
Annual Capital and
  Operation and
  Maintenance. Cost of
  Cooling System             31.664              18.163               6.187
Annual Plant Fuel Cost       82.239              88.081              82.218
Credit for Excess
  Generation                 -0.952              -1.202              -0.210
Annual Replacement
  Capacity and
  Energy Cost                 2.412               3.429               1.470
Annual Auxiliary Power
  and Energy Cost             8.250               4.840               1.706
Total Annual Evaluated Cost 123.613             113.311              91.371
                                    87

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                  Table 4-6.  Comparison of total annual evaluated costs of optimized cooling systems and breakeven water costs.
SITE

COLSTRIP, MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO*
NAVAJO/FARMINCTON,
HEW MEXICO
KAIPAROWITS/ESCAL.1NTE
UTAH
COLSTRIP , MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARM1HGTON,
HEW MEXICO
KAIPAROWITS/ESCALANTE
UTAH
Total Annual Evaluated Costs
do6 dollars/yr)
Evaporative Cooling
Dry Cooling Without Costs of Water Difference
Conventional Turbines
123.204 91.122 32.082
124.605 91,554 33.O51
128.110 -90.426 37.584
43.451 30.482 12.969
123.612 91.371 32.241
127.971 92.001 35.970
High Back Pressure Turbines
112.467 91.122 21.345
112.362 91.554 20.808
112.140 90.426 21.714
38.284 30.482 7.802
113.310 91.371 21.939
114.753 92.001 22.752
Total Water
Evaporated
(10s gallons/yr)

7377
7023
7398
2567
7686
7764
7377
702J
7398
2567
7686
7764
Breakeven water
Costs (S/1000 gallons
of evaporated water)

4. 35
4.71
5.08
5.05
4.19
4.63
2.89
2.96
2.94
3.04
2.85
2.93
* 1000  MWe, all others  3000 MWe .

-------
If the actual water cost does not exceed the breakeven water costs,  an




evaporative cooling system would be selected; if the actual cost of  water




exceeds the breakeven water cost, dry cooling would be selected.






4.3  Costs of Water




     The cost of water comprises the cost of supplying the makeup water,




the cost of treatment of the makeup and/or the circulating water in the




tower, and the cost of treatment and disposal of the blowdown in an




environmentally acceptable manner.  In this section the water treatment




methods used to control the circulating water concentration and the blow-




down treatment and disposal methods used to meet the disposal regulations




are briefly delineated together with their costs.  Water supply costs are




also discussed.  A more extensive discussion is found in Reference 6.






Circulating Cooling Water Treatment and Blowdown Disposal




     The treatment of circulating cooling water is intended to prevent the




problems of scaling, fouling, microbial growth and corrosion.  Salts




dissolved in the makeup water to the cooling tower are concentrated often




to the point of precipitation because of the large evaporative losses.  The




precipitate, which usually consists of carbonates, sulfates and phosphates




of calcium and magnesium together with silica, tends to adhere to heat




transfer surfaces forming a hard scale and lowering the heat transfer coef-




ficient.  This must be prevented by limiting the concentration of the calcium,




magnesium and silica salts.



      Suspended matter in the  circulating water settles out  in stagnant  spots




in the pipes and heat exchangers.  The circulating cooling water  contains




an ever  increasing amount of  suspended matter in the form of silt in the
                                 89

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makeup water and in the form of dust scrubbed out of the air by the circu-




lating water in its passage through the tower.  The suspended matter must




continuously be removed from the circulating cooling water.




     Circulating cooling water is warm and well oxygenated and receives a




steady supply of oxygen for air-borne growth.  Untreated cooling systems




are subject to fungal rot of the wooden parts of the tower, bacterial




corrosion of iron and bacterial production of sulfide, and large growths




of algae in the sunlit portions of the tower.  Biocidal chemicals must




be added to control growth.




     The control of corrosion with chemicals has not been considered since




the condenser heat transfer surfaces are made of copper alloys or stain-




less steel which minimizes corrosion.  However chlorides have been limited




to 3000 mg/1 to prevent corrosion on stainless steel.  This does not apply




if copper-alloy condensers are used.  This limitation on chloride also




restricts the drift salt concentration and minimizes damage to local vegeta-




tion and groundwater supplies.




     Table 4-7 lists the control limits for  cooling tower circulating cooling




water used in this study.




     In a recent study  general methods of treatment of the makeup and




circulating cooling waters to prevent scaling, fouling and microbial growth




have been presented together with their costs.  Emphasis was placed on




finding water treatment disposal systems which minimize the total evaluated




cost.  The results have shown that the total evaluated cost is minimized by




evaporating the highest possible fraction of the makeup water.  Higher  con-




centrations increase the cost of treatment of the circulating cooling water




but this is more than off-set by the reduced cost of supplying the makeup
                                 90

-------
          Table  4-7. control limits for  cooling  tower
                      circulating water  composition.
                                              Suggested at
                                              high pH with
Conventional at
low pH*
pH 6-5 to 7.5
Suspended Solids (mg/1) 200 - 400
Ca x C03 (as CaCC>3) 1,200
Carbonates (mq/1) 5
high concentration Used in
and dispersants* this study
7.5 to 8.5
300 - 400 300
**
6,000 6,000
5 5
Bicarbonates (mg/1)
   50 - 150
300 - 400
  300
Silica (mg/1)
                              150
                       150 - 200
                    150
Mg x Si02 (mg/1)
Ca x SQ   (as CaCO )
  35,000


1.5 x 106 to

2.5 x 106
 60,000


2.5 x 106 to

  Q x 106
60,000
                                                                  2.5  x  10
Chlorides
                                                                    3,000
 *    From  Ref.  1
 **   Dtore  data  needed to confirm  (footnote  from Ref.  7) .
                                   91

-------
water and disposing of the solid residuals in an environmentally acceptable




manner.  Four sites were studied to illustrate minimum water consumption




and minimum cost treatment and disposal systems.  The results of Ref. 6




have been extended to the six sites considered in the present study.  These




results are presented below.




     One of the major limiting factors requiring treatment is the dust that




is scrubbed out of the air in the cooling tower and concentrated in the




circulating cooling water.  Treatment of the makeup water does not affect




this limit and it is for this reason that the makeup water, as distinct




from the sidestream of the circulating water, has not been treated.  The




dust scrubbed out of the air has been estimated by a technique described




in Ref. 7.  The dust flow is calculated to be 38 Ib/min; about 20 percent




of the dust is suspended in the water with the rest settling in the basin




or not being trapped. The resultant input dust rate is 7.6 Ib/min.  With




this input dust rate and a suspended solids limitation of 300 mg/1 the




control of suspended solids only by blowdown would mean a blowdown'rate of




about 6000 gpm (for an evaporation rate of 20,000 gpm) and a maximum con-




centration of 4.3 cycles.  Sidestream separation of suspended solids has been




used in every case.  Clarifiers have been used with the overflow from the




clarifier assumed reduced to 100 mg/1 suspended solids.  The underflow of a




clarifier that is used exclusively for dust and dirt removal is assumed to




be 1% suspended solids with an underflow rate not larger than 2% of the feed




rate.  (Larger underflow rates reduce the concentration).  When lime precipi-




tation also occurs the suspended solids concentration in the underflow can




be higher than 1%.
                                92

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      Synthetic  flocculants  are  added to the clarifier feed at  a rate of



 1 mg/1  at  a  cost  of  $1.60/lb.   When  lime is not  added alum is  added  at a



 rate  of 20 mg/1 at a cost of  5.3c/lb.



      In some designs a  clarifier  effluent concentration of 100 mg/1  sus-



 pended  solids is  not good enough  and a  filter  has  been added.   The supplied



 costs of automatic backflushed  gravity  sand filters  is approximately $150/ft


                          2
 at a  flow  rate  of 2  gpm/ft  for a cost  of $75/gpm.



      Synthetic  polymeric dispersant  chemicals  (antifoulants) are added to



 the circulating water at a  cost of 3C/1000 gallons of sidestream flow.



      The usual  way to prevent scaling when high  cycles of  concentration  are



 used  is  to remove calcium, magnesium, bicarbonate, phosphate and silica.



 When  the four ions and  silica are removed  calcium  sulfate  or the chloride



 ion will usually  be what limits further  concentration.  A  common procedure



 used  to  remove  the calcium and  magnesium ions  is to precipitate with  lime



 and soda ash.   This  lime-soda softening  procedure was  used to  treat  the



 sidestream flows  at all of the  sites considered.  The  quantities of  lime

                                                             Q

 and soda ash  required are estimated  from well  known relations  , and will



 not be repeated here.



      Silica  is precipitated with magnesium hydroxide  at a  rate of about


                        ++9'10
 1 gm  SiO~  per 7 grams Mg         If more silica removal is  required  then



magnesium will have to be added.  The ability  to remove silica with magnesium



 at a  cooling water temperature  of 80 F or  more is illustrated in Ref. 11 (p. 84).



At Navajo/Farmington, New Mexico;  Gillette, Wyoming; and Kaiparowits/Escalante,



 Utah,  dolomite was added to the clarifier  to precipitate silica.



     When  the pH  is raised to about 11 phosphate removal is quite complete,



requiring a consumption of 5 moles of lime for 3 moles of P     Calculation



of the lime requirements must include the  lime needed  to raise the pH.




                                93

-------
     Lime-soda softening involves a small investment in chemical feeders and


mixers and a large investment in clarifiers to settle out the precipitates.


Installed clarifier costs have been estimated using the cheaper of steel or


concrete tanks.  The concrete cost was taken to be 175/cubic yard and


includes excavation, backfill, concrete, concrete forms, rebar and finish.


Steel tank costs depend upon the diameter of the tank.  Clarifiers were


sized separately for each site study and depending on the particular con-

                                                           2
ditions linear velocities in the range of 0.4 to 1.3 gpm/ft  were chosen.


A rule of installing two parallel clarifiers each having 65 percent of. the


required capacity was adopted.


     Microbial growth was prevented by the addition of microbiocides to the


circulating water.  The costs of Mocides having EPA, USDA and similar


approvals as non-dangerous materials lie in the broad range of 15
-------
in  the  cooling  tower blowdown is at most  20%  of  the  weight  of  the  dry  solids



in  the  flue gas desulfurization slurry, well  within  the  reserve  capacity  of



the desulfurization thickener clarifiers.  As a  result the  costs associated



with thickening the cooling tower blowdown are relatively small.   The



thickened slurry is disposed of on-site by ponding or as land  fill.



     Table 4-8 shows the flow diagram, circulating cooling  water concentration



and cost estimates for the Navajo/Farmington,  New Mexico site.  The makeup



water cdmposition for all the sites is found  in  Appendix B.  Table 4-9



summarizes the annual evaluated costs of water treatment and blowdown



disposkl at each of the six sites.  The costs  range  between $0,17 to $0.31 per



1000 gallons of water evaporated.





Water Supply



     Water must be bought and brought to the plant.  For the purposes of



this study the cost of the water rights were assumed to be  zero.



     In studying pipelines, data have been obtained  from two sources.



Stone and Webster Engineering Corporation has  recently estimated costs for


                                                        12
a 12 inch diameter pipeline in the Wyodak, Wyoming  area  .   The line was



designed for a water flow of 2,200 gpm and runs for about 3.8 miles.   The



total cost was estimated to be approximately one million dollars and includes



the cost of pipe metal,  labor for installing,  excavating and backfill.   Extra



costs for going under  or over roads, railroads, rivers,  or bridges  are not



included.  The cost represents about $33,000/(inch diam-mile).


                                            13
     Data from a Bureau  of Reclamation study   of buried aqueducts  showed



that the average costs vary from $21,000/(inch diam-mile) for pipelines to



84 inches in diameter  to $32,000/(inch diam-mile) for diameters greater than



84 inches.   For the present study an installed cost of $25,000/(inch  diam-mile)





                                95

-------
                    Table 4-8.  Flow diagram,  circulating water concentration and estimated costs
                               for Navajo/Farmington,  New Mexico cooling Cower ,
                            Evaporation
                            20,899 gpra**
           1.80 Ib/min
    21,290 gpra
 T.D.S.=330 ppm
   S.S.=100 ppm
  Lime 20.1 Ib/min
Soda Ash 10.5 Ib/min
Dolomite 22.0 Ib/min
                                                 Dust
                                              15.9 Ib/min
   401 gpm
T.D.S.=6500 ppm
   S.S.=3.3%
                  *  Without additional thickening  Of
                     clarifier underflow.

                  ** All flow rates are expressed in gallons
                     per stream minute.
                Concentration of Circulating Water
                       (in mg/1 as CaCO.)
Ca
 +2
Mg
Na+
115

39
6572
636
co3

HC03~
v1
-

124
6254
                                      Si02   13 mg/1 (as Si02)
                               Costs

                       Capital Costs ($1000)


                       2 Lime and Dust Clarifiers
                         (approx. 169 ft. dia. each)
Evaluated Costs ($1000/yr)

15% of Capital

Chemicals

  Lime

  Soda Ash

  Dolomite

  Flocculant

  Dispersant

  Biocide

  Sulphuric Acid (pH control)

    Total Chemicals


Labor

Slowdown Disposal

  TOTAL EVALUATED COSTS
                                                                                                               1140
                                                                                                                173
                                                        228

                                                        177

                                                        185

                                                        113

                                                        252

                                                         84

                                                          1
                                                               1040


                                                                300

                                                               	6

                                                               1340

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Table 4-9. Summary of annual evaluated costs of water treatment and blowdown disposal.
SITE
COLSTRIP, MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON, NEW MEXICO
KAIPAROWITS/ESCALANTE, UTAH
Water Treatment
Capital
($1000/yr)
169
165
169
112
173
174
Chemicals ,
and Labor
(SlOOO/yr)
1060
1390
1280
468
1340
2215
Blowdown
Disposal
($1000/yr)
6
6
6
2
6
10
Total
($1000/yr)
1235
1561
1455
582
1519
2399
Total Costs
($71000 gallons
of water evaporated)
0.17
0.22
0.20
0.23
0.20
0.31

-------
and annual charges of 10% per year were assumed.  Furthermore we have




assumed pumping energy costs of 10 mills/kw-hr (lc/kw-hr) , as compared to




the cooling tower auxiliary costs of 5.2 mills/kw-hr.  It can be shown




that there is an optimum flow rate which minimizes the total evaluated




cost of supplying water to the plant.  For the particular conditions cited




the optimum flow rate is 9.65 ft/sec.




     At some of the sites the pipeline supplied not only the water for the




steam electric power plant but also supplied the water for some of the other




coal conversion plants.  Table 4-10 lists the other plants supplied by the




same pipeline that supplied the steam electric power plant.  The table also




lists the length of pipeline required at each site, L, together with the




difference in elevation, H, between the power plant site and the water source.




Note that two power plants are sited at Kaiparowits/Escalante, Utah, and a




different pipeline supplies water for each plant.  The diameter of pipe, D,




required at each of the sites assuming peak flow rates is also shown.  The




peak flow rates are based on the water consumption data presented in the




summary tables of Section 10 and the appropriate load factor.  Table 4-11




shows the total annual evaluated costs of installing the pipeline and the




annual pumping energy costs.  The total annual evaluated cost of supplying




water to the power plant is given in column 4 and is obtained by multiplying




the total evaluated cost of the pipeline by the fraction of water that is used




by the power plant.  For example, at Colstrip, Montana, the total water consumed




by the power plant is 16,500 gallons per calendar minute while the water




consumed by the Synthane plant is 4,800 gallons per calendar minute.  The cost




of supplying water to the power plant is
                   16,5004.800






                                 98

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Table 4-10.  Pipeline data.
1
SITE
COLSTRIP, MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON , NEW MEXICC
KAIPAROWITS/ESCALANTE , UTAH
Plants Supplied by Pipeline
3000 MWe Power Plant
250 x 106 scf/streaffl day Synthane
3000 MWe Power Plant
250 x 106 scf/stream day Lurgi
3000 MWe Power Plant
250 x 10^ scf/stream day Synthane
250 x 10^ scf/stream day Lurgi
1000 MWe Power Plant
3000 MWe Power Plant
250 x 106 scf/stream day Synthane
L. 3000 MWe Power Plant
I, 3000 MWe Power Plant
L
(miles)
35
20
170
10
15
45
25
H
(ft)
710
0
2000
2330
200
2780
2100
D
(ft)
2.9
2.6
3.0
1.6
3.1
2.8
2.8

-------
                            Table  4-11.  Evaluated  costs of supplying water.
SITE
COLSTRIP, MONTANA
BEOLAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON , NEW MEXICO
KAIPAROWITS/ESCALANTE , UTAH

Evaluated Coses ($10 /yr)
Pipeline Installation
3.06
1.58
15.43
0.47
1.38
3.75
2.08
Pumping
0.96
0.32
4.28
0.38
0.38
1.80
1.21
Total
4.02
1.90
19.71
0.85
1.76
5.55
.3.29
Total
Power Plant
3.11
1.66
13.48
0.85
1.36
5.55
3.29
Power Plant Costs
(S/1000 gallons
water evaporated)
0.42 (0.48)
0.24 (0.26)
1.82 (2.23)
0.33 (0.33)
0.18 (0.20)
0.71 (0.71)
0.42 (0.42)
o
o

-------
The last column is the cost of supplying water to the power plant divided by




the total amount of water evaporated during the year.  The numbers in paren-




thesis are the results of Calculations done by assuming that the pipeline




supplies water only for 'the power plant and not for any of the Lurgi or




Synthane plants.




     Table 4-12 summarizes the costs of water treatment, blowdown disposal




and water supply at each of the sites and compares them to the breakeven water




costs.  In none of the cases does the cost of water exceed the breakeven water




costs indicating that wet cooling is preferred at each of the sites.  Only at




Gillette, Wyoming, where the power plant is 170 miles from the water source and




the cost of supplying water is quite high, does the cost of water even begin




to approach the breakeven water costs, and even then only for the high back




pressure turbines.




     We should note that our estimates of water costs are low.  For example,




the cost of water treatment and blowdown disposal can be about a factor of




two or three higher, while the costs of water supply does not include the




costs of water rights.  A typical range of water rights costs is $10/acre ft




to $100/acre ft or 3
-------
                               Table 4-12. Summary of evaluated water costs.
SITE
COLSTRIP, MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON, NEW MEXICO
KAIPAROWITS/ESCALANTE, UTAH

Evaluated Water Costs
($/1000 gallons of water evaporated)
Water Treatment
and Slowdown Disposal
0.17
0.22
0.20
0.23
0.20
0.31

Water
Supply
0.42
0.24
1.82
0.33
0.18
0.71
0.42
Total
0.59
0.46
2.02
0.56
0.38
1.02
0.73
Breakeven Water Costs
($/1000 gallons of water evaporated)
High Back
Pressure Turbine
2.89
2.96
2.94
3.04
2.85
2.93

Conventional
Turbine
4.35
4.71
5.08
5.05
4.19
4.63

o
to

-------
The purpose of this cooling system is to reduce the evaporative cooling tower


makeup water requirements as well as the capital costs of the dry cooling


tower.  The system shown in Fig. 4-4 was analysed to show the effect of


makeup water requirements on the evaluated costs of the cooling system.  The


cooling system uses a conventional mechanical draft wet tower and a separate


conventional mechanical draft dry tower; the cooling media for each tower flows


in separate circuits.  The dry tower operates during the whole year with its


greatest operating efficiency in winter while the evaporative tower operates


in warmer weather during periods of peaking.  The evaporative tower operates


only when the turbine back pressure would exceed 5 in Hg absolute with the


dry tower alone.


     R. W. Beck and Associates performed the wet/dry tower calculations by


combining the separate evaporative and dry cooling tower computer programs
         t

described previously into a single program.  The dry cooling system is


designed for a whole range of ITD (dry tower initial temperature difference)


and TTD (condenser terminal temperature difference) (see Fig. 4-1) as is done


for the case of the dry tower alone, with the constraint that the turbine back


pressure not exceed 5 in Hg absolute.  For a given ambient air temperature both


the heat rejection to the condenser and the heat load to the dry tower are


known; the difference between the two is the required heat load to the


evaporative cooling tower.   The operating conditions.for the wet cooling


tower are also known.  A series of wet towers are calculated varying the


range and approach temperature to meet the required .operating conditions and


heat load.   The wet tower is sized to meet the maximum performance requirements


associated with the given range of operating conditions.   For off-design con-


ditions it is assumed that the minimum required number of wet tower segments
                                103

-------
                                    HOT WATER
 HOT WATER
CONDENSER
                                       DRY
                                     COOLING
                                      TOWER
                                   COLD WATER
           EVAPORATIVE
             COOLING
              TOWER
COLD WATER
                                                                 HEAT
                                                                EXCHANGER
                                  Fig.  4-4.  Wet/dry  cooling  system.

-------
will be operated and that fan horsepower will be reduced  in order  to  conserve




water and minimize auxiliary energy requirements.  At each ITD,  the total




evaluated costs for the combination wet and dry towers are optimized.




     Table 4-13 lists the optimum wet/dry cooling tower combinations  at




Navajo/Farmington, New Mexico for different water costs,  as well as the dry




cooling system with an auxiliary tower and the all evaporative cooling system




presented in the preceding sections.  Fig. 4-5 shows the  total annual evaluated




costs of the wet/dry cooling system as a function of the water evaporated in




the evaporative cooling tower expressed as a percentage of evaporative loss




of the all evaporative cooling system.  There is virtually no difference in




the evaluated cost with the cost of water to $1.00/1000 gallons  of evaporated




water.  The highest values of ITD considered correspond to points of inflection




in the curves shown in Fig.  4-5.




     It is .shown on Fig. 4-5 that when water costs above about $2.20/1000 gallons




partial dry cooling is more economical than all wet cooling.   The term




"breakeven cost" of water is the cost associated with that curve for which




the annual charge is equal at both ends, i.e., $4.19/1000 gallons  (Table 4-6) as




shown on Fig. 4-5.   The actual water cost at which partial dry cooling becomes




economical may be $0.20-$0.30/1000 gallons of water evaporated more than the




estimated value of $2.20/1000 gallons because of the increase in the total




annual evaluated cost with increasing water costs.




     As was  shown previously, the cost difference between a dry  cooling system




and an ail wet cooling system is relatively insensitive to site,  at least




for the sites considered in  this study.   If a water cost of $2.20-$2.50/1000




gallons of water evaporated  were used at all the sites,  then  Table 4-12




indicates that except for Gillette,  Wyoming,  all evaporative  cooling systems
                                105

-------
    Table 4-13.  Total annual evaluated costs for optimum wet/dry cooling systems at Navajo/Farmington,  New Mexico.
Dry Tower
ITD TTD
(Op) (Op)
30 6
35 S
40 5
45 5
SO S
55 5
60 5
6S S
70 S
75 5
80 5
02 5
84 5
(1) 31 6
(2) -
Wet Tower
Range Approach
 (F>
16.2 20
29.9 19
29.9 19
30.0 19
29.9 19
29.8 19
29.7 19
29.6 19
2B.4 20
28.3 20
28.3 20
28.3 20
28. 3 20
* *
26.4 28
Wet Tower
Evaporative Lt/ss
<106 gallons/yr)
5.51
16.67
44.37
95.53
194.25
319.45
488.82
685.13
917.47
1158.69
1411.58
1514.22
1629.55
4.8S
7686.0
Total Annual Evaluated Costs (S106/vr)
($0/1000 gallons (SO. 50/1000 gallons (SI. 00/1000 gallons
water evaporated) water evaporated) water evaporated)
124.800 124.803 124. 800
121. 3O3 121.311 121.320
118.060 118.082 118.104
116.011 116.059 116.107
114.341 114.438 114.535
112.758 112.918 113.077
111.465 111.709 111.9S3
110.640 110.982 111.325
109.773 110.232 110.690
109.130 109.709 110.289
108.380 109.086 109.792
108.239 108.996 109.753
108.117 108.932
123.613 123.615 123.618
91.371 95.214 99.0B7
(1)  Dry cooling system with auxiliary tower.



(2)  Evaporative cooling system.
* Conditions not specified for auxiliary tower.

-------
        126
        120
    o
    .(
    
     en
     o
     w
     I
H
O
        110
     o

     H  100
         90
                                                                                    $4.19/1000 gallons of

                                                                                       water evaporated
                                                                            2.20-2.50
                       COMPUTER CALCULATIONS
                  	 SKETCHED IK
                                                                             0.50
                      0.25                   0.50                    0.75


WATER EVAPORATED AS A PERCENTAGE OF WATER EVAPORATED FOR ALL EVAPORATIVE COOLING SYSTEM
                                                                                                          1.0
      Fig.   4-5.  Total annual evaluated costs of wet/dry cooling system as a percentage of evaporative  loss

                             of all evaporative cooling system at Navajo/Farmington, New Mexico.

-------
would be preferred if sufficient water is available.  At Gillette, Wyoming




the choice of art all evaporative cooling system would be marginal.  However,




a savings in total water consumed in the cooling tower of about 75% of that




required by all evaporative cooling would be made at the expense of only




50% of the difference in evaluated costs between dry and all evaporative




cooling.






4.5  Water Consumed and Solid Residuals Generated




     The total water evaporated at each of the sites is shown in Table 4-6




and repeated again in Table 4-14.  The tower calculations were made by




R. W. Beck and Associates using the computer program mentioned in Section 4.2,




which is based upon the method of Merkel (see p. 587 of Ref. 14).  These




quantities are also repeated in the summary tables of Section 10.  The total




cooling tower heat load as well as the heat dissipation rate is also shown




in Table 4-14.  This is to be compared to the dissipation rates for the process




cooling water shown in Table 2-12.




     As discussed in Section 4.3 the treatment of cooling water yields waste




sludges'which are about 40% solids - 60% water.  These sludges are derived




primarily from limesoda softening, dust concentration, and thickening.  The




wastes produced at each site are shown in Table 4-15 and repeated again in




the summary tables in Section 10.  The water evaporated is obtained from




Table 4-14.




     Slowdown is not the only liquid waste effluent from a cooling tower.




Small droplets of cooling water having the same contaminants and concentrations




as the blowdown are entrained into the air flow and are carried out of the tower




onto the surrounding terrain.  Local vegetation and groundwater supplies may
                                  108

-------
Table 4-14. Water evaporated and heat dissipation rates for cooling towers.
SITE
COLSTRIP, MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON, NEW MEXICO
KAIPAROWITS/ESCALANTE, UTAH
Total Water
Evaporated
(106 gallons/yr)
7377
7023
7398
2567
7686
7764
Water Evaporated
(gallons/calendar minute)
14,040
13,360
14,075
4,867
14,617
14,770
Cooling Tower
Heat Load
(1012 Btu/yr)
86.87
86.87
86.35
28.96
86.87
86.87
Heat Dissipation
Rate
(Btu/lb water
evaporated)
1414
1484
1401
1354
1357
1343

-------
Table 4-15. Residuals generated at each site

SITE
COLSTRIP , MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON ,
NEW MEXICO
KAIPAROWITS/ESCALANTE ,
UTAH
Wet-Solid
Slurry
(tons per
1000 gallons
of water
evaporated)
0.0075
0.0088
0.0090
0.0064
0.0081
0.0123
Dry Solids
in Slurry
(tons per
1000 gallons
of water
evaporated)
0.0030
0.0035
0.0036
0.0026
0.0032
0.0049
Water
in Slurry
(gallons per
1000 gallons
of water
evaporated)
1.079
1.271
1.295
0.911
1.175
1.774

Wet-Solid
Slurry
( tons/c . day)
151.6
169.3
182.4
45.0
170.6
261.6

Dry Solid
(tons/c. day)
60.6
67.3
73.0
18.3
67.4
104 . 2

Water in
Slurry
(gal/c- min)
15.1
17.0
18.2
4.4
17.2
26.2

-------
be affected by the deposition of the salt-containing droplets.  The amount




of drift is measured as a percentage of the total circulating cooling water




through the tower.  Until recently drift losses of less than 0.2 percent




were guaranteed by the tower manufacturers.  Now, with the development and




addition  of new drift eliminators, drift rates as low as 0.002 to 0.005 percent




have been measured on several new towers,with the lower drift rate attributed




to natural-drift towers and the higher rate to mechanical-draft towers.  For




this study a drift rate of 0.005 percent was used.  The circulating water flow




rates as well as the drift rates are summarized in Table 4-16; the drift rates




are repeated in the summary tables of Section 10.




     The demineralizer waste is taken fco be 50% moisture and to have a solids




content of 1.6 times the total dissolved solids in the makeup water.  This




corresponds to  complete deionization of the makeup water with a regenerant




usage of 160% of the stoichiometric values.  The boiler makeup water was taken




to be 300 gallons/stream minute (210 gallons per calendar minute) per 3000 MWe.




Table 4-17 shows the soluble wet-solids sludge generated from the demineralizer




waste.
                                  Ill

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Table 4-16,Drift rates .
SITE
COLSTRIP , MONTANA
BEULAH, NORTH DAKOTA
GI LLETTE , WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON ,
NEW MEXICO
KAIPAROWITS/ESCALANTE ,
UTAH
Circulating
Flow Rate
(gallons per
stream minute)
1,071,870
1,032,795
1,147,152
344,265
1,071,870
1,032,795
Drift Rates
(gallons per
stream minute)
53.59
51.64
57.36
17,21
53.59
51.64
(gallons per
calendar minute)
37.51
36.15
40.15
12.05
37.51
36.15
(106 gallons/yr)
19.7
19.0
21.1
6.3
19.7
19.0

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Table 4---17. Demineralizer residuals.
SITE
COLSTRIP, MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON,
NEW MEXICO
KAIPAROWITS/ESGALANTE ,
UTAH
Wet-Solids
Sludge
(tons/c.day per
1000 g/c. min)
7.95
8.22
7.56
4.61
5.76
11.06
Boiler
Makeup
(gal/c. min)
210
210
210
70
210
210
Wet-Solids
Sludge
(tons/c . day )
1.6
1.7
1.6
0.3
1.2
2.3
Dry Solids
(tons/c. day)
0.8
0.9
0.8
0.2
0.6
1.2
Water
in Solid
(gal/c. min)
0.1
0.1
0.1
0.03
0.1
0.2

-------
 References

 1.   Rossie, J. P., Mitchell, R. D, and Young, R. 0., "Ecomomics of the Use
      of Surface Condensers with Dry-Type Cooling Systems for Fossil-Fueled
      and Nuclear Generating Plants," R. W. Beck and Associates, Denver,
      Colorado, U. S. Atomic Energy Commission Report No. TID-26714 (UC-12),
      December 1973.

 2.   Rossie, J. P., Cecil, E. A. and Young, R. 0., "Cost Comparison of
      Dry-Type and Conventional Cooling Systems for Representative Nuclear
      Generating Plants," R. W. Beck and Associates, Denver, Colorado.
      U.S. Atomic Energy Commission Report No. TID-26007 (UC-80), March 1972.

 3.   Mitchell, R. D., "A Method for Optimizing and Evaluating Indirect
      Dry-Type Cooling Systems for Large Steam-Electric Generating Plants,"
      R. W. Beck and Associates, Denver, Colorado, U.S. Energy Research and
      Development Administration Report No. ERDA-74 (UC-12), June 1975.

 4.   "Heat Sink Design and Cost Study for Fossil and Nuclear Power Plants,"
      United Engineers and Constructors, Inc., U.S. Atomic Energy Commission
      Report No. WASH-13600 (UC-13 & 80), December-1974.

 5.   Corey, G. R., "A Comparison of the Cost of Nuclear versus Conventional
      Electric Gneeration," Commonwealth Edison Company, Boston, MA,
      December 1975.

 6.   Gold, H., Goldstein, D.  J. and Yung, D., "The Effect of Water Treatment
      on the Comparative Costs of Evaporative and Dry Cooled Power Plants,"
      Water Purification Associates, Cambridge, Mass., ERDA Report No.
      COO-2580-1, June 1976.

 7.   Grits, G. J. and Glover, J., "Cooling Slowdown in Cooling Towers,"
      Water and WastesEngineering, 45-52, April 1975.

 8.   Applebaum, B., Demineralization by Ion Exchange, pages 23-67,
      Academic Press, 1968.

 9.   Mindler, A.B., Permutit Research and Development Center, Princeton, N.J.,
      personal communication.

10.   Kleusner, J., Heist, J.  and Van Note, R. H., "A Demonstration of
      Wastewater Treatment for Reuse in Cooling Towers at Fifteen Cycles of
      Concentration," presented at AIChE Water Reuse Conference, May,  1975

11.   Betg Handbook of Industrial Water Conditioning, Betz Laboratories, Inc.,
      Trevose, PA 19047.

12.   Coraley, W. D., Private Communication, Stone and Webster Engineering
      Corporation, Boston, Massachusetts (September 3, 1975).

13.   "Appraisal Report on Montana-Wyoming Aqueducts," U.S. Department of the
      Interior, Bureau of Reclamation, Washington, D.C. (April 1972).

14.   Kern, D. Q., Process Heat Transfer, McGraw-Hill Book Co., Inc.,  New York (1950),


                                   114

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                          5.   SLURRY PIPELINE





     The coal slurry  pipeline is  a method  of hydraulically  transporting



 coal from  the mine  to its point of use.  Long distance  coal slurry  transport



 may involve distances of  several  hundred miles or as much as a  thousand miles,



 as in  the  case of the proposed ETSI piepline from Gillette,  Wyoming to



 White  Bluff, Arkansas .   In addition to the  mining of the coal,  the process



 of slurry  preparation involves size reduction by crushing the coal,  adding



 the slurry water to the crushed coal and then grinding  it finely.   Chemical



 treatment  may be added after  grinding to improve the slurry characteristcs,



 following  which the slurry is  sent to agitated storage  tanks prior  to pump-


   2
 ing .  These processing steps  are  those which have been described for trans-



 porting low ash, low  sulfur coals  as  in the  proposed Gillette pipeline or


                                                 3 4
 in the operational Black Mesa  piepline in Arizona ' .  We suggest that where



 the transport of a high ash coal such as from Farmington be  involved, then



 coal washing prior to grinding should be added to the processing steps.



     By far the largest quantity of water is required for the slurrification



 itself, in which about an equal weight of water and coal are mixed.  The



process can be somewhat arbitrarily broken down into a mine and plant stage.



The mine stage is considered to include mining,  breaking and first stage



crushing.   The plant  stage is  taken  to include processing and slurry prepara-



tion.   A typical but by no means unique process description is as follows.



     Mine



     (i)    Primary breakers reduce run-of-mine coal to a top size of, say,



            4 to 8 inches.



     (ii)    First stage crushers reduce, coal to a top size of, say, 2 inches



            for storage prior  to preparation.
                                 115

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     Plant




     (i)     Storage  bins  of  say,  2  hour capacity,  receive belt  fed coal from




            storage  piles.




     (ii)    Scalping (vibrating)  screens receive belt fed coal  from bins




            and separate  out oversize coal (say, > k inch) for  transport to




            impact crushers.  Undersized coal (say, < V inch) joins product




            from impact crushers.




     (iii)   Impact crushers  reduce  the product to 99% passing \ inch (80%




            passing 5000  van).




     (iv)    Water at about 50 wt.%  is added to the crushed coal in gravity




            feed chutes.




     (v)     Wet rod mill  receives mixture of water and coarse solids and




            grinds coal down to a top size of all passing 28 mesh (80%




            passing 300 ym).  In no case should the top passing size be




            greater than 8 mesh.




     (vi)    Agitated slurry  storage tanks receive the slurry after pumping




            from the sumps into which it is discharged from the mills.  Any




            coarse,  fast-settling particles are either recycled or sent to




            a dump pond,  and the final product  is sent into the pipeline.




     The water requirements  for the mine stage will be evaluated in Section 7,




along with the mining requirements  for the other processes, since they all




differ only in quantity but not in kind.  Similarly, the water  requirements




for basin and reservoir evaporations, plant dust control and service and




potable water uses will be evaluated in Section 8 along with these same




requirements for the other processes considered in this assessment.
                                 116

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     The principal power requirements for the plant include


                   in-plant coal transfer


                   crushing


                   grinding


                   in-plant pumping


                   slurry mixing and agitation


                   pipeline pumping (first stage)


                   plant service electricity


Of these, the grinding power and power for the first stage of pumping far


exceed all the other requirements combined.  For the example illustrated

                                                                  2
the grinding power  would be about 14.5 MWe based on 6.8 hp-hr/ton  and


25 x 10  tons/yr.  A first stage pump station would consume about 14.8 MWe 


The total electric power requirement is seen to be relatively small and will


therefore be assumed to be purchased, with no direct water consumption


charged to power generation.  For the power consumption uses described


cooling water requirements will be negligible.


     From the above discussion we conclude that the principal process water


requirement is for slurrification.  Assuming a 50/50 mixture by weight of


coal and water,then to transport 25 x 10  tons/year of coal at a 100% load


factor the slurry water requirement is



          25 x 10  tons x 2,000 Ibs  x   I gal   x   1 yr    x   1 day
                    yr          min     8.33 Ibs    365 days   1440 mins



                     = 11,420 gal/calendar min.
                                 117

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References
1.  Odasz, F. B., "Coal Slurry Pipelines," Energy, Water and the West
    (E.R. Gillette, ed.), P- 67, Am. Assoc. for Advance, of Science,
    Washington, D.C., 1976.

2.  Cowper, N. T., et al., "Processing Steps:  Keys to Successful Slurry
    Pipeline Systems," Chemical Engineering 79(3), 58-67, Feb. 7, 1972.

3.  Ctvertnicek, T.E., Rusek, S.J., and Sandy, C.W., "Evaluation of Low-
    Sulfur Western Goal Characteristics, Utilization, and Combustion
    Experience," pp. 150-154, EPA-650/2-75-046 (NTIS PB-243 911), U.S.
    Env. Prot. Agency, Office of Res. & Dev., Washington, D.C., May 1975.

4.  Neihaus, E. D., "Water and Energy Requirements in the Mining and
    Processing of Coal," in Proc. Conf. on Water Requirements for Lower
    Colorado Basin Energy Needs, pp. 151-164, Office of Arid Lands Studies,
    Univ. of Arizona, Tucson, Arizona, May 8, 1975.

5.  Energy Transportation Systems, Inc., Unpublished Document, Casper,
    Wyoming, Feb. 21, 1974.  Summarized in memorandum of E. Rappaport,
    Radian Corp., Austin, Texas.
                                 118

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                     6.  FLUE GAS DESULFURIZATIOH






6-1  Particulate and Sulfur Removal




     Process steam is generated in coal-fired boilers for the electric power and




Lurgi plants examined in this study.  In the Synthane process char is burnt to




generate process steam.  The burning of coal, even low sulfur Western coal,




and of char generates both particulates and oxides of sulfur in the exiting




flue gases .  Particulate removal to meet air quality standards need not involve




significant water consumption if electrostatic precipitators are used, although




some water will be consumed in disposing of the fly ash.  We will therefore




reserve our discussion of the water needed for particulate removal to Section




8, where solids disposal is considered, since this need for water is for the




most part related to ash disposal.




     Sulfur dioxide (S0) represents 98% of the sulfur oxide pollutants and




its removal from the combustion gases before they are released to the stack




generally involves an important use of water.  The most likely procedures for




use in the near future are the wet scrubbing systems that utilize limestone




(CaCO.,) , hydrated or slaked lime (Ca(OH)2) or both.  In the wet limestone process




the flue gas contacts a wet limestone slurry in the scrubber and the SCL is




removed following the reaction
with
          CaC03 + S02 - >- CaS03 4- C02,                          (-6.1)
          CaS03 + hO 2 - ~ CaS04-                                (6.2)
The scrubber effluent generates a spent slurry following the reactions





          CaS03 + hK20 - *- CaS03  JjHjO | ,                       (6.3)





          CaS04 + 2H20 - 5- CaS04  2H20 j.                       (6.4)






                                  119

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In the wet lime scrubbing system the gas containing the SO  is reacted with



a wet lime slurry following the reaction



          Ca(OH)  + SO,	*  CaSO  + HO.                          (6.5)
                "     *"           -5    ,



Reactions (6.2) to  (6.4) follow.



     In any of these procedures water leaves the system as a vapor in the



flue gas and in the slurry of spent solids.  In what follows we examine



these.two streams separately and present methods for estimating the water in



these streams independent of the specific scrubbing procedure or its details.





6.2  Water in Flue Gas



     To estimate the quantity of water which leaves the scrubbed flue gas



we make the assumption that this gas is saturated with water vapor at the



temperature and pressure at which it leaves the scrubber in the final absorber



and before any reheat.  The dependence on temperature and pressure of the



water content is illustrated in Table 6-1 which shows the moles of water vapor



per mole of dry gas at saturation.
   Table 6-1.  Moles of water vapor per mole of dry gas at saturation.
"""V^total Pressure
Temperature*"-*^

-------
     From Table 6-1 it is clear that  lack of knowledge of the pressure of




saturation in the range of interest will give an error of not more than -7%.




However if the temperature of saturation is 10 P higher than was assumed the




water content of the flue gas will be about 40% higher than calculated.  This




indicates a severe limitation on the ability to estimate the quantity of water




in the flue gas without detailed and precise information on the gas temperature.




Moreover, this also shows that large variations in the flue gas water consump-




tion can be expected in the plants unless temperature control is very tight,




which it is generally not.  After comparing with published results we have




selected for saturation conditions 120F  (49 C) and 10 inches of water gauge,




so that the fuel gas is calculated to contain 0.13 moles water per mole of




dry gas.




     We next need to know the dry flue gas volume.  Assuming negligible




carbon monoxide and nitrogen oxides the dry flue gas volume is given by the




formula derived in Table 6-2.  As given there, the total moles of dry flue




gas per unit weight of  coal or char,  as fired,  are







      (4.76X1 + aXfj + |j) +  (3.76 + 4.76a)(| - |j) ,             (6.6)









where a, c, s, h and x are the weights of each element as defined in




Table 6-2 per unit weight of coal of char.   The water carried away by the gas which




was not in the gas before scrubbing,  that is, the makeup water requirement




for gas saturation at 120F and 10 inches of water then becomes in weight




per unit weight of coal or  char as fired  (Ib/lb coal or  char)







  (4.76) (0.13) (1 +a) (^- + ^-) (18) +  (0.13) (3.76 + 4.76a) (|- - ^-) (18) - w - -  .






                                                                  (6.7)





                                 121

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       Table 6-2.   Determination of total moles of dry flue gas
                   per unit weight of coal or char as  fired .

Basis:   Unit weight of coal or char containing:
Element
Carbon
Hydrogen
Oxygen
Sulfur-
Moisture
Wt.
c
h
x
s
w
Formula
C
H2
2
S
H 0
Moles
c/12
h/2
x/32
s/32
w/18
The fraction excess air is a.
Flue gas component
Carbon dioxide, CO,
             Moles in dry gas
                                          12
Moles Cu required
                                                 c
                                                 12
Water, HO
Sulfur dioxide, SO,,
                                          32
                                               h   x_
                                               4 ~ 32

                                                 s
                                                 32
Oxygen, 0,
                                                      Total
             ,c    h   x    s
           a(12 + 4 ' 32 + 32*
                                                                12   4   32   32
Nitrogen, N,

              Total
4.76(1 + al(~ +  j)  + (3.76 + 4.76a)
                                 122

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      The excess air, a, varies from about 0.05 to 0.2 and will very seldom

be known exactly.  We take a = 0.15 recognizing that changes in this quantity

over the range indicated will generally not introduce an error into the results

of greater than 10%.  However, for very high moisture content coals such as

lignites, where w is large, the relative error could be somewhat larger because

the absolute makeup requirement is small.  Using the value of excess air noted,

Eq. (6.7) reduces to


            makeup water   10 0,c    s N  , 1A  _ ,h   x ,       h     /t 0\
            _____= 12.8(_ + _) + 10>5(____ ) _w_ _ .   (6>8)
      In Table 6-3 we have used  the above  formula to calculate the weight of makeup

water required per unit weight of  coal or  char as fired, for the coals and char

considered in the present study.   As already noted, the largest single factor

affecting the water requirement  is seen  to be the moisture content of the coal.

The quantities of flue gas desulfurization water leaving with the boiler flue

gases presented in Section 10 are  based  on the values shown in Table 6-3 multi-

plied by the- known coal or char  feed rates to the boilers.


         Table 6-3.  Element weights per unit weight of coal or char
                     and makeup  water requirements per unit weight of
                     coal or char  for coals and char of present study.


          Mine
        Location            c_       h_       _x       s_       w_   Ib water/lb coal

Beulah, N.D.               .404     .027     .119     .007     .360       .104

Gillette, Wyo.             .494     .034     .128     .003     .280       .291

Colstrip, Mont.            .506     .032     .098     .011     .247       .345

Kaiparowits, Utah          .616     .043     .109     .004     .148       .583

Navajo, N.M.               .473     .035     .096     .009     .124       .439

Rifle, Colo.               .710     .054     .076     .006     .064       .806

All sites, Synthane char   .636     .010     .014     .003       0       .700


                                    123

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 6.3  Water  in Waste Solids^


     As  Indicated by Eqs.  (6.3) and  (6.4)  there  are  two  major solids wastes,



 CaSO.,    W-O and CaSO,   2H20.  In  addition,  unreacted  limestone,  CaCO-j, and



 slaked lime, Ca(OH)2> are  also wasted.   The  amount of  water  leaving in the



 waste solids depends on  the quantity of  sulfur and the slurry concentration.



 In Table 6-4 is shown for  the two  major  products the weight  of solid per



 unit weight of sulfur and  the weight of  water per unit weight of  sulfur.
               Table 6-4.  Weight of CaSO^H^O and  CaS03-35H20,

                           and water of hydration per unit weight

                           of sulfur.
  Crystal Form               Ib solid/lb sulfur         Ib water/lb sulfur



  CaSO,  2H00                       5.38                       1.13
      4    i



  CaS03  ^0                       4.03                       0.28
     Assuming a given solids concentration in the waste slurry, the weight



of slurry water per unit weight of sulfur can be calculated.  In Table 6-5



the weight of the slurry water per unit weight of sulfur is shown for a



40 wt.% solids concentration, which represents a well dewatered waste obtained



by gravity thickening.  Vacuum filtration could increase the percent solids to



60% and vacuum filtration plus centrifugation could raise this figure to



70% .   However, these mechanical dewatering techniques would only be prac-



ticed if transport of the sludge to distant landfill were envisaged, which



is not the case for the Western sites considered in this study.
                                  124

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         Table  6-5.  Weight  of  slurry water per unit weight of
                     sulfur  for a 40 wt.% solids  concentration.
            Crystal  Form           lb slurry water/lb  sulfur

            CaS04  2H20                      8.07


            CaS03 - hK2Q                      6.05
     In Tables 6-6a and 6-6b we have given the compositions in weight fractions.

of lime and limestone scrubber sludges as reported in Ref. 1.  In Ref. 1 the

calcium sulfite was assumed to be in the crystalline form CaSO..  2H?0.  It is

now generally agreed that the form in the sludges is CaSO-  JjELO.  We have

therefore corrected the weight fractions.given in Ref. 1 to the values

shown in Table 6-6.which correspond to the accepted crystalline form of

calcium sulfite.  Also shown in these tables are the corresponding weight

fractions of sulfur and water of hydration, calculated using the values given

in Table 6-4.  All values in Tables 6-6 are stated as pounds of solids, with

one pound of sludge solids as the basis, rather than as weight fractions.
       Table 6-6a.  Weight of components of lime sludge  (dry) and
                    corresponding weights of sulfur and water of hydration,
    Component              lb  solid       lb  sulfur      lb water

    CaC03

    CaS03   ^O

    CaSO,   2H 0

    Ca(OH)2

             Total         1.000           .194           .074
.058
.690
.126
.126
0
.171
.023
0
0
.048
.026
0
                                  125

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.367
.533
.100
0
0
.132
.019
0
0
.037
.021
0
     Table 6-6b.   Weight  of  components of limestone sludge (dry)  and
                  corresponding weights of sulfur and water of hydration.
  Component                Ib  solid      Ib sulfur      Ib water

  CaC03

  CaS03 >  sH20

  CaS04   2H20

  Ca(OH)2

          Total             1.000           .151            .058




     From the data of Tables  6-6 we have  calculated  the weight  of solids

and of the water of hydration per  unit weight of  sulfur for  the lime and

limestone processes.  These figures are given in  Table 6-7.
         Table 6-7.  Weight of solids and water of hydration per
                     unit weight of sulfur in lime and' limestone sludges,
    Process          Ib solid/lb sulfur         Ib water/Ib sulfur

    Lime                     5.2                        0.38

    Limestone                6.6                        0.38




     Table 6-7 shows that the unit weights of solids are reasonably close

and that we may with little error take the average of the two values as

representative of any wet lime, limestone or lime-limestone scrubbing

process, that is, 5.9 Ib solid/lb sulfur.  It is also clear from the. table

that the water of hydration can represent only a very small fraction of the

total makeup water (slurry water plus water of hydration) so that we will
                                  126

-------
neglect this  contribution  and assume  that  the makeup water equals the slurry


water.  In this  case we may write
          Ib makeup water  _  ,.  Q ,1  -

                                    m
Ib sulfur      ~ 5'9(T)                         (6-9)
where m is the weight  fraction of  solids  in  the waste  (i.e., weight of


solids divided by  the  weight  of water plus solids).  Note that a change to


30% solids from 40% solids makes a 50%  increase in the water in the waste,


since (1 - m)/m changes from  1.5 to 2.3.  A  change to 50% solids makes


(1 - m)/m equal to 1 and  decreases the  water in the waste by 33%.


     In Table 6-8  we have tabulated for the  coals and char of Table 6-3 the


slurry makeup water for m = 0.4,along with the total makeup water for the


waste disposal including  the  flue  gas. water.  It should be noted here, that


though the quantity of slurry makeup water is strongly affected by any change


in solids fraction this change has much less of an effect on the total quantity


of water makeup.   It can  be seen from Table  6-8 that with a solids fraction


even as high as 0.4, the  water in  the waste  is only important with the higher


sulfur coals.  Again the  exception to this is the wet lignite (Beulah, N.D.)


where the flue gas water  makeup is so small  that even the small amount of


slurry makeup represents  a sizeable fraction of the total.



6.4  Comparison of Present Approach


     There is little reported data with which to directly compare the estimates


provided by the present approximate formulation for the coals examined.  One

                                                                   2
engineering design estimate has been given for the Kaiparowits coal .   The


wet lime flue gas  desulfurization  design was made for a nominal 3,000 MWe plant,


and the estimates  made in Ref. 2 are compared below in Table 6-9 with our


approximate estimates  derived from Eqs.(6.8) and (6.9) with m = 0.4.


                                  127

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       Table 6-8.  Weight of sulfur and makeup water requirements
                   per unit weight of coal for coals of present
                   study and with 40 wt.% solids in slurry.
              Mine                              Ib water/lb coal
            Location                         in solids      total

         Colstrip, Mont.              .0109      .097          .442

         Navajo, N.M.                 .0091      .081          .520

         Beulah, N.D.                 .0070      .062          .166

         Rifle, Colo.                 .0056      .050          .856

         Kaiparowits, Utah            .0042      .037          .620

         Gillette, Wyo.               .0032      .028          .319

         All sites, Synthane char     .0026      .023          .723
      Table 6-9.  Comparison of flue gas desulfurization makeup
                  water requirements for Kaiparowits coal from
                  design estimates of Ref.  2 and present approximate
                  formulation.

                                       Ib water/lb coal
      Estimate               in solids     in flue gas      total
                   2
   Impact statement             .031           .514           .545

   Present.calculation          .037           .583           .620
     The agreement as shown in Table 6-9 between the estimates is seen to

be quite good, although our result is somewhat higher  than that from the

impact statement.  A similar conclusion is borne out by a comparison with

experimental results for other coals.  It should be noted that had the

present solids calculation been based on our wet lime result of 5.2 Ibs of

solids per Ib of sulfur, rather than the lime-limestone average of 5.9,

the water in the solids would have been .033 instead of .037.   In summary,

                                  128

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it is felt that our approach is sufficiently accurate for the present

purposes and gives a conservative picture of the water requirements.


References
1.  Cooper, H.B., "The Ultimate Disposal of Ash and Other Solids from
    Electric Power Generation," in Water Management by the Electric Power
    Industry  (E.F. Gloyna, H.H. Woodson and H.R. Drew, editors),
    pp. 183-195, Center for Research in Water Resources, The University
    of Texas at Austin, 1975.

2.  Bureau of Land Management, "Final Environmental Impact Statement
    Proposed Kaiparowits Project," Vol. I, pp. 1-89, 105, FES 76-12,
    March 3, 1976.
                                  129

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                              7.  MINING

7.1  Categories
     In the sections that follow we present the general methodology for
calculating the amount of water consumed in the mining of coal or shale and
in any subsequent land reclamation which may be required.  The water quantities
for this category of usage generally will not be too strongly affected by
the conversion process, except as it determines the actual quantity of material
to be mined.  However, the mine location and whether the mining is surface
or underground will be strong determinants of the quantity of water consumed.
     We list below the principal categories of consumed water applicable to
coal or shale mining:
                     Road, Mine and Embankment Dust Control
                     Handling and Crushing Dust Control
                     Service and Fire Water
                     Sanitary and Potable Water
                     Revegetation
                     Coal Washing

In the following sections we will discuss separately each of these cate-
gories.  When water is limited, its use or loss prevention becomes a matter
of economic tradeoff.  The water quantities we will present will be characterized
as reasonable bounds for best available technology, with no  effort to carry
out detailed cost estimating of the type done for cooling towers.

7.2  Coal and Shale Mining Rates
     Before estimating the water quantities associated with the mining
operations it is necessary to know the rate at which the coal is mined to feed
the unit size plants examined in this study.   Here it is important to recognize
                                  130

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that the tonnage mined  is not necessarily that which enters the process.


For example, coal which is mined  underground must be washed and approximately


25% is disposed of as refuse.  In the Lurgi process the gasifier cannot accept


coal fine's, although the boilers  can, the result being that about 10% of the


mined coal is sold off  as fines.


     Basically the quantity of coal required is determined by the heat input


rate for the size plant considered and the heating value of the fuel.  For


a Lurgi 250 x 10  scf per stream  day plant the process needs from Section 2.4

             9                                                 9
are 17.7 x 10  Btu/hr,  and the mine requirements are 19.67 x 10  Btu/hr as


detailed in Table 7.1.   From Section 2.5,the Synthane requirement is

         Q
17.1 x 10  Btu/hr, to which we add about 0.35% of additional heat input to

                                                     9
cover undefined losses,for a total input of 17.7 x 10  Btu/hr.
            Table 7-1.  Process heat requirements for
                        250 x 10 scf/stream day Lurgi plant,
                                           109 Btu/hr

               Gasifier                       14.6

               Boilers                         2.6

                           Subtotal           17.2

               Undefined losses  (0.3%)         0.5

                           Total to process   17.7

               Fines (10% mined coal)          1.97

                           Total from mine    19.67
Finally a 3,000 MWe plant at full load and 35% efficiency requires a heat

                  Q
input of 29.3 x 10  Btu/hr.  All of those requirements are summarized in


Table 7-2, where if no distinction is made between process and mine, the
                                 131

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requirements are the same.  Knowing the higher heating value of the coal

(see Appendix A) it is then a simple matter using the values in Table 7-2

to determine the daily tonnage requirements.
            Table 7-2.  Mine and process requirements for
                        coal conversion plants.



                                  10   Btu per  10 1 Btu per
     Process      Nominal Output   stream day   calendar day  Factor

Lurgi
250 x 106 scf/day
.e 4.72
cess 4.25
,ane 250 x 106 scf/day 4.25
ioil 100,000 bbl/day 8.38

4.25
3.82
3.82
7.54

0.9
0.9
0.9
0.9
Steam-Electric    3,000 MWe

  Under. Mine                         9.36         6.55         0.7

  Surf. Mine &
    Process                           7.02         4.91         0.7




     In the case of shale requirements, we must refer specifically to the

process and the kerogen content of the shale.  From Section 3.2 we note that

for 35 gallon/ton shale that 66,000 tons per stream day (59,400 tons per

calendar day) are required for the TOSCO II process.  The tonnage require-

ments will vary essentially in direct proportion to the shale kerogen content.

The coal slurry pipeline requirements are defined by the transport requirement

of 25 x 10  tons/year or 68,493 tons/calendar day.  Of course, were ash

removal practiced prior to transport then the quantity mined would differ

from that transported.  This, however, is not the case for present study in

which it is Gillette coal to be piped  (see Section 5).


                                 132

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     Tables 7-3a and 7-3b summarize the coal and shale daily tonnage require-

ments derived, where appropriate, from Table 7-2 and the coal heating value.
          Table 7-3a.  Coal tonnage requirements for unit size
                       plants in tons per calendar day.
     Lurgi

       Mine

       Process

     Synthane

     Synthoil

     3,000 MWe

     Slurry  Pipeline
                       Beulah
Colstrip
Gillette
Navaj o
31,135
28,021
28,021
55,251
36,018
-
24,666
22,200
22,200
43,772
28,535
-
25,139
22,625
22,625
44,611
29,082
68,493
25,560
23,004
23,004
45,358
29,569
-
            Table 7-3b.   Coal and shale tonnage requirements
                         for unit size plants  in tons  per
                         calendar day.
         3,000 MWe

           Mine

           Process

         1,000 MWe

         Oil Shale (50,000 bbl/day)
  Kaiparowits



     30,335

     22,751
                                                          Rifle-
                      6,296

                     59,400
                                  133

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7.3  Road, Mine and Embankment Dust Control
     In estimating the water requirements for this category of dust control we
must distinguish between surface and underground mines.  Let us first consider
surface mines which cover the majority of situations of interest in the present
study.  The dust control we speak of here is primarily the fugitive dust generated
on haul roads and unpaved areas in the neighborhood of the mine such as the
mine benches and overburden placement areas.  To a large extent, the length of
unpaved haul roads and mine bench areas will depend on the mine productivity,
as measured by the amount of coal recoverable per unit area of stripped land.
In Table 7-4 we have shown the coal yields per acre for the 5 sites considered
in the present study where  the coal will be strip-mined.  The value at Gillette
was arrived at by averaging the 92,000 ton/acre figure derivable from Ref.  1 and
the 88,000 ton/acre figure derivable from the information in Ref.  2.  The value
for Beulah was derived from the data of Ref. 3,  while that for Farmington was
obtained from Ref.  4.   In a book prepared by the National Academy of Sciences ,
coal yield figures are given for all of the areas considered.  However, these
values appear on average to be about a factor of 1.8 lower than those values ob-
tained from the various environmental impact statements.   We have therefore used
the figures from Ref.  5 multiplied by a factor of 1.8 to derive the values  for
Colstrip and Rifle,  for which detailed statements were not available.


                   Table 7-4.   Coal yields per acre.
                 Mine Location              tons/acre
                 Beulah                      25,000
                 Colstrip                    40,000
                 Gillette                    90,000
                 Navajo                      37,000
                 Rifle                       23,000

                                 134

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     In our assumed mine model we have estimated that the mining of 100 acres per
year would require 2 miles of 45 ft wide unpaved haul roads to serve as spurs
to conveyor belts that would feed the coal to the plant.  Such a belt line
operation may be found described in Ref. 1.  In addition, we assume the bench
area acreage that would have to be wet down to be approximately equal to 4 times
the daily acreage that is mined.  The sum of the two unpaved areas determines
the area on which dust control must be practiced.
     The simplest means of holding down fugitive dust is to wet down the mine
area and haul roads.  We assume as a conservative estimate that the roads and
mine area can be kept in a wetted condition through an annual deposition of
water equal to  the net annual evaporation rate.  Any rainfall is taken to be
an additional safety factor, and is not subtracted from the amount of water
to be laid down, because how much of it is actually absorbed and how much runs
off is variable.  The annual pond evaporation rates for the areas examined are
shown in Table  7-5  (see Appendix B).


              Table 7-5.  Annual pond evaporation rates.

                 Location                   inches/year
                 Beulah                          45
                 Colstrip                        49
                 Gillette                        54
                 Navajo                          61
                 Rifle                           45


     We  can now calculate the lay down rate from the relation

           lay  down rate =  disturbed area  x evaporation rate.            (7.1)
                                   135

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                                      f\
For our assumed mine model, 522,937 ft  must be wetted down per 100 acres/year


disturbed.  In Table 7-6 is shown the acreage it would be necessary to strip


mine yearly for the processes and sites considered.  Using these average


figures and the evaporation rates given in Table 7-5 we have calculated the


required lay down water from Eq. (7.1).  It is this quantity which is listed


in the tables of Section 10 as the "Road, Mine, Embankment Dust Control" water.


The exceptions to this are the Kaiparowits coal mines and the Rifle oil shale


mines, both of which are underground mines.  The dust control requirements for


these mines are very different from a surface mine.  Moreover,, we would note


that the actual acreage disturbed per year by an underground mine is relatively


small.
                                                              *
      Table 7-6.  Area strip mined annually in acres per year.
                Beulah       Colstrip        Gillette        Nava j o
Lurgi
Synthane
Synthoil
3,000 We
454
409
806
526
225
203
400
261
102
92
181
118
252
227
448
292
*  102 acres/yr for 1,000 MWe plant at Rifle and 278 acres/yr
   for slurry pipeline at Gillette.
     In Ref.  6 the shale mine dust suppression water consumed is given as 350 gal


per stream minute.  The mining technique projected is underground room and


pillar mining.  This is one of the methods envisaged in Ref. 7 for underground


coal mining at Kaiparowits.  On the basis of 66,000 tons per stream day of


shale mined,  this amounts to 1 lb^ of water for every 31 Ibs of as-mined shale.


On the basis of other estimates for mine dust suppression water, this value


                                   136

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seems quite reasonable and we have used it to calculate the mine dust control




water for oil shale mining.




     Somewhat less reasonable is the net consumed water for mine dust sup-




pression indicated in Ref. 7 for Kaiparowits.  On the basis of a net consumption




of 621 gallons per calendar minute and a mining of 32,973 tons of coal per calen-




dar day a usage  is indicated of 1 Ib of water for each 9 Ibs of as-mined coal.




If we assume this to include water for crusher  dust suppression, which




generally takes  place at  the mine mouth, then we may compare this with 1 Ib




of water for each 19 Ibs  of as-mined shale  .  The value of water usage indicated




for Kaiparowits  appears to be quite high and we have chosen to use a combined




value for mining and crushing at Kaiparowits which is about 50%. larger than that for




the shale  case or 1 Ib  of water for every 13 Ibs of as-mined coal.  The values




of  mine water consumption listed  in the Rifle shale tables and Kaiparowits




coal  table  are based on the usages indicated and the tonnages given in Table  7-3b.






7.4   Handling  and  Crushing Dust Control




      We consider the water needs  associated with the preparation of the coal




or shale as part of  the estimate  of  the water  requirements  for  a mining opera-




tion  integrated  with  a synthetic  fuel  plant or a steam-electric power plant.




In all  coal preparation plants  dust  is generated in  the  stages  of  loading  and




unloading,  breaking,  conveying,  crushing,  general  screening and storage.   The




water required to hold down this  dust  will  be  considered here.   Coal washing




will be treated separately in Section  7.9,  because of  the specialized nature




 of the process and because of the high consumptions  involved.




      The ways of preventing  dust  from becoming airborne  are through  the  appli-




 cation of water sprays, the  application of  non-toxic chemicals, the  use  of dry




 or wet dust collectors and the use of  either partial or  total enclosure.   We







                                  137

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shall assume that the principal dust generating  sources will be enclosed  and


that where feasible air will be circulated and dry bag dust collection employed.


Whenever coal pulverization is necessary we  consider, as is normally  the


case, that this will be done under conditions of  total enclosure with no


fugitive dust or hold-down water requirements.  We have seen in Section 5  that


water is added in the milling of coal for slurrification, however, this is


a requirement related to the slurrification  itself.  In inactive storage  the


use of water for holding down dust can be minimized by the use of non-toxic


chemicals.


     Despite the design precautions indicated, in large scale plants with


many transfer points, tranfer belts, surge bins, storage silos and active


storage sites it is necessary to employ water sprays to wet down the coal or


shale.  This is also generally necessary with breaking and primary crushing

                                                           4
operations.  An examination of the Wesco Lurgi plant design  and the TOSCO

                      c.
oil shale plant design  indicate that a consumptive use of 1 Ib of water for


every 50 Ibs of coal handled and crushed is a reasonably conservative estimate.


This estimate is essentially in agreement with the value derived from Ref. 6.


Using the tonnage figures of Tables 7-3 leads to the rates of water consumption


for handling and crushing given in the tables of Section 10.



7.5  Mine Personnel


     A number of water requirements in the mine are a direct  function of the


number of people employed in the mine.   One such obvious requirement is water


for sanitary needs and potable usage.   Of course, the number  of personnel is


related to the tonnage mined but the number will also depend  on the mine type


and location.
                                 138

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     In Ref. 8 estimates are given of the number of personnel needed in



model mines to strip 5 x 10  tons of coal per year.  The locations considered,



that are relevant for this study, are the Southwest, Montana, Wyoming and



North Dakota.  We have scaled up on a tonnage output basis, the number of



personnel recommended for these model mines to the outputs of Lurgi plant

                          i              f\               i

mines proposed for Wyoming , North Dakota  and New Mexico  , as well as to a


                                              2
straight mining facility proposed for Gillette .  The numbers of mining



personnel recommended by the mining companies in the environmental impact



statements were compared with those from the scaleup.  In all cases the



recommended numbers of mine personnel were remarkably close to 50% more than



those derived from the model mines data.  In this study we have used the



data of Ref. 8 to compute the number of mine personnel.  However, we have



increased the requirements by 1.5 on the basis of the impact statements and



on  the assumption that a certain number of additional personnel will be



required for the preparation facilities associated with the conversion plants.



     In the absence of equivalent data on mine  personnel  for underground



shale mining in Rifle and underground coal mining in Kaiparowits, we have



found it necessary to rely on the figures given in Refs. 6 and 7.  For the



Kaiparowits case, the number of personnel was scaled downward from that given



in  Ref. 7 in proportion to the difference in tonnage outputs from the respec-



tive mines.



     Tables  7-7 summarize the mine personnel requirements  for the units of



the present  study.
                                139

-------
           Table 7-7a.  Number of mine personnel for specific
                        mines integrated with coal conversion
                            plants and a slurry pipeline.
   Process


Lurgi


Synthane

Synthoil
  Nominal Output   Beulah   Colstrip   Gillette   Navaj o
250 x 106 scf/day   305
250 x 10  scf/day   275
 100,000 bbl/day    540
Steam-Electric    3,000 MWe


Slurry Pipeline 25 x 10  tons/yr
                    350
255


230


455


295
260


235


465


300


715
345

310


610


400
    Table 7-7b.  Number of mine personnel for an underground
               and surface mine integrated with a steam-electric
             plant and for an underground oil shale mine integrated
                            with a shale oil plant .
   Process


Steam-Electric


Steam-Electric


Oil Shale
          Nominal Output


             3,000 MWe


             1,000 MWe


          50,000 bbl/day
     Kaiparowits


        2,360
              Rifle
                          85

                         400
                                 140

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7.6  Sanitary and Potable Water

     Sanitary and potable water usage is directly proportional to the number

of personnel.  Our estimated usage figures per man-shift are given in Table 7-8.

The higher usage figure is for those areas with the higher rates of evaporation

minus precipitation.



           Table 7-8.  Sanitary and potable water usage per
                      man-shift and percent of usage consumed.


                                      Usage                      Consumed
         Location                 (gal/man-shlft)               (% of usage)

Beulah, Colstrip, Gillette              30                          25


Kaiparowits, Navajo, Rifle              35                          30



     In our  calculations we have  assumed 5 shifts per week per man.  The

usage of water in gallons per calendar minute is therefore given by the relation


      gallons usage   5    1 day        gal           f                /7 o\
      a=	:	r* = T x , . . ^ . x 	g , . ,'  x no. of men            (./ .2.)
      calendar min    7   1440 mm   man-shift


No account has been taken of shortened shifts or vacation time so as to provide

a conservative estimate.

     The net consumption will be  quite different from the usage, since we

assume that  the  sanitary and potable water effluent will go through water

treatment in order that it may be reused within the plant.  In Table 7-8

we have given our estimates  of appropriate water consumptions as a percentage

of water usage.  Again a somewhat higher figure has been indicated for those

areas with higher rates of evaporation minus precipitation.
                                  141

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     Using the mine personnel data given in Tables 7-7, and the usage


figures in Table 7-8,  the water usages can be calculated from Eq. (7.2).


The results were always rounded to the nearest gallon per calendar minute.


The net consumptions were then obtained by multiplying these rounded usage


figures by the appropriate fraction given in Table 7-8.  The calculated net


consumptions were also rounded to the nearest gallon per calendar minute,


and it is those figures which are given in the tables of Section 10 under


the headings of "Sanitary & Potable Water."


     We have calculated the quantities of sludge that would be generated in


the recovery of the sanitary and potable waters, even though the quantities


themselves are not large.  A standard figure for suspended solids in sewage

                                                             9
is 0.25 lb/(person)(day) for a usage of 100 gal/(person)(day) .  For our


assumed usage of 30 gal/man-shift this would correspond to a suspended solids


of .075 Ib/man-shift.   Under the assumption that the sludge from the water


treatment plant is dewatered to 80% water,this would mean a generation of


0.375 lb wet sludge per man-shift.  Taking, as before, 5 shifts per week


per man we find that 0-_27_ lb wet sludge is generated per man per calendar day.


This same figure was used for the 35 gal/man-shift consumption, since the


higher usage is associated with greater net evaporation rather than increased


suspended solids per man.  The wet solid figures for mine sanitary and potable


water in the tables of Section 10 were calculated using the preceding wet


sludge figure and the mine personnel of Tables 7-7.
                                  142

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7.7  Service and Fire Water




     The service water usage in the mine such as for equipment washing,




maintenance, pump seals, etc., along with the fire water usage through




evaporation loss is a difficult quantity to estimate.  However, an analysis




of a number of mine designs indicates that this usage, which is essentially




non-recoverable, can be related to the usage (not consumption) of sanitary




and potable water.




     The estimated ratio for service to sanitary usage for a proposed




10 x 10  ton/yr surface mine near Gillette is about 1.6  .  This same figure




for the proposed Kaiparowits underground mine  is about 1.3, based on our




estimated sanitary water usage.  We have used our estimate of sanitary water




usage, since Ref. 10 is in agreement with our estimate for their case, so




that by so doing this enables us to provide the same relative comparison




for the two sites.  The two values are sufficiently close that we have taken




their average and assumed that the service water usage for the mine is 1.5 times




the sanitary water usage.   Moreover, all of the water is taken to be consumed




since recovery in the mine work areas would prove quite difficult.  The values




of fire and service water shown in the Tables of Section 10 were calculated using




the sanitary water usages developed in the preceding section (but not tabulated).






7.8  Revegetation




     As part of any reclamation of mined land in arid and semi-arid regions,




there exists a potential requirement for supplemental irrigation water asso-




ciated with the establishment of soil stabilizing plant cover on mine spoils.




In Ref.  5 (p. 168) 'it is concluded that coal mined areas with greater than




10 inches of mean precipitation annually can be reclaimed without supplemental




irrigation.  Where there is less than 10 inches of annual rainfall, partially
                                 143

-------
reshaped coal mine spoils can be successfully revegetated with supplemental



irrigation of about 10 inches during the first growing season, with no



further requirement during subsequent growing seasons  .  The establishment



of plant growth on spent oil shale piles requires considerably more supple-



mental irrigation and this will be considered separately.



     From the precipitation data given in Appendix B,it can be seen that of



the sites considered the only ones with less than 10 inches of annual rainfall



are Navajo and Kaiparowits.  Strip mining is proposed only for the Navajo site



so that it is only there that significant irrigation water is needed.  However,



some spoil revegetation will be necessary in Kaiparowits on the coarse



waste piles.



     The areas to be revegetated annually at the Navajo site correspond to



the mining area rates listed in Table 7-6.  In the proposed Kaiparowits



design of Ref. 7  (p. 1-196), which we here follow, it is estimated that the



coarse waste dump would occupy an area of 550 acres over the 35 year life



of the plant.  Multiplying the average annual acreage, rate by the ratio of



the total refuse  rate in our design  (7,584 tpd, Table 7-36) to that in the



design of Ref. 7  (8,219 tpd) gives an annual coarse waste spoil area of



14.5 acres/yr.



     With the area to be revegetated annually known, the supplemental irriga-



tion water expressed in gallons per  calendar minute can be calculated from



the relation



                                                   n


     Irr. waterC-fHr-)-  - Area &&) * 43,560 1L.  x 10 in x 1"  x 62.4
                cal.min           yr            acre           I/ in





                                                        1 yr       1  day
                                           8.33  Ibs    365  days    1440 min
                                        , acres v                          ._, ,
                            0.517 x Area(  )                          (7.3)




                                   144

-------
The "Revegetation" water requirements given in the Tables of Section 10 for



Navajo and Kaiparowits were obtained from the above relation and the



acreage rates noted.



     We have based the irrigation requirements for spent shale pile revegation



on an annual spoil area of 11.5 acres/yr for a 50,000 bbl/day plant, which is



the estimated acreage requiring reclamation during the first ten years of



operation .  After this period the annual acreage rate would rise.  Estimates



for the necessary irrigation water indicate that about 1 ft of water is



required initially to leach out the salinity, and then an additional 1 ft/yr

                     fi 10
for from 2 to 5 years '     On a continuous annual basis we shall therefore



consider a one time requirement of 6 ft of water.  This is undoubtedly a



conservative estimate.  Replacing 10 inches by 6 ft in Eq. (7.3) we have
         Shale  Irr. Water(  fal 4 ) = 3.72 x Area(^~)                (7'4)
                       -   cal. min'                yf.





For a 50,000 bbl/day oil shale plant, this gives an average consumption of



43 gallons per  calendar minute.





7.9  Coal Washing



     Often times it may be desirable or necessary to upgrade run-of-mine



coal by reducing the ash and  sulfur levels through washing of  the  coal.  For



all of the surface mined coal at the sites studied this  is not considered



necessary.  However, when coal is  mined underground, as  at Kaiparowits, coal



washing is normally employed  and we shall take this to be the  case.  The



details of washeries can vary significantly, however, our estimate of water



consumption will be a  generalized  one based  on the quantities  of solids handled



and disposed,  rather than on  any specific design.
                                  145

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     From Ref. 7 we find that for the Kaiparowits coal, about 53% of the



refuse is coarse and the remainder is fine waste which ends up in the tailing



ponds.  It is the coarse reject for which the revegetation water requirement



was calculated in the preceding section.  The coarse reject amounts to 4,020 tons



per  calendar day.  Little water is added to the coarse reject, generally



not more than 10 wt. %, and this primarily to aid in dust control and the



subsequent compaction.  On the basis of 10 wt. % of water this amounts to



75 gallons/calendar minute.



     The fine refuse leaving the washery amounts to 3,564 tons/calendar day.



Consistent with our assumption throughout this study, we take the waste to be



a well dewatered one of 40 wt. % solids.  This concentration is somewhat



higher than the more usual 30 to 35% but can be obtained without excessive


          13
difficulty  .  Based on our assumed solids concentration, water enters the


                                                         t-

tailings pond at a rate of 1,005 gal/calendar min.  We follow the design of



Ref. 7 and take 58% of this water to be lost, so tha't the net consumption is



583 gal/calendar min.  This is consistent with a reasonably designed tailings



and clear waste overflow pond (Ref. 13, Chapter 17).  Of the water lost,about



80% or 466 gal/calendar min is retained in the pond and  the remaining 20% is



evaporated.  We have sized a tailings and clear water overflow pond and



calculated the evaporation rate.  V!e find the rate to be approximately con-



sistent with that given in Ref.  7, where a 3 year filling is assumed.  The



evaporation rate  could be reduced by assuming a 2 year filling, but we have



chosen to use the figures given  as conservative estimates.
                                 146

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 References


 1.   Wyoming Coal Gas Co. and Rochelle Coal Co., "Applicant's Environmental
      Assessment for a Proposed Gasification Project in Campbell and Converse
      Counties, Wyoming," Prepared by SERNCO, October, 1974.

 2.   Geological Survey, "Proposed Plan of Mining and Reclamation - Cordero
      Mine, Sun Oil Co., Coal Lease W-8385, Campbell County, Wyoming," Final
      Environmental Statement No. 76-22, U.S. Dept. of the Interior,
      April 30, 1976.

 3.   North Dakota Gasification Project for ANG Coal Gasification Co.,
      "Environmental Impact Report in Connection with Joint Application of
      Michigan Wisconsin Pipe Line Co. and ANG Coal Gasification Co. for a
      Certificate of Public Convenience and Necessity, Woodward-Clyde
      Consultants," Federal Power Commission Docket No. CP75-278, Vol. Ill,
      March 1975.

 4.   Batelle Columbus Laboratories, "Detailed Environmental Analysis Concerning
      a Proposed Gasification Plant for Transwestern Coal Gasification  Co.,
      Pacific Coal Gasification Co., Western Gasification and The Expansion
      of a Strip Mine Operation Near Burnham, New Mexico Owned and Operated
      by Utah International Inc.," Federal Power Commission, Feb. 1, 1973.

 5.   National Academy of Sciences, Rehabilitation Potential of Western Coal
      Lands, pp. 32, 33, Ballinger Publishing, Cambridge, Mass., 1974.

 6.   Colony Development Operation, "An Environmental Impact Analysis for a
      Shale Oil Complex at Parachute Creek, Colorado, Part 1 - Plant Complex
      and Service Corridor," Atlantic Richfield Co., Denver, Colorado, 1974.

 7.   Bureau of Land Management, "Final Environmental Impact Statement Proposed
      Kaiparowits Project," Chapter I, FES 76-12, U.S. Dept. of the Interior,
      March 3, 1976.

 8.   Bureau of Mines, "Cost Analyses of Model Mines for Strip Mining of Coal
      in the United States," Information Circular 8535, U.S. Dept.  of the
      Interior, 1972.

 9.   Metcalf & Eddy, Inc., Wastewater Engineering,  p. 581,  McGraw-Hill,
      New York, 1972.

10.   Atlantic Richfield Co.,  "Preliminary Environmental Impact Assessment for
      the Proposed Black Thunder Coal Mine, Campbell County, Wyoming," and
      "Revised Mining and Reclamation Plan  for the Proposed Black Thunder Coal
      Mine," 1974.   Also "Black Thunder Mine,  10 Million Ton Per Year Water
      Supply," (Personal Comnunication, Hugh W.  Evans), Denver, Colorado,
      March 6, 1975.
                                  147

-------
11.  Aldon, F. E., "Techniques for Establishing Native Plants on Coal Mine
     Spoils in New Mexico," in Proc.  Third Symposiumon Surface Mining and
     Reclamation, Vol.  I, pp. 21.28,  National Coal Association, Washington,  B.C.,
     1975.

12.  U.S. Dept. of the Interior, "Final Environmental Statement for the
     Prototype Oil Shale Leasing Program," Vol. I, U.S. Gov't. Printing
     Office, Washington, B.C., 1973.

13.  Leonard, J. W.,and Mitchell, D.  R., Coal Preparation, Chapter 12,
     Am. Inst. of Mining, Metallurgical and Petroleum Engineers, New York,
     1968.
                                  148

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         8,  EVAPORATION, SOLIDS DISPOSAL AND OTHER USES









8.1  Categories




     In this section we examine the water requirements associated with those




solids disposal problems not already considered.  We will also determine the




quantity of residuals to be disposed.  Of particular concern are the disposal




of bottom ash, fly ash and spent shale.  Among the other uses of plant water




not included in the process estimate but to be treated here are the water




needs for dust control, service requirements, and sanitary and potable con-




sumption.  Finally, since all the water which is used in the mine and plant




will generally have come from an onsite reservoir, and since it may have passed




through settling basins, it is also necessary to calculate the evaporation




losses from these holding areas.  These losses are chargeable to the water




requirements for the mine-plant complex.






8-2  Bottom Ash and Spent Shale Disposal




     Ash will enter a furnace or gasifier in the coal or char.  Some of it




will leave as hot ash or slag from the bottom of the unit, and the remainder




will leave as fly ash in the flue gases.  The specific gasifier or furnace




defines the temperature at which the hot bottom ash or slag is removed.




This temperature is important to water consumption since the ash or slag is




generally cooled down by quenching with water before disposal, mainly for




reasons of safety.  We will take the ash to be quenched down to a temperature




somewhat below the boiling point of water, say around 200 F.  In Table 8-1




we have listed our estimates of the temperature at which the bottom ash will




be removed from the various processes or units.  Also listed are the ash




temperature drops on quenching (AT).
                                 149

-------
         Table 8-1.  Temperature of bottom  ash  on removal

                     and ash  temperature  drop on quenching.
                                   Ash  Removal           Ash  Temperature

Process or Unit                   Temperature,F        Drop on  Quenching,F




Lurgi Gasifier                        1,000                      800



Dry-Ash Furnace                       1,200                    1,000



Synthane Furnace                      1,200                    1,000



Synthoil Hydrogen Unit                1,500                    1,300








     The rate at which water is evaporated in cooling down the  ash  can be



determined from the relation






  heat removed/time = specific heat x temperature drop x ash  quenched/time.


                                                                       (8.1)


Dividing the heat removal rate by the heat of vaporization (1,000 Btu/lb)



determines the evaporation rate.  Based on the analysis of bituminous ash



we have estimated the ash specific heat to be 0.2 Btu/(lb)( F).  In terms of



water evaporated we then rewrite  Eq,  (8.1) as






                    (  ?   : )  = 3.33 X 10   A -DULLUm rt.SU Vj
                     cal. mm                              day
    Water Evaporated (fal  .  )  = 3.33 x 10 5 x Bottom Ash Or255-) x AT(F).
                     pal. min                              U3V
                                                                       (8.2)




     In addition to the water evaporated, a certain amount of excess water



must be added to the ash both for handling and ease of disposal.  The  weight



of water remaining in the quenched ash is taken to be 30% of the ash weight



(23 wt. %).  An expression for the amount of this remaining water is. given by




                        /  gal  _x        Ibs water              /tons.
  Water in Quenched Ash V~[~-~)  = 0.3  ib ash ~ x Bottom  '   	
                                         x 2000 i^s x . 1 gal   x _l_..day _

                                                ton   8.33 Ibs   1440 min
                                   = 5 x 10~2 x Bottom Ash(-)  -     (8.3) .
                                                           day
                                   150

-------
     The two streams defined by Eqs.  (8.2) and  (8.3) are seen to be of the


same order and the sum of them specifies the net water requirement for the


bottom ash disposal.  The water requirement is  directly proportional to the


ash removal rate which must be known.


     To determine the bottom ash removal rate it is first necessary to


calculate the total ash that will be  removed.   This quantity is simply the


product of the percent ash, as defined for each coal in Appendix A, multiplied


by the rate of coal input to the processes, as  given in Tables 7-3.  In the


present study we have assumed the use of pulverized coal fired dry-ash furnaces,


in which normally about 20% of the ash leaves as bottom ash and the remaining

                     2
80% leaves as fly ash .  The exception to this  rule in the present study is


when Navajo coal is used.  In that case, Ref. 3 indicates that about 25% of the


ash leaves as bottom ash with 75% leaving as fly ash.  This may be a consequence


of the high ash content of this particular coal.  In the Synthane process the


same breakdown is assumed, with the ash entering the furnaces in the char,


which is recovered from the gasifier, rather than directly with the coal.


In the Lurgi process, according to Table 7-1 the fraction of the process coal


which is fed directly to the boilers  is 2.6/7.9 or 15.1%.  Of this fraction,


the same split is again taken between the bottom ash and fly ash, as defined


previously for the dry-ash furnaces.  The remainder of the process coal comes


out as bottom ash from the gasifier.  In the Synthoil process all of the ash


is assumed to come out as bottom ash  in the hydrogen plant.  In Table 8-2 we


have summarized the various ash quantities calculated on the basis of the rules


just given.
                                   151

-------
Ul
N>
                               Table 8-2.   Ash  quantities in tons per day,
                    Steam-Electric  (.3,000 MWe)''
        *  Except Rifle which is 1,000 MWe
Synthane (250 x 10  scf/day)
Location
Beulah
Co Is trip
Gillette
Kaiparowits
Nava j o
Rifle*
Bottom
535
555
326
319
1893
76
Fly
2138
2222
1303
1274
5677
302
Total
2673
2777
1629
1593
7570
378
Bottom
416
432
253
-
1472

Fly
1663
1728
1014
-
4417

Total
2079
2160
1267
-
5889
	
                          Lurgi (250 x 10  scf/day)
   Synthoil  (ICO,OOP  bbl/day)

Location
Beulah
Colstrip
Gillette
Nava j o
Gasif ier
Bottom
1765
1833
1075
4999
Boiler
Bottom
63
65
38
223
Fly
251
262
154
667
Total
2079
2160
1267
5889
Bottom
4100
4259
2498
11100
Fl Total
4100
4259
2498
11100

-------
     From Eqs. (8.2) and  (8.3) and the data in Tables 8-1 and 8-2, we have




evaluated the bottom ash water consumption quantities and solids disposal




quantities given in the Tables of Section 10.




     In Section 3.3 we have already discussed the spent shale disposal




problem.  Both the quantity of shale and shale moisturizing water were




given in Fig. 3-1 and Table 3-1 for a 50,000 bbl/stream day output.  It is




these quantities, corrected for a 90% load factor, which are listed in the




oil shale tables of Section 10.






8.3  Fly Ash and Shale Dust Disposal




     In the present study we assume that dry electrostatic preclpitators




are used to remove the coal fly ash from the flue gas.  In these precipitators




the collected ash is discharged into storage hoppers by rapping.  The removal




process itself is dry but when the ash is withdrawn from the storage hoppers




or silos this is usually done by screw conveyors, with the ash wet down by




water sprays to prevent dusting and to make the handling easier.  The water




sprayed on the ash would normally be about 25% by weight of the ash, that is,




20 wt. % of the mixture.  We have used this figure to determine the quantity




of water leaving with the fly ash, the amount of fly ash itself having already




been specified in Table 8-2.




     A fine particulate removal process is also necessary in the TOSCO shale




oil retorting, where shale dust must be removed from flue gases prior to their




discharge into the atmosphere.  In the TOSCO process wet venturi scrubbers




are specified.  Since this is part of the process design we must accept the




penalties in water consumption inherent in these scrubbers.  We would only




note that the water which does leave with the scrubbed shale dust is mixed
                                  153

-------
with the moisturized spent shale.  The scrubber sludge water therefore serves




as part of the needed moisturizing water and, moreover, as we already discussed




in Section 3.3, it then becomes permanently cemented into the spent shale




and does not present a leaching problem.  The quantities of water and sludge




have already been given for a 50,000 bbl/day plant in the footnote of Table 3-1.




The quantities listed in the shale tables of Section 10 have been appropriately




corrected for the 90% load factor.






8.4  Plant Dust Control




     Within the boundaries of any of the plants considered in the present




study water will be needed for dust control at a certain number of points.




These points are similar to those described for the mines in Section 7.4,




namely transfer areas, active storage, surge bins, etc.




     We may expect that somewhat less water would be required in the plants




than in the mines, since many of the operations tend to be enclosed.  On this




basis we have assumed a consumptive use of one-third that applicable to the




mine areas, specifically 1 Ib of water for every 150 Ibs of coal handled and




transferred.  We have compared this estimate with that deduced from the data




of Ref. 4 and find it to be about one-half of the estimated value used there.




The value noted has been used for all plants except the slurry pipeline and




the oil shale plants, where we have used half the water, that is, 1 Ib of




water for every 300 Ibs of coal or shale handled.  This is because in-the shale




plants part of the dust control water has already been accounted for in the




usage calculated in Section 7.4.  In the case of the slurry pipeline, the coal




is normally wet during much of the processing so that we can expect less dust




control water to be needed.
                                  154

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8-5  Plant Personnel




     In the plant, as in the mine  (see Section 7.5), a certain number of




water requirements depend directly on the number of people employed.  Determining




these numbers is difficult and we have relied upon the estimates of the com-




panies proposing to set up plants.  In the cases where there are no estimates




we have extrapolated from similar plants.  There is no reason to expect




significant variations in the numbers of people employed at a given type of




plant as a function of geographical location.  Clearly, the largest single




influencing factor is the plant output.




     In Table 8-3 we have listed the number of plant personnel, valid for all




of the plant-site combinations considered in this study.  The figure for




the 3,000 MWe steam-electric plant has essentially been taken from Ref. 4.




The number of people for the 1,000 MWe plant has been reduced in proportion but




with 10% more people to account for the inefficiency of a smaller scale.




The figure for the Lurgi plants represents a rounded average derived from




the estimates given in Refs. 3, 5 and 6.  We have used the same number of




personnel for the Synthane plants as for the Lurgi plants, since the output




and operations are similar.  The number of personnel for the 50,000 bbl/day




shale plant was taken directly from the estimates provided by the designers




For the 100,000 bbl/day plant this number was simply doubled, since the plant




is essentially constituted of two 50,000 bbl/day units with little economy




of scale.  The output from the Synthoil plant is the same as the larger oil




shale plant and many of the operations are similar to those carried out in. the




shale oil upgrading.  -However, the material tonnage which must be taken in and




handled is less than half that of the shale plant, the solids to be disposed of
                                   155

-------
are only a small fraction of the spent shale, and finally some economy of

scale is expected because of the unitary design.  An analysis of these

factors indicates that about 30% fewer personnel than in the larger shale plant

could be expected.



        Table 8-3.  Plant personnel at all sites.


     Plant                     Output                  Personnel

Lurgi & Synthane         250 x 106 scf/day                650

Synthoil                  100,000 bbl/day               1,150

Steam-Electric               3,000 MWe                    500
                             1,000 MWe                    185

Oil Shale                  50,000 bbl/day                 820
                          100,000 bbl/day               1,640
8-6  Plant Sanitary and Potable Water

     The calculation of the plant sanitary and potable water usage, cpnsump-

tion and solids residuals is exactly the same as for the mine.  It is described

completely in Section 7.6 and will not be repeated here.  The only information

needed is the number of plant personnel and that is given in the preceding

section in Table 8-3.


8.7  Plant Service and Fire Water

     As in the mine (see Section, 7.7), a certain amount of water is required

in the plant for various service functions.  We shall again assume that the

service water usage is related to the sanitary water usage.  The rationale,

as for the mine, is that the larger the service functions the larger the number
                                   156

-------
of personnel and sanitary usage.  In general, more water will be needed for



the plant than for the mine service facilities, so that we have assumed the



service water usage for the plant is 2 times the sanitary water usage.



     Unlike the mine case, some of the plant service water will be recoverable



after use.  We assume that 1/3 of the service water used is consumed and 2/3- is



recovered after treatment.  The used service water that is treated will be


                                               9
considered to be a low to medium strength waste , containing about 300 ppm



of suspended solids which are removed in the treatment prior to the reuse of



the water.  As in Section 7,6, the sludge from the water treatment plant is



assumed to be dewatered to 80% water.  The wet sludge weight which must be



disposed of daily is then given by the relation




           ,   /tons^ _ 300 Ibs solids   5 Ibs sludge   R ~o Ibs water    1 ton

   wet biuage^day )   106 ibs water  X.  Ib solid   xo""    gai    x 2000 Ibs





                              x [Water Usage-Water Consumed] (fal .  ) x 1440 f^
                                                             cal. mm         day




                    = 6 x 10~3 x Water Usage(  fal . ) .              (8.4)
                                          6  cal. mm'





     From the sanitary water 'usage the service water usage and consumption



are readily determined; while the generated sludge, which is quite small, is



calculable from Eq. (8.4) above.  The site specific results are given in the



tables of Section 10.





8.8  Settling Basin Evaporation



     If the surface feed water is sufficiently dirty or tutbid, it will



generally be appropriate  to employ settling basins at the supply source to



settle out the suspended matter, prior to pumping the water to an on-site



reservoir for plant and mine use.  In any settling basin,water will be lost



through evaporation and this loss is a penalty in water consumption chargeable



against the mine-plant complex.



                                   157

-------
     The quantity of water lost through evaporation will depend  on  the  basin



area and the net evaporation rate.  The basin area is given by the  relation




             r.     A      Throughput x Settling Time                   ,0  cx
             Basin Area = - " f. . - r - -  & -                   (8.5)
                                 Water Depth




In the present, study we will assume that peak usage and surge periods can be



accounted for by designing for a throughput which is 50% greater than the mean



annual consumption.  A conservative settling time to clarify a turbid surface



stream, especially where a precipitant such as lime is used, may be taken



to be 24 hours.  Finally, we choose the settling basin water depth  to be  3 ft,



which is a generally accepted value.  Using these values Eq.  (8.5)  can  be



written





   Basin Area  (ft ) = 1.5 x Consumption (  - - ;  ) x   - ^ x 8.33  -
                                  r     cal. mm    3 ft.         gal



                                    1 ft3          inin
                                 X T-r  ;  77;  X 1440 -r -
                                   62.4 Ibs        day
                    = 96.1 x Consumption (     )  .                   (8.6)
                                   v     cal. nan




     With the basin area determined, the quantity evaporated  in  gal/ calendar  minute



is given by the relation





   Quantity Evaporated(  !p   ) = Basin Area(ft )  x Net Evaporation Rate(  )
                       Oct_L  lujLil                                           J^



                                          1 ft   ,9  ,  Ibs water     1 gal i

                                       X 12 in  X    ^    ft3     X 8.33 Ibs



                                                    1 yr       1 day

                                                x 365 days X 1440 min




                      = 1.19 x 10~  x Basin Area(ft )  x Net Evaporation Rate( )  .





                                                                       (8.7)
                                   158

-------
In Table 8-4 are summarized the pond evaporation rates minus the annual precipi-

tation for the sites of the present study.  Also tabulated is the net evaporation

rate assuming some form of evaporation control such as the application of

monomolecular films to the water surface.  This control may also be a natural

one resulting from the presence of impurities in the local waters.  Experience

indicates that a reasonable maximum value to take for the effective reduction

in the evaporation minus precipitation rate is 25%  .  Also shown in Table 8-4

are the sites at which settling basins would be used based on the feed water

suspended solids concentrations given in Appendix B.
      Table 8-4.  Evaporation rates without and with evaporation
                        control and need for settling basin.
Location
Pond Evap.-Precip.
      (in/yr)
Beulah
Cols trip
Gillette
Kaiparowits
Nava j o
Rifle
30
35
40
61
53
33
Net Evap.
(in/yr)
23
26
40
46
40
25
Settling Basin
Need
No
Yes
Yes
No
Yes
V ft
Yes
*  Except for 100,000 bbl/day oil shale plant where groundwater is used.
                                   159

-------
     The calculation of the basin area cannot of course be carried out until



all the consumption figures are known.  The calculation generally involves one iter-



ation, in that  it  is necessary to assume a figure for the evaporation losses



in the basin and the reservoir (see next section) to determine the through-



put.  A loss rate from these sources is then determined and the result is



iterated.  One iteration is usually sufficient.





8.9  Reservoir Evaporation



     In this study we have assumed that the clarified feed water is pumped



to an on-site reservoir where it is stored prior to use.  To determinethe



reservoir size, a one week supply for the mine and plant is assumed to be



held in storage.  As a reservoir depth we take 21 ft.  In that case it can



be seen that the storage time per unit water height (3 days/21 ft) is the



same as was chosen for the settling basin so that the reservoir is given by



the same expression as Eq.  (8.6), that is,




                            j                         gal
           Reservoir Area(ft ) = 96.1 x Consumption(=	)       (8.8)
                                                    cal. mm




Similarly, the net evaporation rate is given by Eq. (8.7) with the basin area



understood to be replaced by the reservoir area.



     For the reservoir characteristics chosen, it follows that in those cases



where both a settling basin and a reservoir are required that the quantities



evaporated will be the same.  This simplifies somewhat the iterative calcula-



tion necessary to determine the losses that was described in the last section.



The results based on Eqs.  (8.6) to (8.8) and the rates given in Table 8-4 are



summarized in the tables of Section 10.
                                   160

-------
 References

 1.    Hendrickson, T.A. (editor), Synthetic Fuels Data Handbook, Cameron
      Engineers, Inc., Denver, Colorado, 1975.

 2.    Babcok & Wilcox, Steam - Its Generation and Use, 38th Edition, Revised,
      pp. 18-1 ff., Babcok & Wilcox Co., New York, 1975.

 3.    Batelle Columbus Laboratories, "Detailed Environmental Analysis Concerning
      a Proposed Gasification Plant for Transwestern Coal Gasification Co.,
      Pacific Coal Gasification Co., Western Gasification and The Expansion
      of a Strip Mine Operation Near Burnham, New Mexico Owned and Operated
      by Utah International Inc.," Federal Power Commission, Feb. 1, 1973.

 4.    Bureau of Land Management, "Final Environmental Impact Statement Proposed
      Kaiparowits Project," Chapter I, FES 76-12, U.S. Dept. of the Inte'rior,
      March 3, 1976.

 5.    North Dakota Gasification Project for ANG Coal Gasification Co.,
      "Environmental Impact Report in Connection with Joint Application of
      Michigan Wisconsin Pipe Line Co. and ANG Coal Gasification Co. for a
      Certificate of Public Convenience and Necessity," Woodward-Clyde
      Consultants,  Federal Power Commission Docket No.  CP75-278, Vol. Ill,
      March 1975.

 6.    Wyoming Coal Gas Co. and Rochelle Coal Co., "Applicant's Environmental
      Assessment for a Proposed Gasification Project in Campbell and Converse
      Counties, Wyoming," Prepared by SERNCO, October, 1974.

 7.    Colony Development Operation, "An Environmental Impact Analysis for a
      Shale Oil Complex at Parachute Creek, Colorado, Part 1 - Plant Complex
      and Service Corridor," Atlantic Richfield Company, Denver, Colorado,  1974.

 8.    Energy Transportation Systems, Inc., Unpublished Document, Casper,
      Wyoming, Feb. 21, 1974.  Summarized in memorandum.of E. Rappaport,
      Radian Corp., Austin, Texas.

 9.    Metcalf & Eddy, Inc., Wastewater Engineering, p. 231, McGraw-Hill,
      New York, 1972.

10.    Office of Water Resources Research, "Evaporation Suppression, a Bibliography,"
      WRSIC 73-216, Water Resources Scientific Information Center, U.S. Dept.
      of the Interior, Washington, D.C., 1973.
                                    161

-------
         9.  MUNICIPAL WATER REQUIREMENTS AND RESIDUALS









     In this section we present a rough basis for the estimation of the net




municipal water requirements associated with an increased population  in the




areas considered, resulting from the introduction of one or more  of  the




mine-plant complexes.  In presenting these estimates it is to be understood




that we assume all sewage water effluent in any municipality will be treated




to enable its reuse within the mine-plant boundaries.




     In Table 9-1 are shown our estimates of municipal water requirements




expressed on a gallons per capita per day basis.  The total water requirements




are rounded average estimates derived from Ref.  1.  The reasons for the some-




what higher figures for Montana and Wyoming compared with, say, Colorado are




not completely evident, since one might have expected the more arid region to




have a somewhat higher usage.  One explanation may be that these data were




obtained from averaging in a considerable number of areas where there is a




large water consumption for animals.  It should be noted that in some instances,




particularly in the case of Utah, the water consumption given' in Table 9-1




is lower than that cited in Ref. 1.  The reason for this is that for the




municipalities to be associated with the mine-plant complexes, the water use




will be principally for domestic, commercial and public consumption,  with




little requirement for the industrial portion of the total consumption that is




normally taken into account in municipal usage.   On the other hand, the




Utah figure given in Ref. 1 averages in the relatively large industrial




consumption associated with the Salt Lake region which encompasses the major




portion of the state's usage.
                                  162

-------
            Table  9-1.   Municipal  water requirements  in
                           gallons per  capita  per  day .

                                                           Treated for
     State                 Total           Consumed            Reuse

Montana, Wyoming            175              50                 125


Colorado, New Mexico,
Utah                        150              60                  90


North Dakota                100              30                  70
     For Montana, Wyoming  and North Dakota the consumptive use was estimated

at around 30%.  The somewhat higher consumption of 40% was taken for Colorado,

New Mexico and Utah because of  the more arid nature of the areas and the

concomitant higher rates of municipal consumption.  The last column of Table 9-1

is the difference between  the first two and represents that water which will

be treated for reuse.

     We may also estimate  the quantity of wet sludge which must be disposed of

after treatment for reuse  (see  also Section 7.6).  A standard figure for

suspended solids in sewage is 0.25 Ib/capita/day  (Ref. 1, p. 581). As in

Section 7.6,we assume that any  increased water usage above the average value

of 100 gal/capita/day associated with this solids loading,does not increase

the suspended solids effluent.  Furthermore we consider, as elsewhere in this

study, that the sludge from any water treatment plant is dewatered to 80%

water (20% solids).  This  yields a sludge rate of 1.25 Ibs of wet sludge per

capita per day.  Once the  population figures are specified this figure would

provide an estimate of the quantity of sludge to be disposed of daily.


Reference

1.   Metcalf & Eddy, Inc., Wastewater Engineering, p.  25, McGraw-Hill,
     New York, 1972.
                                   163

-------
                 10. SITE-SPECIFIC RESULTS









     The summary of the total water consumed and wet-solids residuals




generated at each site and for each unit size mine-plant complex are




given in Table 10-1.  A detailed breakdown by water use category of




the water consumption and residuals generated for each plant-site




combination is presented in the tables following Table 10-1.  Each




calculated quantity has been derived in the preceding sections.   The




results are presented by site in alphabetical order and by process




in the order shown in Table 10-1.
                              164

-------
                             Table 10-1.  Summary of  total water consumed and residuals generated at each site.

FACILITY

SLURRY PIPELINE (25 x 106 tons/yr @ 100% load factor)
ACRE-FT/YR*
WET SOLIDS* - 10 TONS/YK
LURGI (250 x 106 scf/stream day ? 90% load factor)
ACRE-FT/YR*
WET SOLIDS1' - 106 TONS/YR
SYNTHANB (250 x 106 scf/stream day @ 90% load factor)
ACRE-FT/YR*
MET SOLIDS1' - 106 TONS/YR
SYNTHOIL (100,000 bbl/strcam day 8 90* load factor)
ACRE-FT/YR*
WET SOLIDS* - 10s TONS/YR
ELECTRICAL GENERATION ( 3,000 HWe @ 35% eff and
70% load factor)
ACRE-FT/YR*
WET SOLIDSf - 10s TONS/YR
ELECTRICAL GENERATION (1,000 HWe 0 35% eff and
70% load factor)
ACRE-FT/YK*
WET SOLIDS* - 106 TONS/YR
OIL SHALE (50,000 bbl/stream day 8 90% load factor)
ACRE-FT/YR*
WET SOLIDS'" - io8 TONS/YR
OIL SHALE (100,000 bbl/streaffl day S 90% load factor)
ACRE-FT/YR"
WET SOLIDS* - IO6 TONS/YR

BEULAH,
NORTH DAKOTA




3,307
1.20

7,671
1.08

10,085
2.00


23,884
2.65











CO) .STRIP,
MONTANA




4,618
1.27

7,808
1.12

10,296
2.07


26,659
3.01











GILLETTE,
WYOMING

19,171


4,206
0.72

7,776
0.71

9,227
1.23


25,842
1.32










KAIPARONITS/ NAVAJO/
ESCAIANTB
UTAH














29,816
5.30










FAKMIMGTON
NEW MKXICO




5,639
3.00

8,670
2.84

11,753
5.31


29,206
5.00











RIFLE,
COLORADO


















9,494
0.38

6,480
20.40

12,924
40.81
* water Consumed
t Residuals

-------

SITE BEULAH
PLAMT TYPE Lurgi, 250 x 10 set per
stream day 
199
2,050
:OMSUMED





(-769)
26
3
(-740)

3,0/6
3
2
87
3,168
169

706
16.8.
13
2

-
389

-
8
226
.. 16. ...
17
11
t
121
3,307







o
6



S

;-






o


o



i
i






WET-SOLID





120
27
147


18
13

31
438




.04


.04



5,374
311

.J3
.09
2.685
3,301
SOLIDS
DRY SOLID





24
14
38


9
7

16
175











' 1.B28 '
251



2,079
2,308

HATER IN SOLIt'





16
1
18


' ' 1.5 "~
"^viL-L.

2.6
44

1









91
10



101
166
FOOTNOTES
s,primarily soluble
  inorganic waste
i,primarily insoluble
  inorganic waste
o,primarily insoluble
  organic waste

-------

SITE BEULAH
PIJUIT TYPE Synthane, 250 x 10 scf per
stream day @ 90Z load factor
	
PROCESS,
Net water consumed
Condensate Treatment Sludge
Boiler Demineralizcr Waste
SUBTOTAL
COOLING

Treatment Waste
Drift  Leakage
SUBTOTAL
FLUK GAS DESUI.Ft'P.IZATION

MI MI KG
Road, Mine, Embankment Oust: Control
Handling  Crushing Dust Control
Service 4 Fire Water
Sanitary  Potable Water
Revegetation
Coal washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL  OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service S Fire Water - Plant
Sanitary  Potable Water - Plant
SUBTOTAL
TOTAL
WATER CONSUMED
GAL/C. HIM

658
14
2
674

ACRE-FT/YR

1,061
23
3
1,087

3.084 I 4.974
2
2
89
3,177
532

116
93
6
1
-
-
216

-
13
35
69
31
7
2
157
4,756
3
3
144
5,124
858

187
150
10
2
-
-
349


21
57
11J
50
11
3
253
7,671

r. , i t o


o
s



8
i







O


O



i
i

o
o



WET-SOLID
TONS/C. DAY


105
23
128


27
24

51
170




.04


.04



5"4i
2,077

.12
.09
2,619
2,968
SOLIDS
DRY SOLID
TONS/C, DAY


WATKR IN SOLID
GAL./C. MIN

.,, 	 .^ ..... .-.--__ _
21
12
33


14
	 	 i-2 	 
26
68











416
1,663



2,079
2,206
14
1.9
16


2.3

4.3
17











21
69



90
127
FOOTNOTES
s, primarily soluble
inorganic waste
i, primarily insol'&le
inorganic waste
o, primarily insoluble
organic waste




-------

SITE BEULAH
PLANT Tm; Sytuhoil^ 100,000 bbl per
scream dav _@ 90* J.oad factor
PROCESS
Net Water Consumed
Condensate Treatment sludge
Boiler Dcfflineralizer Waste
SUBTOTAL
COOLING

Treatment Waste

Drift  Leakage
SUBTOTAL
FLUE CAS DESULFUMZATION
MINING
Boad, Mine, Embankment Oust Control
Handling & Crushing Dust control
Service  Fire Water
Sanitary  Potable Water
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottora Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service c Fire Water - Plant
Sanitary  Potable Water - Plant
SUBTOTAL
TOTAL
WATER <




(-72) .__
12
1
(-59)

5.254
2
 """ ' "
244
8,729
-

368
297
19
3
-
-
687

_
26
616
-
58
J.8. .
6
764
10,085






0
S



S
i







o


o



i


a
o



WET-SOUD
TONS/C DAY




89
S
97


20
46 ' ""

66





.07


.07



5,330
-

.20
.15
5,330
5,493
SOLIDS
DKY SOLID
TONS/C. DAY




18
It
22


10
5J "

33












4,100
-



4,100
4,155

WATER IN SOLTU
GAL/C. KIN




12
0.7
13


1.7 1
3.?f~

5.6
-











205
-



205
224
FOOTNOTES
s(primarily soluble
  inorganic waste

i,primarily insoluble
  inorganic waste

o,primarily insoluble
  organic waste

-------

SITE BEULAH
PLANT TYPE 3- "* @ 3 6- 3nd
70Z load factor

PROCESS
Nut Wator Consumed
Condensate Treatment sludge

SUBTOTAL
COOLING

Treatment waste

Drift  Leakage
SUBTOTAL
FLOE GAS DESULFURIZATION

MINING
Road, Mine, Embankment Dust Control
Handling & crushing Dust Control
Service  Fire Water
Sanitary  Potable Water
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION. SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service s Fire Water - Plant
Sanitary & Potable Water - Plant
SUBTOTAL
TOTAL
WATER







6.1
0.1

P. 360
17

36
13,413
896


149
120
8
1
-
_
278

_
39
45
RQ
40
5
2
220
14,807
:ONSUMED







0.2
0.2

21,550
27

58
21,635
1,445


240
194
13
2
-
_
449

-
63
72.5
141 S
65
8
3
355
23,884








s



i









o


o



i
i

o
o



WET-SOLiU
TONS/C DAY






1.7
1.7


169


169
3,720





,05


.OS



697
2.672

.08
.07
3,369
7,260
SOLIDS
DRY SOLID
TONS/C DAY






0.*
0.9


~"~ 	 ~6"? 	


67
1,488












535
2,138



2,673
4,229

WATER IN SOLID
GAL/C. MIN






6.1
0.1


17


17
372












27
89



116
505

























FOOTNOTES
s, primarily soluble
inorganic waste

inorganic waste

o, primarily insoluble
organic waste





-------

SITE COLSTRIP
PLAOT TYPE Lurgl, 250 x 10 scf per
stream day @ 90Z load factor
PROCKSS

Condensate Treatment Sludge
Boiler Deraincralizer Waste
SUBTOTAL
COOLING
Evaporated
Treatment Waste
Drift  Leakage
SUBTOTAL
FLUE GRS DESULFURIZATIOU
HIKING
Road, Mine, Embankment Dust Control
Handling & Crushing Dust Control
Service  Fire Water
Sanitary s Potable Water
Revegetation
Coal Hashing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL fi OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service S Fire water - Plant
Sanitary t Potable Water - Plant
SUBTOTAL
TOTAL
WATER CONSUMED
GAiyC. MIN

183
12
2
197

2,004
2
1
57
2,064
233

69
82
6
1
-
-
158

9
9
146
11
27
7
2
211
2,863
ACRE-FT/YR

295
20
3
318

. 3.232
3
- J-6
92
3,329
376

__.. Ill
132
10
2
-
-
255

14.5
14.5
235
18
.. . 44
11
3
340
4,618

S, i, 0


o
S



s
f.







0


o



1
1

q
0


SOLIDS
WET-SOLID
TONS/C. DAY


89
24
113

DRY SOLID
TOKS/C. DAY


18
12
30

1 " ' 	 	
19
14

33
540




.04


.04



2,470
326

J2
.09
2,796
3,482
10
7

17
216











1,9UU
260



2,160
2,423
WATER IN SOLID
CAL/C. HtH


12
1
14


1.6
 ,_.kL~-~
2.8
54











95
11



106
177
FOOTNOTES
S,primarily soluble
  inorganic waste
i,primarily insoluble
  inorganic waste
o,primarily insoluble
  organic waste

-------

SITK COLSTR1P
PLANT TYPK Synthane,250 x 10 set per
stream day @ 90Z load factor

PROCESS
Net Water Consumed
Condensate Treatment Sludge
Boiler Demineralizer Waste
SUBTOTAL
COOLING

Treatment Waste

Drift  Leakage
SUBTOTAL
FLUE GAS DESULFURI2ATION

MINING
Road, Mine, Embankment. Dust control
Handling  Crushing Dust Control
Service s Fire Water
Sanitary S Potable Hater
Rcvegetation
Coal Mashing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service & Fire Water - Plant
Sanitary S Potable Water - Plant
SUBTOTAL
TOTAL
WATER (





658
14
2
674

3.240
2
2
93
3,337
517


63
74
5
1
-
-
143

14
14
36
72
25
7
2
170
4,841
rONSUMKD





1.061
23
3
1,087

5.226
3
3
150
5,382
834


102
119
8
2
-
-
231

23
23
5B
116
40
11
3
274
7,808

s i o





o
s



s
i








0






1
i

o
o



WET-SOLID
TONS/C DAY





103
22
127


27
24

51
170





.03


.03



564
2,160

,12
,09
2,724
3,072
SOLIDS
DRV SOLID
TONS/C DAY





21
11
32


14
12. , -, ,

26
68












432
1,728



2,160
2,286

WATER IN SOLID
GAL/C. KIN





14
1.8
16


2'3 
2 _,.

4.3
17












22
72



94
131

























FOOTNOTES
s, primarily soluble
inorganic waste

inorganic waste

o, primarily insoluble
organic waste





-------
ro

SITE COLSTRIP
PLAHT TYPE Synthoil, 100,000 bbl per
Stream day ? 903! load factor

PROCESS
Net Water Consumed
Condensate Treatment Sludge
Boiler Domineralizer Haste
SUBTOTAL
COOLING

Treatment Waste

Drift s Leakage
SUBTOTAL
FLUE GAS DESULFURIZATtOH
MINIMS
Road, Hinc, Embankment Dust Control
Handling  Crushing Dust Control
Service  Fire Water
Sanitary s Potable Hater
Revegetation
Coal Hashing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust control - Plant
Service  Fire Hater - Plane
Sanitary s Potable Hater - Plant
SUBTOTAL
TOTAL
WATER (





526
9
I
536

4.9J,9
1
3
143
5,066
_

123
1*6
11
2
-
-
282

19
19
397
-
49
11
4
499
6,383
XJNSUMEO





848
15
1.6
865

7.934
1.4
5
231
8,171


198
236
18
3
-
-
455

31
31
640
-
79
18
6
805
10,296

.





o
s



8
i







o


o



1


o
o



WUT-SOLID





67
8
75


16
40

56





.06


.06



5,537


.20
.15
5,537
5,668
SOLIDS
DRV SOLID





13
4
17


8
20

28












4,259




4,259
4,304

WATER IN SOLID
GAL/C >!IN





9
U. '6
10


1.3
.^2,3^.,.,.. .

4.6












213




213
228
























FOOTNOTES
s, primarily soluble
inorganic waste



o,primarily insoluble
organic waste





-------

SITE COLSTRIP
PLAHV TYPE 3,000 MWe ? 35% off. and
70Z load factor

PROCESS
Not Water Consumed
Condcnsate Treatment Sludge
Boiler Demineralizel: Waste
SUBTOTAL
COOLING
Evaporated
Treatment Waste

Drift & Leakage
SUBTOTAL
FLUE GAS DESULFUMZATION

MIHIHG
Road, Mine, Embankment Dust control
Handling  Crushing Dust Control
Service & Fire Water
Sanitary s Potable Hater
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL  OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service 1 Fire Water - Plant
Sanitary  Potable Water - Plant
SUBTOTAL
TOTAL
WATER







0.1
0.1

14,040
15

38
'4,093
1,975


81
95
6
1
-
-
183

49
49.
46
93
32
5
2
276
16,527
:ONSUMED







0.2
0,2

22.646
24

62
22,732
3,186


131
153
10
2
-
-
296

79
79
74
150
52
8
3
445
26,659








8



i









O


o



i
i

o
o



WET- SOLID






1.6
1.6


152


152
4,588





.04


.04



723
2,780

.08
.07
3,503
8,245
SOLIDS
DRY SOLID
TONS/C DAY






0,8
0.8


61


61
1,835





1






555
2,222



2,777
4,674

WATER IN SOLIU
GAL/Ct M1N


_



0,1
oa


15


15
459












28
93



121
595






i


















FOOTNOTES
s, primarily soluble
inorganic waste



o, primarily Insoluble
organic waste





-------

SITE GILLETTE
PLANT TXPfi Slurry Pipeline,
250 x 10 tons/yr 8 100Z load facto:
PROCESS
Net Water Consumed
Condcnsato Treatment Sludge
Boiler Dcmineralizer Haste
SUBTOTAL
COOLING

Treatment: Waste

Drift s Leakage
SUBTOTAL
FLUE GAS DESULFURIZATIQN
HI!UHC
Road, Mine, Embankment Oust Control
Handling & Crushing Dust Control
Service  Fire Water
Sanitary fi Potable Water
Re vegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL 8 OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Pust control - Plant
Service & Fire Hater - Plant
Sanitary t Potable Water - Plant
SUBTOTAL
TOTAL
WATER C




11,420
_
-
11,120

_
-

~
-
-

95
228
17
3
-
-
343

41
41
-
-
38
2
1
1?3
11,886
fflNSUMED




18,420
-
-
18,420

-


~
-
-

153
368
27
5
-
.
553

66
66
-
-
61
3
2
198
19,171




















o


0






o
o



WET-SOLID


















.10


.10






.04
.03

.17
SOLIDS
DRV SOLID

































WATER IN SOLID
CAI/C . MTH
































FOOTNOTES

s,primarily soluble
  inorganic waste
i/primarily insoluble
  inorganic waste
o,primarily insoluble
  organic waste

-------
Ul

SITE GILLETTE
1-LANT TYPE Lurgi, 250 x 10 scl per
stream day g 90J load factor

PROCESS
Set Water Consumed
Condensate Treatment Sludge
Boiler Dcraineralizer Waste
SUBTOTAL
COOLING
Evaporated
Treatment Waste

Drift S Leakage
SUBTOTAL
FLUE GAS DESULFURIZATION

MINt:!C
Road, Mine, Embankment Dust Control
Handling  Crushing Dust Control
Service & Fire Water
Sanitary  Potable Water
Revegetation
Coal Washing
SUBTOTAL

EVAPORATION, SOLIDS DISPOSAL  OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service t Fire Water - Plant
Sanitary S Potable Water - Plant
SUBTOTAL
TOTAL
WATER C





38
13
2
53

2J344
2
1
58
2,105
178


34
84
6
1
-
-
125


9
9
86
6
28
7
2
147
2,608
;ONSUMED





61
21
3
85

3.297
3
1.6
93
3,395
287


SS
135
10
2
-
-
202


14.5
14.5
139
10
45
11
3
237
4,206







o
s



s
1








0


o




1
i

o
o



WET-SOLID
TONS/C. DAY





100
26
126


20
14

34
163





.04


.04




1.449
190

.12
.09
1,639
1,962
SOLIDS
DRV SOLID
TONS/C DAY





20
13
33


10
7

17
65













1,113
154



1,2'67
1,382

WATER IN SOLID
GAL/C. MIN





13
2
15


1.6
1.2 _, 	 ^

2.8
16
__r












56
6



62
96

























FOOTNOTES

s, primarily soluble
inorganic waste



o, primarily insoluble
organic waste





-------

SITE GILLETTE
PLANT TYPE Synthane, 250 x 10 scf per
stream day @ 90Z load factor

F.RDCESS
Net Water Consumed
Condensate Treatment Sludge
Boiler Demineralizer Haste
SUBTOTAL
COOLING
Evaporated
Treatment waste
Drift fi Leakage
SUBTOTAL
FLUE GAS DESULFURIZATION
KINING
Road, Mine, Embankment Dust control
Handling  Crushing Dust control
Service 6 Fire Water
Sanitary & Potable water
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL & OTHERS
Settling Basin Evaporation
Reservoir. Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service & fire water - Plant
Sanitary  Potable Water - Plant
SUBTOTAL
TOTAL
HATER CONSUMED
OM./C. MIN

658
14
2
67 tt

3,266
2
2
94
3,364
532

31
75
6
1
-
-
113

17
17
28
42
25
7
2
118
4,821
ACRE-FT/YK

1.061
23
3
1,087

5,268
3
3
152
5,426
858

50
121
10
2
-
-
163

, , ,27,5 	 	
27.5
45
68
40
11
3
222
7,776

s, i, o


0
s



s
i







o


0



1
1

o
o


SOLIDS
WET-SOLID
TOKS/C. DAi


105
23
128


28
24

52
170




.03


.03



...,. 331
1,266

.12
.09
1.597
1,947
DRY SOLID
TOKS/C, DAY


21
11
32

WATER IN SOLID
GAL/C. MIN


14
1.9 .
16

1
14
12

26
68











253
1,014



1.267
1,393
2.3
2

4.3
17

, I,, ^









13
42



55
92
FOOTNOTES
s,primarily soluble
  inorganic waste

i,primarily insoluble
  inorganic waste

o,primarily insoluble
  organic waste

-------

SITE GILLETTE
PLANT TYPE Sjmthoil, 100,000 bbl per
stream day @ 90Z load factor
PROgss
Net Water Consumed
Condensate Treatment Sludge
Boiler Dcraineralizer Waste
SUBTOTAL
COOLIMG

Treatment Waste

Drift 6 Leakage
SUBTOTAL
FLUE CAS DESULFURI2ATION

MINING
Road, Mine, Embankment Dust Control
Handling f Crushing Dust Control
Service S Fire Hater
Sanitary & Potable Water
Rcvegotation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Ply Ash Disposal
Dust Control - Plant
Service  Fire Water - Plant
Sanitary S, Potable Water - Plan.t
SUBTOTAL
TOTAL
HATER




290
8
1
299

4.718
1
4
i3>
4,860



62
149
11
2
-
-
224

20
20
233
-
50
11
4
338
5,721
CONSUMED




468
13
. 1
482

7.610
2
6
221
7,839



100
240
18
3
-
-
361

32
32
376
-
81
1H
6
545
9,227






o
s



a
i








o


0



i


6
o



WBT-SOLTD




61
8
69


15
46

61






.06


.06



3,248
-

.20
.15
3,248
3,378
SOLIDS
DRV SOLID
TOH^/C DAY




12
4
16


8
23

31-













2,49B
,



2,498
2,545

WATER IN SOLI
G7VJ./C . MI N




8
0.6
9


1.3
3.9

5.2













125
_



125
139
























QOTOOTES
s, primarily soluble
inorganic waste



, primarily insoluble
organic waste





-------

SJTE GILLETTE
PIJUJT TYPE 3,000 MHe g 35Z elf . and
70Z load factor
PROCESS
Not Water Consumed
Condensate Treatment Sludge
Boiler Domineralizer Waste
SUBTOTAL
COOUNG

Treatment Waste

Drift t Leakage
SUBTOTAL
FLUE GAS OESUI.FUMZATIOH
HIKING
Road, Mine, Embankment Dust Control
Handling  Crushing Oust Control

Sanitary 6 Potable Water
Rcvegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL  OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
fly Ash Disposal
Dust Control - Plant
Service & Fire Water - Plant
Sanitary 1. Potable Water - plant
SUBTOTAL
TOTAL
-WATER c






0.1
0.1

14,075
18

^b
14,133
1,512

40
97
8
1
-
-
146

55
55
27
54
32
5
2
230
16,021
-ONSUMED






0.2
0.2

22./03
29

65
22,797
2,439

65
156
13
2
-
-
235

89
89
43
87
52
8
3
371
25,842

s i o









i








o


o



1
i

o
o



WET-SOLID





1.6
1.6


182


182
1,373




.o


.04



422
1,627

.08
.07 '
2,049
3,606
SOMtDS
DRY SOLID
TONS/C DAY





0.8
0.8


73


73
549











Jib
1,303



1,625
2,252

WATER IN SOLID
GAT'/C . HIM





0.1
0.1


18


18
137











16
54



70
225
 s,primarily soluble
   inorganic waste

 i,primarily insoluble
   inorganic waste

"jo,primarily insoluble
   organic waste

-------

SITE KAIFAROWITS/ESCALANTE
PLANT TYPE 3' W* $ 35Z efft and
702 Ififld factor

PROCESS
Not Water Consumed
Condcnsate Treatment Sludge
Boiler Demineralizer Waste
SUBTOTAL
COOLING

Treatment Waste

Drift  Leakage
SUBTOTAL
FLUE GAS DESULFURIZATIOti

MINING
Road, Mine/ Embankment Dust Control
Handling fi Crushing Dust Control
Service E Fire Water
Sanitary 6 Potable Water
Revegetation
Coal Wash i no

SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL  OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Botton Ash Disposal
Fly Ash Disposal
Dust control - Plant
Service t Fire Water - Plant
Sanitary & Potable Water - Plant
SUBTOTAL
TOTAL
WATER <







0,2
0.2

14,770
26

36
14,832
2,313


38?

, ._ 62
12
8
658

1.J29

-
97
27
ST
>1
A
3
211
18,485
:ONSUMED







0.3
0.3

23,824
42

58
23,924
3,731


628

100
19
13
1 061

1,821

-
156
44
85
40
10
5
340
29,816








8



i









0

i
i,o




i
i

o
o



WET-SOLID






2.3
2.3


262


262
1,410





-- -?2

4,467
6,359
10.826



415
1.592

,10
.07
2,007
14,507
SOLIDS
DRY SOLID






1.2
1.2


104


104
564







4,020
3,564
7.584



319
1,274



1,593
9,846

HATKR IN SOLID
GAL/C fclN






0.2
0.2


26


26
141







75
Abb
5* '



16
53



69
777
























COARSE REJECT
'AIL1NGS
FOOTNOTES
Srprimarily soluble
inorganic waste
.


o, primarily insoluble
organic waste





-------
CO
o

SITE NAVAJO/FARMINGTON
HJVNT TYPE Lurgl, 250 x 10 acf per
stress day 9 90S load factor
PROCESS^
Net Water consumed
Condensate Treatment Sludge
Boiler Dcniineralizer Waste
SUBTOTAL
COOLING

Treatment Waste

Drift s Leakage
SUBTOTAL
FLUE GAS DESULFURlZftTION
MIMING
Road, Mine, Embankment Dust Control
Handling  Crushing Dust Control
Service & Fire Water
Sanitary S potable Hater
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL G CITHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service * Fire Hater - Plant
Sanitary S Potable Water - Plant
SUBTOTAL
TOTAL
WATER




526
11
2
539

1.792
1
1
52
1,8*6
289

97
85
9
2
130 .

323

16
16
401
28
28
7
3
499
3,496
COHSUHED




848
18
3
869

2r89l
1.6
J..6
84
2,978
466

156
137
i5
3
210
_
521

26
26
647
45
45
11
5
805
5,639






o
s



S
i







o


o



i
i

o
o



WET-SOLID




80
18
98


17
;3

30
468




.05


.05



6,787
835

.13
.09
7,622
8,218
SOLIDS
DRV SOLID
TONS/C DAY




16
9
25


9
6

15
187











5,222
667



5,889
6,116

WATER IN SOLID
GAL/C. M1K




11
1.5
13


1.4
1.1

2.5
47











2bl
28



289
352
                                                                                                                                              FOOTNOTES

                                                                                                                                              s,primarily soluble
                                                                                                                                                inorganic waste
                                                                                                                                              i,primarily insoluble
                                                                                                                                                inorganic waste
                                                                                                                                              o,primarily insoluble
                                                                                                                                                organic waste

-------
CO

SITE NAVAJO/FARMINCTON
P1.ANT TYPE Synthane, 250 x 10 scf per
stream day @ 903! load factor

PROCESS
Net Water Consumed
Condensate Treatment Sludge
Boiler Dcmincralizer Waste
SUBTOTAL
COOUNG

Treatment Waste

Drift & Leakage
SUBTOTAL
FLUE GAS DESULFURI2ATJON

MIN1IIG
Road, Mine, Embankment Dust "Control
Handling fi Crushing Dust Control
Service & Fire Water
Sanitary C Potable Water
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION , SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service  Fire Water - Plant
Sanitary  Potable Water - Plant
SUBTOTAL
TOTAL
HATER C





658
14
1
673

3,384
2
2
98
3,486
532


. 87
77
8
2
117
-
291

25
25
123
_ 184
26
7
3
393
5,375
XWSUMED





1.061
23
1.6
1,086

5.459
3
3
158
5,623
858


140
124
13
3
189
-
469

40
40
199
297
42
11
$
634
8,670







o
s



B
T.








a


o



1
i

o
rp



WET-SOLID





105
17
122


27
24

51
170





4


.04



1.416
5.S21

.11
.09
7.437
7,780
SOLIDS
DRY SOLID





__, .. ?!..
8
29


14
12

26
68












1 477
4 417



5.889
6,012

WATER IN SOLID
GAL/C HIM





^<>
1,4
Tj


2.3
i

4.3
17












74
184,



258
294

























FOOTNOTES
s, primarily soluble
inorganic waste

inorganic waste

o, primarily insoluble
organic waste





-------
CO

SITE HAVAJO/FARMTNnTON
PLANT TYpKSynthoi1' 1.000 bbl Per
stream day @ 90Z load factor
PROCESS
Net Water Consumed
Condensate Treatment Sludge
Boiler Dcmincralizer Waste
SUBTOTAL
CODLING

Treatment Waste

Drift s Leakage
SUUTOTAL
FLOE GAS OESULFURIZATION

MINING
Road, Mine, Embankment Dust Control
Handling  Crushing Dust Control
Service  Fire Water
Sanitary  Potable Water
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service  Fire Water - Plant
Sanitary  Potable Water - Plant
SUBTOTAL
TOTAL
WATER C




625
7
1
633

4.765
1
4
138
4,908



172
151
17
3
232
-
575

33
33
1.035
_
50
13
6
1.170
7,286
XINSUMED




1.009
11
. 1.6
1,021

7.686
2
6
223
7,917



278
244
27
5
374
-
928

53
53
1.670
_
80
21
10
1.887
11,753

c i o




O
s



e
i








o


o



1


o
o



WET-SOLID




52
6.
58


13
41

54






.08


.08



14,430
_

.24
.15
14.430
14,542
SOLIDS
DRY SOLID




10
3
13


7
21

28













11,100
-



11,100
11,141

WATER IN SOLID
GAL/C . MIN




7
O.S
8


1.1
3.5

4.6













555
-



555
568
                                                                                                                                                FOOTN?OTES
                                                                                                                                                s,primarily soluble
                                                                                                                                                  anorganic waste
                                                                                                                                                i,primarily InsolubZL>s
                                                                                                                                                  inorganic waste
                                                                                                                                                o,primarily insoluble
                                                                                                                                                  organic waste

-------

SITE NAVAJO/FARMINGTON
PLANT TYPE 3,000 MWe @ 35Z eft. and
70X load factor

PROCESS
Not Water Consumed
Condensatc Treatment Sludge
Boiler Dcmineralizer Waste
SUBTOTAL
COOLING

Treatnent Waste

Drift  Leakage
SUBTOTAL
FLUE GAS DKSULFURIZATION

MINING
Road, Mine, Embankment Dust Control
Handling ( Crushing Dust Control
Service  Pirc Hater
Sanitary 6 Potable Water
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL  OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service t Fire Water - Plant
Sanitary i Potable Water - Plant
SUBTOTAL
TOTM.
WATER C







0.1
0.1

14.617
17

38
14,672
2,456


]1?
59
11
2
151
-
375

83
83
1SS
?17
\\
6
3
603
18,106
rONSUMED







0.2
0.2

23.577
28

61
23,666
3,961


1R1
160
18
3
244
-
606

134
134
255
382
53
10
5
973
29,206

s i o










1









0


o



i
i

o
0



WET-SOLID
TONS/C DAY






1.2
1.2


171


171
3,970





.05


.05



2.463
7,099

.11
.oi
9,562
	 i3';m 	
SOLIDS
DRY SOLID
TONS/C DAY






0.6
0.6


67

~"
67
1,588












1.893
5,677



7,570
9,226

WATER IN SOLID
GAL/C. MIN






0.1
0.1


17


17
397


-
__








95
237



332
746

























FOOTNOTES
s, primarily soluble
inorganic waste



o, primarily insoluble
organic waste





-------
CO

SITE RIFLE
PLANT TYPE 1.000 Mtfe @ 3SZ etf. and
70* load factor

PROCESS
Net Water Consumed
Condensate Treatment Sludge
Boiler Dcmineralizer Waste
SUBTOTAL
COOLING
Evaporated
Treatracnt Waste
Drift ( Leakage
SUBTOTAL
FLUE GAS DESULrURIZATION

KtKIUC
Road, Hine, Erabanknent Dust Control
Handling * Crushing Dust Control
Service S Fire Water
Sanitary & Potable Water
Revegetation
Coal. Washing
SUBTOTAL
EVAPORATION! , SOLIDS DISPOSAL & OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service fc Fire water - Plant
Sanitary S Potable Water - Plant
SUBTOTAL
TOTAL
HATER CONSUMED
GAL/C. MIN



0.03
0.03

4,867
L *

12
4,883
884

29
21
3
1
-
-
54

17
17
7
13
7
2
1
64
5,885
ACRE-FT/XR



0.05
0.05

7_,851
7

19
7,877
1,426

, 47 ___
34
5
2
-
~
88

27.5
27. S
11
21.. __
11
3
2
103
9,^94

s, i, o



S



i















i
i

o



SOLIDS
WET-SOLID
TONS/C. DAY



0.3
0.3


45


45
520




.01


.01



100
380

.04
.03
480
1,045
DRY SOLID
TONS/C. DAY



0.2
0.2


18


18
208











>6
302



378
604
WATER IN SOLIC
GAL/C. KM



0.03
0.03


4


4
52











4
13



17
73
                                                                                                                                                 FOOTNOTES
                                                                                                                                                 s/primarily soluble
                                                                                                                                                   anorganic waste

                                                                                                                                                 i,primarily insoluble
                                                                                                                                                   inorganic waste

                                                                                                                                                 o/priiaarily insoluble
                                                                                                                                                   organic waste

-------
I-1
OO
Ui

SITE RIH,E
PLANT WE Shal6' 50'00 b" P0r
scream day @ 90% load factor

PROCESS
Wet Water Consumed
Retort
Refinery
SUBTOTAL
COOLING

Treatment Waste

Drift c, Leakage
SUBTOTAL
FLUE CAS DESULFURIZATJCM
HIKING
Road, Mine, Enjbankmcnt Dust Control
Handling & Crushing Dust Control
Service fi Firo Water
Sanitary  Potable Water
Revegetation
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL  OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Spent Shale Disposal
Venturi Scrubbing Dust Control
Dust control - Plant
Service s Fire Water - Plant
Sanitary  Potable Water - Plant
SUBTOTAL
TOTAL
WATER CONSUMED
GAL/C. HIM


716
548
1,264

ACRE-PT/YR


_ 1,155
884
2,039

874 I 1.410
-

L 26
900


315
198
11
2
43

569

12
12
1,125
90
33
9
4
K285
4,081
.

42
1,452


SOS
319
18
3
69

917

19
19
1,815
145
51
15 .

2.072
6,480

s, i, o
















a


o



i.sdlubTe org .
i.soluble orft.

0
o


SOLIDS
KBT-SOUD
TONS/C. DAY
















.05


.05



55,022
871

.17
.11_.._
55.893
55,893
Dfiy SOLID
TONS/C. DAY























48,263
331 "



48,594
48,594

WATER IN SOLID
. GAL/C. HIN























1,127
90



1,217
1,217
FOOTNOTES
s, primarily soluble
inorganic waste
i, primarily insoluble
inorganic waste
o, primarily insoluble
organic waste

-------
CO

SITE RIFLE
PLANT TYPE Shale, 100,000 bbl per
stress day at 90Z load factor
PROCESS
Met Wator Consumed
Retort
Refinery
SUBTOTAL
COOLING
Evaporated
Treatment Waste
Drift 4 Leakage
SUBTOTAL
FLUE GAS DfiSULFURIZATION
MINING
Road, Mine, Embankment Dust Control
Handling S Crushing Dust Control
Service fi Fire Water
Sanitary s Potable Water
Revegetation
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Spent Shale Disposal
Venturi Scrubbing pust Control
pust Control - Plant
Service t Fire Kater - Plant
Sanitary s Potable Water - Plant
SUBTOTAL
TOTAL
WATER CONSUMED
GM./C. KIN


1,432
1,096
2,528

1,748
1

52
1,801


630
396
21
4
86

1,137


2")
J.?
180
66
19
8
2,546
8,012
ACKE-FT/YR


2,310
1,768
4,078
-
2.819
1.6

84
2,905


1,016
639
34
6
139

1,834


37
.. -trfi?q
290
107
31
13
4,107
12,924

s, i , o
















o


o



t, soluble ore
L, soluble ors

0
0


SOLIDS
WET-SOLID
TONS/C. DM







9


9





.11


.11



110,045 ._
1,742

.34
.22
111,788
111,797
DHY SOLID
TONS/C. DAY







5


5












96.526
662



97,188
97,193
WATER IN SOLID
GM./C. M1K



1



0.7


0.7












2,254
180



2,434
2,435
                                                                                                                                              FOOTNOTES
                                                                                                                                              s,primarily sellable
                                                                                                                                                inorganic waste
                                                                                                                                              i,primarily insoluble
                                                                                                                                                inorganic waste
                                                                                                                                              o,primarily insoluble
                                                                                                                                                organic waste

-------
                          11.  FINDINGS



     The findings of this study are presented in the following sections


on the basis of total site-specific water consumption and residuals, a


breakdown of these quantities, and regional water consumption and


residuals.



11.1 Total Site-Specific Water Consumption and Residuals


     Table 10-1, repeated here as Table 11-1, summarizes the study find-


ings on the net annual water consumption and wet solid residuals generated


at each site for the unit size mine-plant complexes assumed to be located


there.


     The largest variation  in water consumption as a function of site


(a factor of about 1.7) is  for the Lurgi process.  This is principally a


consequence of the differences in coal moisture at the different locations,


The lowest consumption is at Beulah, North Dakota where the net consumed

                              f)                   O
water is found to be 2.96 x 10  gal/day (3.31 x 10  acre-ft/yr) or about


one-third the lowest published design estimates.  The corresponding


variations in water consumption for the Synthane and Synthoil facilities


are found to be relatively  small being no more, respectively, than 13%


and 16%.  However, for the  steam electric power generating plants


a maximum difference in water consumption of 25% is noted.  These same


findings do not hold for the residuals, as we shall discuss below.


     Since both the products and outputs of the Lurgi and Synthane plants


are the same, these two facilities may from this point of view be


compared directly.  It is found that a Synthane complex uses from 1.5 to


2.3 times the water that a  Lurgi facility does at the same site.  This


is a consequence of comparing unlike technologies.  It is related in part
                                 187

-------
              Table 11-1.  Summary of  net annual water  consumption and wet solid residuals generated at  each site.
FACILITY
SLUKJW PIPELINE (25 x ID6 tons/yr @ 100* .load factor)
NET WATER CONSUMED - 103 ACRE-PT/YR*
WET SOLID RESIDUALS - 105 TON'S/YR
IURGI (250 x 10* set/stream day @ 90* load factor)
NET WATER CONSUMED - 103 ACRE-FT/YR
WET SOLID RESIDUALS - 10s TONS/YR
SYMTHAHE (250 x 1C6 set/stream day @ 90% load factor!
NET KATSR COMSUVD - 103 ACRE-FT/VR
KET SOLID RESIDUALS - 106 TOHS/YR
EYKTIIOIL (100,000 bbl/streara day @ 90% load factor)
IIET HATER CONSUMED - 103 ACRE-FT/YR
KtT SOLID RESIDUALS - 106 TONS/YR
ELECTRICAL GSNERATION (3,000 NKC 8 35% eff, 70% load factor)
KET KATER CONSUMED - 103 ACRE-FT/YR
KET SOLID RESIDUALS - 106 TONS/YR
ELECTKICAi GENERATION (1,000 KWe 6 35% e, 70% load factor)
NET WATER CONSUMED - 103 A'CRE-PT/YR
VmT SOLID RESIDUALS - K>6 TONS/VR
OIL SHALE (50,000 bbl/stream day 6 90% load factor)
IIET WATER CONSUMED - 103 ACRE-PT/YR
hTT SOLID RESIDUALS - 10& TONS/YR
OIL SIIALE (100,000 bbl/stream day @ 90% load factor)
NP.T HATER CONSUMED - 103 ACRE-FT/YR
WET SOLID RESIDUALS - 106 TONS/YR
BEULAH,
NORTH DAKOTA

3.31
1.20
7.67
1.08
10.09
2.00
23.88
2.65



COLSTRIP,
MONTANA

4.62
1.27
7.81
1.12
10.30
2.07
26.66
3.01



GILLETTE,
WYOMING
19.17
4.21
0.72
7.78
0.71
9.23
1.23
25.84
1.32



KRIPAROWITS/
ESCALANTE,
UTAH




29.82
5.30



NAVAJO/
FARMINGTON,
NEW MEXICO

5.64
3.00
8.67
2.84
11.75
5.31
29,21
5.00



RIFLE,
COLORADO





9.49
0.38
6.48
20.40
12.92
40.61
O3
O3
          To convert 103 acre-ft/yr to 106 tons/yr multiply by 1.36,
           to convert 103 "aesre-ft/yr to 1Q& gal/day multiply by 0.894.

-------
to the fact that the Lurgi process accepts wet coal and therefore the




moisture is utilized, but at a cost.  This same water could in principle




also be recovered in Synthane plants from coal drying, but also at a cost.




Nevertheless, with the water treatment designs of this study, the absolute




consumptions of the Synthane plants are still below the lowest published




water consumption estimates for gasification plants of this size.




     The products of the 100,000 bbl/day Synthoil and TOSCO II oil shale




facilities are roughly the same, so that they may with reason be compared




between themselves.  It is of interest that their net water consumptions




are roughly comparable, with the shale oil facility about 20% higher.  How-




ever, the solid residuals from the oil shale processing are very much




higher, as we shall discuss below.




     In comparing the absolute water requirements between processes




caution must be exercised, since generally the fuel inputs and product




outputs are not directly comparable.  One means of comparison among




processes, whose outputs are fuels to be used for their heating value, is




to express the net water consumptions in terms of gallons per million Btu




of fuel produced (gal/10  Btu).  We may include the slurry pipeline in




this comparison if we take the output to be the heating.value of the




coal being transported.  In a. rough manner, we may likewise include




electric power generation in the comparison by expressing the net water




consumed in terms of the heating value of the input coal, that is,




gal/10  Btu of input.  In Table 11-2 are shown the water requirements




in gal/10  Btu, with no distinction made as to consumption between the




sites but with overall ranges given instead.
                                189

-------
          Table 11-2.  Net water consumed for Western coal sites
                       per million Btu of heating value in product,
                                           Net Water Consumed
              Facility                       (gal/10  Btu)
              Lurgi                               14-24
              Synthane                            32-36
              Synthoil                            15-19
              Oil Shale                            23
              Slurry Pipeline                      14
              Electric Generation                 43-54*
              *gal/10  Btu of heating value of input coal.
     As a very approximate finding, Table 11-2 would seem to show that
with the design procedures used in this study and with proper water
treatment design the Lurgi, Synthoil, oil shale and slurry pipeline water
requirements are roughly the same when expressed per unit of heating out-
put.  The slurry pipeline requirement is at the lower end of the spread,
while oil shale is at the upper end.  The Synthane facilities require
about.2 times more water and electric power generation at least 2.5 times
more, as measured in terms of the heating value of the input coal.
     As shown in Table 11-1, for a given facility the quantity of solid
residuals is very site dependent.  For each of the coal conversion
processes including electric generation, the largest variation between
sites is more than a factor of 4.  This large variation occurs for all the
processes between Navajo/Farmington, New Mexico and Gillette, Wyoming
principally as a result of the relatively high ash content of the Navajo
coal compared to that at Gillette (and the other sites).   A big fraction
                                190

-------
of the large quantity of residuals generated at Kaiparowits is coal




refuse, a consequence of the fact that the coal.is underground mined.




Outstripping all the coal conversion residuals by an order of magni-




tude are those from shale oil processing, where the primary residual




is the wet spent shale.  Comparing the 100,000 bbl/day Synthoil and




TOSCO II oil shale facilities, the quantities of shale residuals are




from 8 to 33 times those from the coal conversion plants.





11.2 Site-SpecificWater Consumption and Residual Breakdowns




     To clarify how the water is consumed and from where the residuals




arise, in Figs. 11-1 to 11-3 are shown breakdowns of the consumed water




by use and of the wet solid residuals by type.  The breakdowns are given




in Fig. 11-1 for the production of 250 x 10  scf/day of synthetic natural




gas by the Lurgi and Synthane processes; in Fig. 11-2 for the production




of 100,000 bbl/day of synthetic fuel oil by the Synthoil process and




from oil shale by the TOSCO II process; and in Fig. 11-3 for the genera-




tion of 3,000 MWe of electricity by coal-fired steam generation.  The




sites are those discussed throughout the study.




     For clarity of graphical presentation, the five major water con-




sumption categories and their subcategories are combined into three




principal use groups:  (1) process and flue gas desulfurization (FGD),




(2) cooling and  (3) solids disposal, mining and other.  Although in the




detailed analyses solids disposal is broken down into a large number




of categories, for simplicity of presentation they are here combined into




the following'main groups:  (1) ash, (2) flue gas desulfurization (FGD)




sludge, (3) spent shale,  (4) coal refuse and (5) other wastes.  In the




graphs of Figs. 11-1 and 11-3, generally only two types of waste are
                                191

-------
                      250 X |06SCF/DAY
10 r
  SVNTHANE
6 -
2 -
       LURGI
                     WATER (IOSACRE-FT/YR
                 SYNTHANE
                                  SYNTHANE
       DISPOSAL
       MINING,
       OTHER
                                                   SYNTHANE
                                                         LURGI
            PROCESS (-)
         I/  a F60
   BEULAH
                   COLSTRIP
                 GILLETTE
NAVAJQ
3r
                   WET SOLIDS (I06TONS/YR)
                       'ASH
                       V  '
                             OTHER,
   BEULAH
COLSTRIP
                                    GILLETTE
                                                     NAVAJO
Fig. 11-1.   Breakdown of net annual water consumption  and
             wet solid residuals  generated in the production
             of  250 x lO^ scf/stream day of synthetic
             natural gas by the Lurgi and Synthane  processes
             at  different Western sites.
                               192

-------
14 r
12
  100,000 BBL/DAY

WATER (I03 ACRE-FT/YR}
                                                     OIL SHALE
                        MINING, DISPOSAL,
                            OTHER
                   WET  SOLIDS  (I06TONS/YR)
                                                      RIFLE
             Breakdown of net annual water  consumption and
             wet solid residuals  generated  in the production
             of 100,000 bbl/stream  day  of  fuel oil by the
             Synthoil process at  different  Western sites and
             by the TOSCO II oil  shale  process at Rifle,
             Colorado.
                           193

-------
                          3,000  MWe
16
                     WATER (!03ACRE-FT/YR )
                   DISPOSAL, MINING,OTHER
                 FGD
  BEULAH
  COLSTR1P
GILLETTE
KAIPAROWITS
                                                       NAVAJO
   ASH
                    WET SOLiDS  (I06TONS/YR)
                FGO
               SLUDGE
                I J...I I
                                           ttf-
                                           CC~
                                .
                               o:-
                              -o.-.1
  BEULAH

Fie. 11-3.
  COLSTR1P
GILLETTE
KAIPAROWITS
NAVAJO
Breakdown of  net annual water consumption and
wet solid residuals generated in the  production
of 3,000 MWe/stream day of electricity  by coal-
fired steam-electric generating plants  at
different Western sites.
                               194

-------
indicated and in Fig. 11-2 only one type, because the contributions




of the remaining types are negligibly small on the scales of the




figures.




     Process and flue Gas Desulfurizatioji (FGD) Water




     The process water requirement relates to the fact that hydrogen




is needed for the fuel conversions, and its source is water.  The




water consumed depends on the difference between the hydrogen to carbon




ratio in the coal or shale to this same ratio in the product fuel.  A




second factor in determining net consumed process water is the moisture




present in the coal or shale, which is not treated as a water input but




which may be recovered in the process.




     The consequence of these facts is evident in the findings that the




Synthane process water requirements are independent of site, amounting




to about 4.5 gal/10  Btu (1,087 acre-ft/yr).  As noted, the coal moisture




could be recovered  at a cost prior to its conversion, but this is an




economic question.  The Synthane process makes maximum use of the




hydrogen in the coal in contrast to the Lurgi process.  On the other




hand, the Lurgi process accepts wet coal and the coal moisture over-




shadows the process requirement, though the resulting dirty process




condensate must be treated at a cost.  The Lurgi process water is found




to range between a net consumption of 3,6 gal/10  Btu (869 acre-ft/yr)




at Navajo, New Mexico to a net production of 3.1 gal/10  Btu (740 acre-ft/yr)




at Beulah, North Dakota.  As we point out below, the Lurgi flue gas




desulfurization water also depends directly on the coal moisture, while




in the Synthane.process it does not because dry char is used in the




boilers.  These results taken together explain the constancy of the




Synthane process and FGD water in Fig. 11-1 and the variability with site




of the corresponding Lurgi requirements.




                                195

-------
     The crude oil product of the Synthoil plant has a hydrogen to




carbon ratio not much greater than that of the coal.  As a result,




the process water is found to range from a net consumption of only




1.6 gal/10  Btu (1,021 acre-ft/yr) at Navajo,  New Mexico to a net




production of 0.15 gal/10  Btu (95 acre-ft/yr) at Beulah, North Dakota.




This variation, illustrated in Fig. 11-2, is associated with variations




in the oxygen content of the coal.  The principal loss of water is as




a consequence of water vapor released up the stack when light hydro-




carbons produced in the process are burnt.  The process water require-




ment for the 100,000 bbl/day TOSCO II oil shale plant shown in Fig. 11-2




is about 7.3 gal/10  Btu (4,078 acre-ft/yr).  This result is large and




cannot be compared directly with the Synthoil results because the




biggest part of the consumption includes water that is vaporized and




lost in wet scrubbing of the stack gases, in moisturizing the spent




shale and in removing sulfur in the upgrading process.




     Process steam is generated in the Lurgi, Synthane and electric




power generating facilities with the concomitant generation of sulfur




dioxide in the combustion gases.  The procedures considered for the




removal of the SC>2 before it is released  to the stack are wet scrubbing




utilizing lime, limestone or both.  In these procedures water leaves




the plant as vapor in the flue gas and in the slurry of spent solids.




By far the largest quantity of water leaves as saturated vapor in the




scrubbed flue  gas and the amount  is found to  depend critically on the




flue gas temperature.   In this study a temperature  of 120F was assumed,




but a variation of 10F could give a 40%  higher water quantity.   This




is important since generally tight temperature control will be difficult
                                 196

-------
to achieve.  Apart from temperature, the largest single factor affecting




the water requirement is the moisture content of the coal fed to the




boilers.  For example, at Beulah, North Dakota only 0.10 Ibs water/lb coal




is required compared to 0.44 Ibs water/lb coal at Navajo, New Mexico




and 0.7 Ibs water/lb char in the Synthane process.  The water leaving




in the waste solids is proportional to the sulfur content in the coal




but is generally a small fraction of the total FGD requirement.  The




exception to this is when a very wet North Dakota lignite is used and the




total flue gas makeup is so small that the slurry makeup becomes a sizable




fraction of the total.





     Cooling Water




     The largest quantity of water consumed in all facilities, except




oil shale, is the water evaporated for cooling.  As is shown in Fig.




11-3, in electric power generation the cooling water dominates the total




requirement as it does to a somewhat lesser extent in the Synthoil




facilities (Fig. 11-2).  Air cooling does exist as an alternative to




cooling by evaporation, and the quantity of water used for cooling is




dictated by economic considerations.




     The process of converting coal or oil shale to another fuel or to




electricity is not, and cannot be 100% efficient.  The product fuel or




electricity always has a lower heating value or energy content than the




coal or shale input.  In the conversion of coal-to-electricity about 35%




of the energy in the feed coal leaves the plant as electricity.  In the




Lurgi or Synthane coal-to-gas plants about 65-70% of the heating value




of the feed coal leaves the plant as gas plus by-products.  In Synthoil




coal-to-oil plants about 70-75% of the heating value of the feed coal
                               197

-------
leaves the plant as fuel oil plus other products.  In shale-to-oil plants




the efficiency  is somewhat higher.  For the same energy input, the most




important factor in determining the water required for cooling in two




different plants at the same site is overall plant efficiency.  It is




for this reason that the water requirements for electrical generation




are high when compared to other processes.




     Some of the heat which is not recovered in the product or by-products




may be dissipated by evaporating cooling water.  Some of the unrecovered




heat cannot be used to evaporate water and leaves the plant in hot gases




up a flue, as water vapor from coal drying, as convective and radiant




losses from machinery and container surfaces, and in other direct ways.




About 25% of the unrecovered heat in all of the fuel-to-fuel and coal-to-




electricity plants is lost directly as described.




     In the fuel-to-fuel conversion plants (Lurgi, Synthane, Synthoil




and oil shale) another 25-50% of the unrecovered heat is dissipated at




temperatures that are over 140F in locations where wet evaporative




cooling is both wasteful of water and uneconomical.   In these cases, air




or dry cooling should be practiced.




     Whether or not to use wet evaporative cooling to dissipate the




remaining 25-50% of the unrecovered heat in the fuel-to-fuel plants and




the roughly 75% of the unrecovered heat in the electric generating




plants depends on the cost of water, buying water rights and transporting




the water to the plants,  as well as the cost of treating the circulating




cooling water and disposing of the cooling tower residues.   In the sites




of this study, these costs total in the range of from $0.40 to $2.00




per 1000 gallons of water evaporated.   It is also found that to within
                                198

-------
about 5% at all the sites, 1500 Btu are dissipated per Ib of water




evaporated in the fuel-to-fuel plants, while 1400 Btu are dissipated




per Ib of water evaporated in the electric generating plants.  This




translates into a range of $0.03 to $0.17 per 10  Btu of unrecovered




heat dissipated.




     To save the water cost dry cooling must be used.  However, when




cooling to low temperatures the capital cost of such cooling is high.




In addition, in all of the plants a large part of the unrecovered heat




is dissipated in the condensers of steam turbines used to drive gener-




ators, gas compressors and other machinery.  The lower is the condenser




temperature, the less is  the steam requirement for a constant shaft




power in a steam turbine.  The result, therefore, is that dry cooling




also involves a fuel penalty, since it does not cool down to as low a




temperature as does wet cooling.




     In the electric generating plants the most important point of loss




of unrecovered energy is  in the turbine condensers.  The heat lost in




these condensers is about 48% of the  heating value of the feed coal and




about 75% of the unrecovered heat lost from the plant.  The character-




istics of the turbines are such that  the added capital cost of dry




cooling plus the fuel penalty dictate wet cooling, unless cooling water




costs about $4.63 per 1000 gallons evaporated.  The water quantities




listed in this study are  all based on wet cooled condensers.




     At Navajo/Farmington, New Mexico a wet/dry tower calculation for




electric generation is carried out.   It is shown that when water costs




about $2.20 per  1000 gallons, partial dry cooling is more economical than




all  wet cooling.  If a water cost of  $2.20 per 1000 gallons of water is
                                 199

-------
used at all the sites, then except for Gillette, Wyoming all evaporative




cooling systems would still be preferred if sufficient water is avail-




able.  At Gillette the choice of an all evaporative cooling system is




marginal.  However, a savings in total water consumed in the cooling




tower of about 75% of that required by all evaporative cooling is made




at the expense of only 50% of the difference in evaluated costs between




dry and all evaporative cooling.




     In the Synthoil and Synthane plants wet cooling is used at all




sites for the steam turbine condensers, gas compressor interstage coolers




and selected final cooling of process streams.  Depending on the site




and process, between 42 and 54% of the unrecovered heat is taken to be




dissipated by wet cooling.  Cooling water requirements for the Lurgi plants




are taken from existing designs and are about 2/3 that for Synthane except




at Navajo, New Mexico where they are about 1/2.  Wet/dry combination




cooling is not examined.  Wet/dry cooling can reduce the cooling water




requirement to about 25% of that used and probably becomes economically




viable when cooling water costs $1 to $1.50 per 1000 gallons evaporated.




Thus at a site such as Gillette, Wyoming the stated cooling water require-




ments are certainly generous.




     In Lurgi process plants, 28% of the unrecovered heat is assumed to




be dissipated by wet cooling at all sites.  This number comes from




designs made for New Mexico and may be uneconomical, for example, in




North Dakota.





     Water for Solids Disposal, Mining and Other Uses




     All solid residuals that leave the plant boundaries generally do




so wet, and this water constitutes most of the water consumption associated
                                200

-------
with disposal.  From the study findings, the weight of water as a
fraction of the total weight of wet solid residuals is found to vary
with site over the ranges indicated in Table 11-3.
          Table 11-3.  Weight of water as a percent of total
                       weight of wet solid residuals.
                                    Water  in Wet Solids
              Facility                    (wt. %)	
              Lurgi                       25-31
              Synthane                    22-29
              Synthoii                    24-25
              Electric  Generation        32-43
              Oil Shale                   13
      As  an approximate estimate we may say that  the  Lurgi,  Synthane  and
 Synthoii facilities average a weight percent of  water  in the wet  solids
 in a range around 25%, with the Lurgi facility at the  high end of the
 range.   This figure is simply related to the fact that the predominant
 solid waste from these processes is ash, as ""illustrated in Figs.  11-1 and
 11-2.  The variation in range relates to the fraction  of waste that  is
 bottom ash, fly ash or FGD sludge, since they each require somewhat
 different quantities of water for disposal.  The percent water in the wet
 solids is in a range around 38% for electric power generation.  This is
 related to the fact that in most cases, except for the very high ash
 Navajo coal, the FGD sludge represents about half the  solid waste.  The
 other exception is at Kaiparowits where the largest fraction of the
 solid waste is coal refuse from coal cleaning with a 30% weight of water.
                                  201

-------
Both at Navajo  and Kaiparowits  the  weight  percent  of water  is  at  the



low end of  the  range.  The  13 weight  percent water for  the  TOSCO  II



oil shale facility simply represents  the weight percent water  in  the



spent shale, which constitutes  essentially the entire solids disposal.



     In surface mining the  largest  use  of  water is for dust control at



the mine, on the roads, in  crushing and in handling.  The exception to



this is when water is required  for  revegetation, which for  the sites



examined is only necessary  at Navajo/Farmington, New Mexico.   In  under-



ground mining,  which is considered  only for Kaiparowits, the largest



quantity of water is required for coal  washing.  The actual quantities



of water needed are quite site  and  process  specific, depending on the



rate of coal mined and area stripped.   Other losses include evaporative



losses which are, of course, site-specific.  As a  very rough rule, for



the Lurgi, Synthane and electric generation facilities in the  graphs of



Figs. 11-1 to 11-3, the mining  water at Navajo is  about 65% of that for



solids disposal and other uses.  At Gillette and Colstrip it is about



75% and at Beulah about 130%.   The  corresponding figures for the



Synthoil facilities are 50%, 60% and 90%.   These percentages are  quite



approximate and intended only to give some  idea as to how the mining



and solids disposal categories break down in the summary graphs.  The



oil shale mining and disposal use in Fig. 11-2 is  split between


        3                                   3
1.8 x 10  acre-ft/yr for mining and 4.1 x 10  acre-ft/yr for solids



disposal and other uses.  At Kaiparowits, because of the coal cleaning



requirements,  most of the water shown in Fig.  11-3 for disposal,



mining and other uses is actually for mining,  into which category coal



washing is placed.
                                202

-------
     Residuals




     As shown in Fig. 11-2, by far the largest residual is the spent




shale generated in surface oil shale processing.  The dry weight of




the spent shale is 82% of the originally mined shale and with the




moisturizing water it has a weight equal to 94% of the feed shale.  Of




particular environmental importance in the TOSCO II process is that




the moisturizing water added to the spent shale leads to cementation




of the shale and freezing in of the water after compaction.  Were this




not the case, severe leaching problems could ensue.




     In the Synthane, Lurgi and Synthoil processes, ash is the principal




solid residual.  The quantities of ash are very site-specific because




of the differences in coal heating values and ash content.  The Navajo,




New Mexico coal with an ash content of 25.6% is a particularly high




ash coal, so that the quantities of wet-solid residuals at this site




are several times those from the other sites with the same facilities.




     Particularly large quantities of solid wastes in electric power




generation are generated by flue gas desulfurization.  The weight of




the resultant wet sludges ranges from 70-130% the weight of the wet




ash, except at Navajo/Farmington where it is 42%.  Large quantities of




solid waste are also generated whenever it is necessary to clean the




coal, as is the case in the electric power generation facility at




Kaiparowits.  The weight of wet coal refuse there is more than 3 times




the combined weight of the FGD and ash residuals.




     Emphasis is placed here on the quantities of material to be disposed




of and not on their toxicity or hazardous character.  In this regard




it is to be emphasized that although the residuals discussed are in
                                203

-------
general harmless, they nevertheless do contain trace quantities of




harmful elements and compounds.  It is possible that the disposal




of the large quantities of residuals noted could lead to a collective




problem in the dispersion of the hazardous materials.





11.3 Regional Water Consumption and Residuals




     Fig. 11-4 summarizes the study findings on the aggregated net




annual water consumption and wet solid residuals generated in the region




of the West in which energy development is focused.  The three levels




of energy development are based on the Stanford Research Institute




energy model with low end-use demand, nominal end-use demand and low




nuclear availability.




     For each level of energy development, it is found that the aggre-




gated net water consumption increases by a factor of 9-10 between the




years 1980 and 2000, while during the same period the wet solid residuals




increase by a factor of 75-100.  This large increase in residuals beyond




1980 is associated with the spent shale from surface oil shale processing.




     On the basis of the quantities of water consumed and residuals




generated, -Colorado appears to be the state most affected by energy




development in the Rocky Mountain Region.  This is due principally to




the projected rapid growth of a surface processing oil shale industry.




Montana is the most affected state in the Powder River Region, princi-




pally because of the projected growth of slurry pipeline development and




electric power generation.  The actual environmental impacts of siting




synthetic fuel and electric power generation facilities cannot, however,




be properly assessed without an appropriate determination of local and




regional water supply and demand data, and residual disposal methods.
                                  204

-------
2600
2200
 1800
 1400
1000
 600
 200
                       WATER (I03ACRE-FT/YR)
 320
 240
  160
  80
    LOW DEMAND

[   1 NOMINAL DEMAND

    LOW NUCLEAR
        1980
                1985
1990
              WET SOLIDS (IO$TONS/YR)

      SPENT  SHALE             .<-_
                                    I
        1980

   Fig. 11-4.
                1985
1990
2000

                                                            2000
                      1600
                                                     1200
                                                     800
                                                     400
2000
       Regional net annual water consumption and wet
       solid residuals generated in the Western coal and
       oil shale areas between the years 1980 and  2000
       for three levels of energy development.
                              205

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                  APPENDIX A.  COAL ANALYSES



      Coal analyses are required for carrying out the hydrogen

 balances described in Section 2,  for determining the solid resi-

 duals in flue gas desulfurization, as described in Section 6,

 for determining mine and process  coal tonnage requirements

 (Section 7),  and for calculating  the quantity of bottom and fly

 ash to be disposed of (Section 8).  The coal analyses are given

 in Table A-l  on a wet and dry basis for each of the six sites.



 References

 1.    Michigan Wisconsin Pipe Line Co.  and  ANG Gasification Co.,
      Application for Certificates of Public Convenience and
      Necessity," Exhibit Z-6,  p.  4,  Federal Power  Commission
      Docket CP75-278,  1974.

 2.    Ibid.,p.  2.

 3.    Converted to  dry  basis  from  data  given in Ref.  1.

 4.    "Trials  of  American Coals  in a  Lurgi  Gasifier  at   Westfield,
      Scotland,"  p.  55,  Research and  Development  Report  No.  FE-105,
      Energy Research  and Development Administration, Washington,
      B.C., November  1974.

 5.    Converted  to  dry  basis  from  data  given in Ref.  4.

 6.    SERNCO,  "Applicants' Environmental Assessment  for  a Proposed
      Gasification  Project in Cambell and Converse Counties, Wyoming,
      Prepared for  Wyoming Coal  Gas Co. and  Rochelle  Coal Co.,"
      p. E-34,  October  1974.

 7.    Converted to  dry basis from  data  given in Ref.  6.

 8.    "Kaiparowits  Project Final Environmental  Impact Statement,"
     Vol. I,  p.  1-92, Bureau of Land Management, U.S. Department
     of the Interior, Washington,  B.C., March  3, 1976.

9.   Converted to  dry basis from data  given  in Ref.  8.
                              206

-------
10.   Batelle Columbus Lab oratories,  "Detailed  Environmental Analysis
     Concerning a Proposed Gasification  Plant for Transwestern Coal
     Gasification Co., Pacific Coal Gasification Co., Western Gasi-
     fication Co., and ttie Expansion of  a  Strip Mine Operation Near
     Burnham, New Mexico  Owned and  Operated by Utah International
     Inc.," p. 3.11, Federal Power  Commission, Feb. 1, 1973.

11.   Approximation from data in El  Paso  Natural Gas Company, "Second
     Supplement to Application for  Certificate of Public Convenience
     and Necessity," Section Z-2, p.  II-C-1,  Federal Power Commission
     Docket CP73-131, 1973, to conform with proximate analysis.

12.   A high volatile B btuminous coal as  is  appropriate to  the region.

13.   Hamshar, J.A., Terzan, H.D.,  and Scotti, L.J., "Clean  Fuels  from
     Coal by the COED Process," in  Symp. Proceedings: Environmental
     Aspects of Fuel Conversion Technology (May 1974, St. Louis, Mo.),
     p. 174, EPA Technology Series  Rept. No.  EPA-650/2-74-118, Office
     of Research and Development, Environmental Protection Agency,
     Washington, D.C., October 1974.

14.   Converted from dry basis from  data  given in Ref. 13.
                              207

-------
                                                    Table A-l,   Coal analyses.

As received
Proximate Analysis, Wet Basis
Moisture, wt. %
Ash, wt, %
Volatile Matter, wt. %
Fixed Carbon, wt. %
Volatile Matter -f Fixed Carbon, wt. 7,
Total
Sulfur
Higher Heating Value, BTU/lb
Ultimate Analysis, Dry Basis
Carbon, wt. %
Hydrogen, wt. %
Nitrogen, wt. 7,
Sulfur, wt. %
Chloride, wt. %
Ash, wt. %
Oxygen by Difference, wt. %
Total
BEULAH,
NORTH DAKOTA
Ref. 1
35.98
7.42


56.6
100.0
0.71
6,822 2
Ref. 3
63.17
4.25
1.27
1.11
0.02
11.59
18.59
100.0
COLSTRIP,
MONTANA
Ref. 4
24.70
9.73
29.20
36,37

100.0
1.16
8,611
Ref. 5
67.15
4.22
1.20
1.45
0.04
12.92
13.02
100.0
GILLETTE,
WYOMING
Ref. 6
28.0
5.6
32.7
33.7

100.0
0.32
8,449
Ref. 7
68.63
4.70
0.69
0.45
0.04
7.75
17.74
100.0
KAIPAROWITS/
ESCALANTE,
UTAH
Ref, 8
14.8
7.0
36.0
42.2

100.0
0.42
10,800
Ref. 9
72.24
5.08
1.15
0.49
0.02
8.22
12.80
100.0
NAVAJO/
FARMINGTON ,
NEW MEXICO
Ref. 10
12.4
25.6
28.2
33.8

100.0
0.91
8,310
Ref. 11
53.97
3.95
0.89
1.04

29.22
10.93
100.0
RIFLE, 1?
COLORADO
Ref. 13
6.4
6.0
39.0
48.6

100.0

13,010
Ref. 14
75.8
5.8
1.7
0.6
0.004
6.4
9.7
100.0
o
00

-------
       APPENDIX B.  WATER ANALYSES AND PRECIPITATION
                    AND EVAPORATION RATES



     Feed water analyses are required to determine the solid

residuals found in the blowdown of process water treatment

plants and cooling towers and the need for settling basins.

Table B-l shows the source of feed water for each of the plant-

site combinations considered in the assessment.  Table B-2 gives

the quality of each of the source waters.  Unless otherwise indi-

cated, the analyses have been supplied to us by the Radian Cor-
                        *
poration, Austin, Texas.

     Precipitation and evaporation data at each of the six sites

are presented in Table B-3.  These data have been used to estimate

the water requirements for dust control on the mine area and haul

roads  (Section 7.3), supplemental irrigation water required for

revegetation  (Section 7.8), and the evaporation losses from settling

basins (Section 8.8) and reservoirs (Section 8.9).
References
1.   "Environmental  Impact  Report, North Dakota Gasification Project,"
     for ANG Coal Gasification  Co., p.  2-244, FPC Docket No. CP75-278,
     Vol. Ill, March 5,  1975.

2.   Data is weighted average for Bighorn River at Bighorn,Montana
     (Yellowstone River  Basin near Colstrip) from "Quality of- Surface
     Waters of the United States, 1968, Part 6: Missouri River Basin,"
     p. 125, Geological  Survey  Water-Supply Paper 2098, 1973.  Average
     based otiyearly  discharge and load.
 Sethness, E.D., private  communication.
                              209

-------
 3.   Ibid., p. 65.  For Bluewater Creek at Fromberg, Montana based
     on yearly discharge and load.

 4.   Ibid., p. 158.  For North Platte River at Orin, Wyoming.  Time
     weighted average over year.

 5.   Weighted average data for Colorado River at Lees Ferry, Arizona
     taken from "Quality of Surface Waters of the United States, 1968,
     Parts 9 and 10: Colorado River Basin and the Great Basin," p.
     156, Geological Survey Water-Supply Paper 2098, 1973.

 6.   Ibid., p. 157.  Lower value most probable.  Upper value time
     averaged.

 7.   Data is averaged for San Juan River at Farmington, New Mexico
     from U.S. Geological Survey, Water Supply Papers No.2015 (1967),
     2098 (1968), and 2148 (1969).

 8.   Data for Colorado River above Grand Valley from "An Environ-
     mental Impact Analysis for a Shale Oil Complex at Parachute
     Creek, Colorado, Part I: Plant Complex and Service Corridor,"
     Table 7, p. 43, Colmy Development Operation, Atlantic Rich-
     field Co., Denver, 1974.

 9.   Ibid, Appendix 12 (Chemical Water Quality Characteristics of
     Parachute Creek, p.  29).  Straight average of raw data.

10.   For Colorado River near Cisco, Utah based on yearly discharge
     and load.  "Quality of Surface Waters of the United States,
     1968, Parts 9 and 10: Colorado River Basin and the Great Basin,"
     p. 48, Geological Survey Water-Supply Paper 2098, 1973.

11.   According to Weeks,  et al., "Simulated Effects of Oil Shale
     Development on the Hydrology of Piceance Basin, Colorado,"
     U.S. Geological Survey Professional Paper 908, 1974,  only
     tract C-b could supply sufficient ground water from the mine
     to meet development plans.  In this case, 2/3 of discharge
     is from upper aquifer and 1/3 from lower aquifer.  Data
     given represents 2/3 - 1/3 weighting of mean from upper and
     lower aquifers as given in Table 6,  p. 35 of cited reference.

12.   Geraghty, J.H. et al., Water Atlas of the United States, Plate
     12, Water Information Center, Inc.,  Port Washington,  New York,
     1973.

13.   Climates of the States, Vol. II - Western States, p.  757,
     Water Information Center, Inc., Port Washington, N.Y.,  1973.
                              210

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Table B-l.  Source of feed water.
PROCESS
SLURRY PIPELINE
LURGI GAS
SYNTHANE GAS
SYNTHOIL GAS
ELECTRICAL GENERATION
3000 MWe
1000 MWe
OIL SHALE
50,000 bbl/day
100,000 bbl/day
BEULAH,
NORTH DAKOTA

Lake
Sakakawea
Lake
Sakakawea
Lake
Sakakawea
Lake
Sakakawea

COLSTRIP ,
MONTANA

Yellowstone
River
Yellowstone
River
Yellowstone
River
Yellowstone
River

GILLETTE,
WYOMING
North Placte
River
Yellowstone
River
Yellowstone
River
North Platte
River
Yellowstone
River

KA1PAROWITS/
ESCALANTE,
UTAH




Lake
Powell

NAVAJO/
FARMINGTON,
NEW MEXICO

San Juan
River
San Juan
River
San Juan
River
San Juan
River

RIFLE,
COLORADO




White
River
Colorado
River
Groundwater

-------
Table B-2.  Source water quality.

Dissolved Calcium
(mg/ as CaCOj)
Dissolved Magnesium
(og/ as CaCOj)
Dissolved Sodium
(rng/i as CaCOj)
Dissolved Chloride
(mg/i as CaCOj)
Dissolved Bicarbonate
(mg/Z. as CaCOj)
Dissolved Sulfate
(mg/i as CaCOj)
Dissolved Silica
Total Dissolved Solids
(n.g/1)
Suspended Sediment (mg/i)
Hardness (mg/ as CaCOj)
pH Units
BEULAH,
NORTH DAKOTA
Lake
Sakakawea
123
78
129
13
148
177
7
428
21
201
8.1
COLSTRIP,
MONTANA
Yellowstone
River
99
56
75
8
113
113
10
284
365 2
155
8.2
GILLETTE,
WYOMING
Yellowstone
River
115
66
98
10
131
148
12
364
371 3
181
7.7
GILLETTE,
WYOMING
North Platte
River
153
82
109
17
139
197
10
414
320 4
235
8.2
KAIPAROWITS/
ESCALANTE,
UTAH
Lake
Powell
213
122
205
99
149
292
105
677
5-15 6
335
7.6.
KAVAJO/
FASMINGTON,
NEW MEXICO
San Juan
River
138
37
68
12
117
118
12 7
300
278
175
7.8
RIFLE,
COLORADO
White
River
99
35
19
13
93
47
10
181
663
134
8.0
RIFLE,
COLORADO
Colorado
River
158
53
205
168
118
134
12 9
454
2087 10
211
8.0
RIFLE,
COLORADO
Cround-
Wacer
115
41
3198
666
2788
250

3773

156


-------
Table B-3.   Precipitation and evaporation data (inches/year).

Precipitation
Lake Evaporation Rate
(70% Pan)
Pond Evaporation Rate
(90%^ Pan)
Pan Evaporation Rate
BEULAH,
NORTH DAKOTA
15 I
3512
45
50
COLSTRIP ,
MONTANA
14 13
38 12
49
54
GILLETTE,
WYOMING
14 14
42 14
54
60
KAIPAROWITS"/
ESCALANTE,
UTAH
g15
54 12
69
77
NAVAJO/
FARMINGTON,
NEW MEXICO
816
47.5 12
61
68
RIFLE,
COLORADO
12 17
35 12
45
50

-------
                  APPENDIX C.  LOAD FACTORS



     A load factor for a plant is defined as the percentage of time

that a plant is on-stream throughout the year.  The load factor for

each of the unit size mine-plant complexes is given in Table C-l.

Throughout this report rate quantities are specified based on either

a "stream" time unit or a "calendar" time unit; for example, gallons

per stream minute or gallons per calendar minute.  The ratio of a

calendar time to a stream time is the load factor.  For example, for

a plant having a load factor of 90%, 10 gallons per stream minute =

9 gallons per calendar minute.  All rate quantities  based on a cal-

endar time unit can be converted to a yearly basis by multiplying

the quantity by 365 days, or 365 x 24 = 8760 hours, or 365 x 24 x 60

= 525,600 minutes.  For example, 10 gallons per calendar minute =

5,256,000 gallons per year.  The year as a time unit is a calendar

time unit.



Reference

1.  Raye, T.D., Memorandum to J. White, Radian Corporation, Austin,
    Texas, April 26, 1976.
                              215

-------
             Table C-l.   Load factors.
                                    Load Factor
Slurry Pipeline                       100%




Lurgi                                  90%




Synthane                               90%




Synthoil                               90%




Steam-Electric Generation              70%




Oil Shale                              90%
                          216

-------
       APPENDIX D.  TOTAL WATER CONSUMED AND RESIDUALS
             GENERATED FOR THREE ENERGY SCENARIOS
                     BY STATE AND COUNTY
     Reference 1 establishes the temporal and spatial regional sce-
narios for levels of western energy development used in this assess-
ment.  The scenarios are based on the Stanford Research Institute
energy model with nominal end-use demand, low end-use demand, and
low nuclear availability cases.  The regional scenarios focus on
the Powder River Region, which includes the states of Montana, North
Dakota, and Wyoming; and the Rocky Mountain Region, which includes
the states of  Colorado, New Mexico, and Utah.  Further disaggregation
of regional facilities  to Counties within the States was performed on
the basis of published  resources.  For each level of western energy
development and  for each region,  the  time frames considered are  the
years  1980, 1985,  1990, and 2000.  The total water  consumed and
residuals generated by  State and  County are presented in this appendix.
      The  results of the regional  scenarios are based on the results
of  the site-specific scenario  calculations presented in Section  10.
The total water  consumed  and residuals generated for each  plant-County
 combination given in Ref.  1 were  the  same  as  for one of the (site -
 specific) plant-site combinations considered  in  Section 10.   A plant-
 County combination was matched to a plant-site combination on the
 basis of coal type, water source, and climate.   We found  the base
 quantities to be the same for all Counties considered  within a  given
                                217

-------
State.  Table D-l shows the base quantities used to calculate the

total water consumed and wet-solids residuals generated by State

for the unit size mine-plant complexes shown in the table.

     Table D-2 shows the page number on which the results for

specific scenarios are presented in this appendix.



Reference


1.   Conine, W.D., "Regional Scenario Definitions for Levels of
     Western Energy Development Corresponding to Nominal Demand
     Low Demand, and Nuclear Moratorium Assumptions," Radian Cor-
     poration, Report No. 100-090-07-01, Austin, Texas, June 22
     JL./ / O 
                              21-8

-------
                                           Table D-l.  Base quantities ass
-------
Table D-2.  Location of results for specific scenarios by
            region, energy demand, and year.



Nominal Demand
1980
1985
1990
2000
Low Demand
1980
1985
1990
2000
Low Nuclear
Availability
1980
1985
1990
2000
Page Number
Rocky Mountain
Region

221
222
223
224

225
226
227
228


229
230
231
232
Powder River
Region

233
234
235
236

237
238
239
240.


241
242
243
244
                                220

-------
         CASE
                  NOMINAL DEMAND
         FACILITIES  SITED It! ROCKY MOUNTAINS REGION BY  1980 (AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Gar fie Id
TOTAL
NEW MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAL
UTAH
Garfield
Kane
Uintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*


















WET SOLIDS'
106 TON/YR


















LURGI GAS
ACRli-
FT/YR*


















WET SOLIDS*
106 TON/YR


















SYNTHAI..: GAS
ACKE-
FT/YR*


















WET SOLIDSt
106 TON/YR


















SYNTHOIL
ACRE-
FT/YR*


















WET SOLIDSt
106 TON/YR


















ELECTRICAL GENERATION
ACRE-
FT/YR*







29,206




29,206


29,816

29,816
WET- SOLIDSt
106 TON/YR







5.00




5.00


5.30

5.30
OIL SHALE
ACRli-
PT/YR*


















WET SOLIDS"
106 TON/YR


















to
          * Water Censured
          t Residuals

-------
        NOMINAL DEMAND
FACILITIES SITED IN ROCKY MOUNTAINS  REGION BY 1985  (AFTER 197i
STATS/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
NEW MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAL
UTAH
Garfield
Kane
Uintah
TOTAI.
SLURRY PIPELINE
ACRE-
FT/YR*


19,171


19,171












ET SOLIDS1'
106 TON/YR


_


-












LURGI GAS
ACRE-
FTAR*


















WET SOLIDSt
106 TON/YR


















SYNTHAIT: GAS
ACRE-
PT/YR*


















rfET SOLIDSt
106 TON/YR


















SYNTHOIL
ACRE-
FT/YR*


















WET SOLIDSt
106 TON/YR


















ELECTRICAL GENERATION
ACRE-
FT/YR*



28,482

28,482

29,206




29,206


29,816

29j8l6
MET SOLIDSt
106 TON/YR



1.14

1,14

5.00




S.OO


5.30

5.30
OIL SHALE
ACRE-
PT/YR*



25,848

25,848












VET SOLIDST
106 TOH/YR



81.62

81.62












* Kator Consumed
t Residuals

-------
        NOMINAL DEMAND
FACILITIES SITED IN ROCKY MOUNTAINS REGION By
                                                    (AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
NEW MEXICO
San Juan
Lea
Poosevelt
Cftavos
Eddy
TOTAL
UTAH
CarfUld
Kane
Uintah
TOTAL
SLURM PIPELINE
ACRE-
FT/YR*


19,171


19,171












WET SOLIDS1'
106 TONAR


-


-












EORGI GAS
ACRE-
PT/YR*


















WET SOLIDSt
106 TON/YR


















SYNTHA..E GAS
ACRE-
FT/YR*


















MET SOLIDSt
106 TON/VR


















SYHTHOII.
ACRE-
FT/YR*


















WET SOLIDSt
106 TON/lfR


















ELECTRICAL GENERATION
ACRE-
FT/YR*



28,482

28,482

29,206




29,206

29 , 816
29,816

59,632
MET SOLIDSt
10* TON/YR



1.14

1.14

5.00




5.00

5.30
5.30

10.60
OIL SBRLE
ACKE-
FT/YR*



51,696
12,924
64,620












WET SOLIDS'?
106 TOM/XR



163.24
40.83
204.05












 * Water Consumed
 t Residuals

-------
          CASE
                   NOMINAL DEMAND
          FACILITIES SITED  IN  ROCKY MOUNTAINS  REGION BY 2000  (AFTER 1975}
STATE/COUNTY


ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
NEW MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAL
UTAH
Garfield
Kane
Dintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*


19,171


19,171












WET SOLIDS'
106 TON/YR


-


-












LURGI GAS
ACRE-
FT/YR*







5,639




5,639





WET SOLIDSt
106 TON/YR







3.00




3.00





SYNTHAiffi GAS
ACRE-
FT/YR*







8,670




8,670





WET SOLIDS*
106 TON/YR







2.84




2.84





SYNTHOIL
ACRB-
PT/YR*


















WET SOLIDST
106 TON/YR


















ELECTRICAL GENERATION
ACRE-
FTAR*



28,482

28,482

29,206




29,206

29,816
29,816

59,632
WET SOLIDSt
106 TON/YR



1.14

1.14

5.00




5.00

5.30
5.30

10.60
OIL SHALE
ACRE-
FT/YR*



336,024
155,088
491,112










51,696
51,696

-------
          CASE
          FACILITIES SITED IN FQCKY MOUNTAINS REGION BY  198 (AFTER I97S)
STATE/COOHTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Gar fie Id
TOTAL
t!EW KEXIOO
San Juan
Lea
Boose velt
Chaves
Eddy
TOTAL
OTAH
Garfield
Kane
Uintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*


















WET SOLIDS'
106 TON/YR


















LUR6I GAS
ACRE-
FTAR*


















WET SOLIDSt
106 TON/YR


















SYNTIIAT:E GAS
ACRE-
FTAR*


















WET SOLIDSt
106 TON/YR


















SYNTHOIl
ACRE-
PT/YR*


















WET SOLIDSt
106 TON/YR


















ELECTRICAL GENERATION
ACRE-
PT/YR*















29,816

29,816
WET SOLIDSt
ZO6 TON/YR















5.30

5.30
OIL SHALE
ACRE-
PT/YR*


















CT SOLI^St
106 TON/YR


















to
K>
Ul
          * Water Consuned
          t Residuals

-------
CASE  LOW DEMASP,
FACILITIES SITED IN  BOCKY MOUNTAINS  REGION BY  1985 (AFTER 1975}
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
HSW MEXICO
San Juan
Lea
Koosevelt
Chaves
Eddy
TOTAL
 UTAH
Garfield
Kane
Uintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*


19,171


19,171












WET SOLIDS1'
106 TON/YR


-


-












LURCI GAS
ACRE-
FTAR*


















WET SOLIDSt
106 TON/YR


















SYNTHAi:; GAS
ACRE-
FT/YR*


















WET SOLIDSt
106 TON/YR


















SYNTHOIL
ACRE-
FTAR*


















WET SOLIDS'^
106 TON/YR


















ELECTRICAL GENERATION
ACRE-
FT/YR*







29,206




29,206


29,816

29,816
WET SOLIDSt
106 TON/YR







5.00




5.00


5.30-

5.30
OIL SHALE
ACRE-
FT/YR*



25,848

25,848












VET SOLI!3at
O6 TOM/YR



81.62

81.62












* Hater Consused
t Residuals

-------
           CASE
                  LOW DEMAND
           FACILITIES SITED IN ROCKY MOUNTAINS REGION BY  199 (AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
NEW MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAL
UTAH
Cat-field
Kane
Uintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*


19,171


19,171












rfET SOLIDS'-'
106 TON/YR


-


-












LURGI GAS
ACRE-
FT/YR*


















WET SOLIDSt
106 TON/YR


















SYNTIiATIE GAS
ACRE-
FT/YR*


















WET SOLIDSt
106 TON/YR


















SYNTHOIL
ACRE-
FT/YR*


















WET SOLIDSt
106 TON/YR


















ELECTRICAL GENERATION
 ACRE-
FT/YR*







29,206




29,206


29,816

29,816
WET SOLIDSt
106 TON/YR







5.00




5.00


5.30

5.30
OIL SHM-S
ACRE-
FT/YR*



51,696
12,924
64,620












" SOLIBST
106 TON/YR



163,24
40.81
204.05












to
S3
           * Kater Consumed
           t Residuals

-------
          CASE   LOW
          FACILITIES SITED IN' ROCK! MOUNTAINS REGION BY
                                                         2000
                                                               (AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huecfano
Rio Blanco
Gar fie Id
TOTAL
NEW MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAt.
UTAH
Garfield
Kane
Uir.tah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*


19,171


19,171












rfET SOLIDS'5'
106 TON/YR


-


-












LURGI GAS
ACRE-
FTAR*







5,639




5.639





WET SOLIDSt
106 TON/YR







3.00




3.00





SYNTMME GftS
ACRE-
FT/YR*


















WET SOLIDSt
106 TON/YR


















SYNTHOIL
ACRE-
FT/YR*


















WET SOIJDST
106 TON/YR


















ELECTRICAL GENERATION
ACRE-
FT/YR*







29,206




29,206


29,816

29 , 816
iET SOLIDSt
106 TON/YR







5.00




5.00


5.30

5.30
OIL SHALE
ACKE-
FT/YR*



271,404
142,164
413,568










38,772
38,772
VET SOLICST
106 TON/YR



857.01
448.91
1,305.92










122.43
122.43
CO
          *  Water Constimed
          t  Residuals

-------
            CASE LOW HUCLEAR AVAILABILITY
            FACILITIES SITED IS SOCKY KOUHTAINS  REGION  BY  . 1-980 {AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
HSU MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAL
UTAH
Garfield
Kane
Uintah
TOTAL
SLURRY
ACRE"
FT/YR*


















PIPELINE
HET SOLIDS*
106 TON/YR


















LURGI GAS
ACRE-
FT/VR*


















WET SOLIDgt
106 TON/YR


















SYNTHAME GAS
ACEE-
FT/YR*


















WET EOLIDSt
106 TON/YR


















SYNTHOIL
ACRE-
FT/YR*


















WET SOLIDSt
106 TONAR


















ELECTRICAI. GENERATION
ACRE-
FT/YR*







29,206




29,206


29,816

29,816
WET SOLIDSt
106 TON'/YR







5.00




S.OO


5.30

5.30
OIL SHALE
AC8E-
PT/YR*


















WET SOI.ID5T
106 TON/YR


















NJ
VO
            * Katcr Consuaed
            t Reiiduals

-------
             CASE LOW NUCLEAR AVAILABILITY
             FACILITIES SITED IN ROCKY MOUNTAINS REGION BY  3.985 (AFTER  1975)
STATE/COUNTY
ARIZONA
COLORADO
Hucrfano
Rio Blanco
Garfield
TOTAL

NEK MEXICO
San Juan
Lea
Soosevelt
Chaves
Eddy
TOTAL
UTAH
Garfieid
Kane
Ointsh
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*


19,171


19,171













WET SOLIDS7
106 TONAR


_
















LURGI GAS
ACRE-
FTAR*



















WET SOLIDSt
106 TON/YR



















SYN-MAI.3 GAS
ACRE-
PT/YR*






VJET SOLIDSt
106 TON/YR






I
























SyNTHOIt
ACHE-
FT/YR*



















)ET SOLIDS+
106 TON/YR



















ELECTRICAL GENERATION
ACRE-
FT/YR*



28,482

28,482


58,412




58,412

29,816
29,816

59,632
VET SOLIDSt
O6 TON/YR



1.14

1.14


10.00




10.00

5.30
5.30

10.60
OIL SHALE
ACRE-
FT/YR*



25,848

25,848













vET SOLIDST
106 TOM/YR



81.62

81.62













ro
w
o
            * Water  Consumed

            t Residuals

-------
CASE tOW NUCLEAR AVAILABILITY
FACILITIES SITED IN ROCK* MOUNTAINS REGION BY  1990 (AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
NEW MEXICO
San Juan
Lea
Koosevelt
Chaves
Eddy
TOTAL
UTAH
Garfield
Kane
Uintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*


19,171


19,171












WET SOLIDS'^
106 TON/YR


-


-












LURGI GAS
ACRE-
FT/YR*


















WET SOLtDSt
106 TON/YR


















SYNTHA"E GAS
ACRE-
FTAR*


















WET SOLIDSt
106 TON/YR


















SYNTHOIL
ACRE-
FT/YR*


















WET SOLIDSt
106 TONAR


















ELECTRICAL GENERATION
ACRE-
FTAR*



28,482

28,482

58,412




58,412

59,632
29,816

89,448
WET SOLIDSt
106 TON/YR



1.14

1.14

10.00




10.00

10.60
5.30

15.90
OIL SHALE
ACRE-
FT/YR*



51,696

51,696












WET SOLIDST
106 TON/YR



163.24

163.24












* Water Consumed
t Residuals

-------
          CASE'
                    NUCLEAR AVAILABILITY
          FACILITIES  SITED IN ROCKY MOUNTAINS REGION DY 200 (AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
NEW MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAL
UTAH
Garfield
Kane
Uintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*


38,342


38,342












VET SOLIDS*
106 TON/YR


-


-












LURGI GAS
ACKE-
FTAR*







5,639




5,639





WET SOLIDSt
106 TON/YR







3.00




3.00





SYNTllANi! GAS
ACRE-
PT/YR*







8,670




8,670





IET SOLIDSt
106 TON/YR







2.84




2.84





SYNTHOIL
ACRE-
FTAR*


















WET. SOLIDS*
10S TON/YR


















ELECTRICAL GENERATION
ACRE-
FT/YR*



28,482
28,482
56,964

87,618




87,618

59,632
59,632

119,264
ET S'OLIDSt
O6 TON/YR



1.14
1.14
2.28

15.00




15.00

10.60
10.60

21.20
OIL SHALE
ACBE-
FT/YR*



323,100
155,088
478,188










51,696
51,696
ET SOLIDST
O6 TOM/YR



1,020.25
489.72
1,509,97










163.24
163.24
N>
to
IS5
          " Hater Consumed
          t Residuals

-------
                  NOMINAL DEMAND
            FACILITIES SITED IN POWDER RIVER REGION BX 1980  (AFTER 1975)
STATE/COONTY

MONTANA
Povdcr River
Big Horn
Rosebud
Custer
Wlbaux
Richland
Mccone
TOTAL.
NORTH DAKOTA
Billings
Bovoian
Dunn
Hettinger
KcKenzie
Mctean
Mercer
Morton
Oliver
Slope
Stark
Ward
William
TOTAL
WYOMING
Caccbell
Johnson
Sheridan
TOTAL
SLURRY PIPELINE
ACRE-
FTAR*

























19,171


19,171
WET SOLIDS'
106 TONAR

























-


-
LOSS! GAS
ACRE-
FTAR*





























WET SOLIDS T
106 TON/YR





























SYNTHA..E GAS
ACRE-
PTAR*





























WET SOLIDSt
106 TONAR





























sin
ACRE-
PTAR





























THOII,
HET SOLIDS"
106 TONAR





























.EUrVTRIC'A  f;rai~UATTfi
ACRE-
FTAR*


26,659
26,659




53,318



23,884



23,884






47,768

25,842


25,842
HET SOLIDS'
106 TON'AR


3.01
3.01




6.02



2.65



2.65






5.30

1.32


1.32
SI!i W1&
ACRE-
FTAR*





























TOT SOLIDS7
io5 TO^AR





























to
w
OJ
           * Hater Consumed

           t Residuals

-------
            CASE   MflHTHflT.
            FACILITIES SITED IN POWDER RIVER REGION BY 1985 (AFTER 1975)
STATE/COUNT*

MONTANA
Powder River
Big Horn
Rosebud
Cuscer
wibaux
Richland
XcCone
TOTAL
HORTH DAKOTA
Billings
Bowman
Dunn
Hettinger
KcXenzie
X=Loan
Kcreer
Korton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Campbell
Johnson
Sheridan
TOTAL
ST.URRY PTPftLINK
ACRE-
fT/YR*

19,1'1
19,171
19,171




57,513
















19,171


19,171
WET SOLIDS'
106 TOH/VR

_
"
-




1
















-


-
LURCI GAS
ACRE-
FT/YR*





























HET SOLIDST
106 TOH/YR





























pYNTHAKfi GAS
ACRE-
FT/YR*





























WET SOLIDSt
106 fON/YR





























SYN
ACRE-
FTAR*





























HOIt,
WET SOLIDS1
O6 TON/YR





























F,y,F,erttjc;!^
ACRS-
FT/YR*

53,318
26,659
26,659




106,636



23,884

23,884
23,884
23,884


23,884



119,420

51,684


51,684
fif-NFUHTTON
i*ET SOLIDST
O6 TON/YR

6.02
3.01
3.01




12.04



2.65

2.65
2.65
2.65


2.65



13.25

2.64


2.64
cvn, (ME
ACRE-
PT/YR*





























CT SOLIDS'
O5 TOS/YR





























to
OJ
           * Water Consumed

           t Residuals

-------
          CASE  HOHINAL DEMAND
          FACILITIES SITED IN POWDER RIVER REGION BY  1990 (AFTER 1975)
STATE/COUNTY
MONTANA
Povder Rivet
Big Horn
Rosebud
Custer
Kibaux
Richland
KcCone
T07AL
NORTH SAKOTft
Billings
Bovsar.
E'jnn.
Hettinger
McKenzie
McLean
Kercar
Morton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Campbell
Johnson
Sheridan
TOTAL
SLURRY PIPET.INK
ACRE-
FT/YR*

38,342
19,171
19,171




76,684
















38,342


38,342
WET SOLIDST
106 TON/YR

-
_
_




--
















-


-
LURCt CAS 	
ACRE-
FT/YR*



4,618




4,618



3,307



3,307






6,614





WET SOLIDST
106 TON/YR



1.27




1.27



1.20



1.20






2.40





SYNTH \K~ GAS
ACRB-
FTAR*





























WET SOLIDSt
106 TON/YR





























SY
ACRE-
FT/YR*





























THOU,
WET SOLI OS 1
106 TON/YR





























EIiEWICft r,t^ii?RTTO'i
ACR-
FT/YR*

53,318
53,318
26,659




133,295

23,884

23,884

23,884
23,884
23,884


23,864



143, 304

51,684


51,684
WET SOLIDS7
106 TON/YR

6.02
6.02
3.01




15.05

2.65

2.65

2.65
2.65
2.65


2.65



15.90

2.64


2.64
"IL S1'-'**.1"
ACBE-
FT/YR*





























WET SOLZ3S '
1C6 TON/YR





























CO
u>
Ul
           Water Consumed

          t Residuals

-------
           CASE
           FACILITIES SITED IN POWDER RIVER REGION BY 2000  (AFTER i97S)
STATE/COUNTY
MONTANA
Powder River
Big Hfejrn
Rosebud
Duster
ttibaux
Rithland
TOTAL
NORTH DAKOTA
Billings
Bowman
Dunn
Hettinger
McKenzie
KcLaan
Kercer
Morton
Oliver
Slope
Stark
Ward
William
TOTAL
WYOMING
CaajiBell
Johnson
Sheridan
TOTAL
' SLURRY
biCRE-
VT/YR*

76,684
76,684
57.513



210,881
















76,684
19,171
19,171
115,026
PIPELINE
WET SOLIDS1"
106 TON/YR

_
-
_



-
















-
-
-
-
T.DWT GAS
ACRE-
FTAR*

18,472
13,854
13,854



46..J80

3,307
3,307
6,614
3,307
3,307
6,614
6,614

3,307

6,614

3,307
46,298

16,824
4,206
4,206
25,236
WET SOLIDS!
106 TONAR

5.08
3.81
3.81



12.70 -

1.20
1.20
2.40
1.20
1.20
2.40
2.40

1.20

2.40

1.20
16.80

2.88
0.72
0.72
4.32
SYNTKAN,-: GAS
ACRE-

IS, 616
15,616
7,808



39,040

7,671

7,671



15,342


15,342


7,671
53,697

13,552
7,776

23,328
WET SOUDSt
106 TON/YR

2.24
2.24
1.12



5.60

1.08

1.08



2.16


2.16


1.08
7.56

1.42
0.71

2.13
SYN
ACRE-
FTAR*


5,148




5,148



10,085










10.085





THOU.
3T SOLIDSl
1O6 'TON/YR


1.04




1.04



2.00










2,00





ET.ErTRJfCM GSNEHATTONI
ACRE-
FTAR*

53,318
53,318
53,318



159,954

23,884

47,768

23,884
47,768
47,768

23,884




214,956

51,684

25,841
77,525
ET SOLIDS1'
O6 TON/YR

6.02
6.02
6.02



18.06

2.65

5.30

2.65
S.30
5.30

2.65




23.85

2.64

1.32
3.96
OT, ,SM F
ACBE-
FT/YR*




























JET SOLIDS7




























ro
CO
CTi
           * Water Consuracd
           t Residuals

-------
                    T.flU  nFHAND
            FACILITIES SITED IN POWDER RIVER REGION BY  1980 (AFTER 1975)
STATE/COUSTY

MONTANA
Powder River
Big Horn
Rosebud
Ouster
Wibaux
Richland
HcConc
TOTAL
NORTH DAKOTA
Billings
Bowman
Dunn
Hettinger
McKenzie
KcLoan
Kerccr
Xorton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Campbell
Johnson-
Sheridan
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*
























19,171


19,171
WET SOLIDST
106 TONAR
























-


-
LtlRGT GAS
ACRE-
FT/YR*




























WET SOLIDS T
10^ TON/YR




























SYHT--AI-? GAS
ACRE-
FT/YR




























WET soLiost
106 TONAR




























SY
ACRE-
FT/YR*





























WET SOLIDSt
106 TON/YR




























rrpTTBT^
ACSE-
FT/YR*

26,659





26,659



23,884


23,884







47,768

25,842


25,842
r CEMFRATOBl
WET SOLIDST
106 TONAR

3.01





3.01



2.65


2.65







5.30

1.32


1.32
nrr CPJ^
ACRE-
ET/YR*




























WET SOLIDS'
106 TO.\'/yR




























IsJ
CO
            * Water consumed
            t Residuals

-------
            CASE  LOW DEMAND
            FACILITIES SITED IS POWDER RIVER REGION BY  1985 (AFTER  1975)
STATE/COUNTY
MONTANA
Powder River
Big Horn
Rosebud
Custer
Wibaux
Richland
KcCor.c
TOTAL
NORTH DAKOTA
Billings
Bo-ir-an
Dunn
Hettimjer
KcXenzie
McLean
Mercer
Xorton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Caspbell
Johnson
Sheridan
TOTAL
SLtiPRY PTPEI.TNK
ACRE-
FT/YR*

19,171
19,171





38,342
















19,171


19,171
WET SOLIDS1"
106 TON/YR

_
_





-
















-


-
LURGT CAS
ACRE-
FT/YR*





























WET SOLIDST
106 TON/YR





























SYNTIIANii GAS
ACRE-
FT/YR*





























WET SOLIDSt
106 TON/YR





























SYN
ACRE-
PT/YR*





























TIIOTT,
SffiT SOLIDSt
106 TON/YR





























!f!,.:(7TpT^AT RFNFHATTON
ACRE-
FT/YR*

26,659
26,659
26,659




79,977



23,884


23,884
23,884


23,884



95,536

51,684


51,684
WEf SOLIDS7
106 TON/YR

3.01
3.01
3.01




9.03



2.65


2.65
2.65


2.65



10.60

2.64


2.64
OIIl 5HAT.T
ACRE-
FT/YR*





























HEX SOLIDS'
106 TON/YR





























t"J
u>
00
           * Water Consumed
           t Residuals

-------
           CASE  LOW DEMAND
           FACILITIES  SITED IN POWDER RIVER REGION BY  1990 (AFTER 1975)
STATE/COUNTY

MONTANA
Powder River
Big Horn
Rosebud
Custer
Wiba-JX
Richland
McCone
TOT At
NORTH DAKOTA
Billings
Bowman
Dunn
Hettinger
HcXenzie
McLean
Mercer
Morton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Carapbo 1 1
Johnson
Sheridan
TOTAL
SLURRY
ACRE-
FT/YR*

19,171
19,171
19,171




57,513
















38,342


38,342
PIPELINE
WET SOLIDS1*
106 TON/YR

-
_
-




-.
















-


-
LURCT GAS
ACRE-
FT/YR*












3,307



3,307






6,614





WET SOLIDST
106 TON/YR












1.20



1.20






2.40





SYNTHAhR fiAS
ACRE-
FT/YR*





























WET SOLIDS^
10& TON/YR





























SYh
ACRE-
FT/YR*





























THOIT.
WET SOLIDS!
106 TON/YR





























Ki.^rTRTrAt
ACRE-
FT/YR*

26,659
26,659
26,659




79,977



23,884


23,884
23,884


23,984



95,536

51,684

25,842
77,526
^P-MFRAT^pM
WET SOLIDS7
106 TON/YR

3.01
3.01
3.01




9.03



2.65


2.65
2.65


2.65



10.60

2.64

1.32
3.96
OIL 
-------
           CASE  LOU DEMAND
           FACILITIES SITED IN POWDER RIVER REGION BY  2000 (AFTER 1975)
STATE/COUNTY

MONTANA
Powder River
Big Horn
Rosebud
Custer
Wibaux
Richland
KcCone
TOTAL
NORTH DAKOTA
Billings
Scvsvan
Dunn
Hettinger
McKenzie
McLean
Xercer
Morcon
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Campbell
Johnson
Sheridan
TOTAL
SLURRY
ACRE-
FT/YR*

57,513
57,513
57,513




172,539
















38,342
19,171
19,171
76,684
PXPRUNR
WET SOLIDST
106 TON/YR

_
_
-




-
















-
-
-
-
r,uft<-r GAS
ACRE-
FTAR*

13,854
9,236
4,618




27,708

3,307

3,307
3,307

3,307
3,307

3,307

3,307

3,307
26,456

8,412
4,206

12,618
WET SOLIDS'
106 TONAR

3.81
2.54
1.27




7.62 .

1.20

1.20
1.20

1.20
1.20

1.20

1.20

1.20
9.60

1.44
0.72

2.16
SYNTIW..R GAS
ACRF.-
FT/YR*

7,808
7,808
7,808




23,424

7,671

7,671



7,671


7,671


7,671
38,355

7,776
7,776

15,552
WET SOLIDSt
106 TONAR

1.12
1.12
1.12




3.36

1.08

1.08



1.08


1.08


1.08
5.40

0.71
0.71

1.42
SYI.
ACRE-
FT/YR*


10,296





10,296
















9,227


9,227
TIIOIL
WET SOLIDSt
106 TON/YR


2.07





2.07
















1.23


1.23
ET.KrrpICAT
ACRE-
FT/YR*

53,318
53,318
26,659




133,295

23,884

23,884

23,884
23,884
23,884


23,884



143,304

51,684

25,842
77,526
GFN-ESJVTTftN
WET SOLIDST
106 TON/YR

6.02
6.02
3.01




15.05

2.65

2.65

2.65
2.65
2.65


2.65



15.90

2.64

1.32
3.96
QTT. pijay.r
ACRE-
FT/YR*





























WET SOLIDS'
106 TON/YR





























S3
-P--
o
           * Water Consumed
           t Residuals

-------
CASE  LOW MUCLEAR VAILABIUTY	


FACILITIES  SITED III POWDER RIVER REGION BY  1980 (AFTER  1075)
STATE/COUNT*
MONTANA
Powdar River
Big Horn
Rosebud
Custer
Kiiaux
Richland
KcCor.e
TOTAL
NORTH DAKOTA
Billings
Bowjnaa
Dunn
Hettinger
KcKenzie
KcLean
Kercer
Morton
Oliver
Slope
Stark
Bard
Williaas
TOTAL
WYOMING
Ca.-r.pbeU
Johnson
Sheridan
TOTAL
SLURRY PIPEMNF.
ACRE-
?T/SfR*























19,171


19,171
WET SOLIDS1"
106 TOS/VR























-


- .
. 1URGI GAS
ACRE-
FT/YR*



























1T SOLIDS!
106 TON/VR



























SYNTHAN- GAS
ACRE-
FT/YS*



























vIET SOLIDSt
106 TONAH



























?Y
ACRE-
PT/YS*



























THOIL,
MET SOLIDS
106 TOtVYR



























ET.Efp-Rjf^T. r;gMp:RTro
ACRE-
FT/VR*


26,659
26,659




53,318


23,884



23,884






47,768

51,684


51,684
WET SOLIDS
106 TON/I R


3.01
3.01




6.02


2,65



2.65






5.30

2.64


2.64,
Off. SHALE
ACRE-
FT/YR*



























WET SOLIDS'
106 TONAR



























* Water Consumed
t Residuals

-------
 CASE
           KUCLEAR AVAILABILITY
 FACILITIES SITED IN POWDER RIVER REGION BY 1985  (AFTER 1975)
STATE/COUNTY

KO:;TM;A
Powder River
Big Horn
Rosebud
custer
Wibaux
Richland
KcCone
TOTAL
NORTH DAKOTA
Billings
Sovnan
Dunn
Hettinger
KcKenzie
McLean
Kercer
Morton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Campbell
Johnson
Sheridan
TOTAL
SF.URRY
ACRE-
PTAR*

38,342
19,171
19,171




76,684
















38,342


38,342
PIPELINE
VET SOLIDST
10& TONAR

_
.
-




-
















_


-

ACRE-
PTAR*





























I GAS
WET SOLIDST
IO6 TONAR





























SYNTHAN-: CAS
ACRE-
PT/YR*





























WET SOLIDSt
106 SONAR





























SYHTHOII.
ACKE-
PTAK*





























IET SOLIDSt
IO6 TONAR





























FIPrTRTrM
ACRE-^


33,318
53,318
26,659




133,295



23,884

23,884
23,884
23,884

23,884
23,884
23,884


167,188
-
51,684


51,684
GEUFFMISSa.
rfET SOLIDS1
IO6 TOSAR

6.02
6.02
3.01




15.05



2.65

2.65
2.65
2.65

2.65
2.65
2.65


18.55

2.64


2.64
	 IJJi M.P
ACRE-
FTAR"





























ET SOLIDS'
O6 TONAR





























* Water Consumed
t Residuals

-------
CASE  tnu NUCKFAR AVATLABrlTTY	

FACILITIES SITED IN POWDER  RIVER REGION BY 1990 (AFTER 1975)
STATE/COUNTY

MONTANA
Powder River
Big Horn
Rosebud
Custer
Vibaux
Ricnland
XcCor.e
TOTAL
NORTH DAKOTA
Billings
Bownan
Dunn
Hettinger
McKer.zie
KcLsan
>!ercer
Korton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Campbell
Johnson
Sheridan
TOTAL
SLURRY
ACRE-
FT/VR*

38,342
38,342
38,342




115,026
















76,684


76,684
PIPELINE
WET SOLIDS T
106 TON/YR

-
'
-




-
















-


-
MIRGI GAS
ACRE-
FT/YR*



4,618




4,618



3,307










3,307





WET SOLIDST
106 TON/YR



1.27




1.27



1.20










1.20





SYNTHANn GAS
ACRE-
FT/YR*





























WET SOLIDSt
106 TON/YR





























pYl
ACRE-
FTAR*





























TjiOfL
WET SOLIDS1
106 TON/YR





























ELECTRJCA .GE^^F!^.'lTIP^'
ACRE-
FT/YR*

53,318
53,318
53,318




159,954

23,884

23,884

23,884
23,884
23,884

23,884
23,884
23,884


191,072

77,526


77,526
WET SOLIDS1"
106 TOM/YR

6.02
6.02
6.02




18.06

2.65

2.65

2.65
2.65
2.65

2.65
2.65
2.65


21.20

3.96


3.96
OIL .CiM*.c'
ACRE-
FT/YR*





























WET SOLIDS'
106 TON/YR

,



























* Hater Consumed
t Residuals

-------
 CASE  LOW KUCLEAH AVAILABILITY	

 FACILITIES SITED IN POWDER WVfiR REGION BY  2000  (AFTER 1975)
STATE/COUNTY
MONTANA
Powder River
Big Horn
Rosebud
Custer
Wibaux
Rich land
McCor.e
TOTAL
NORTH DAKOTA
Billings
Bovnan
Dunn
Hettinger
McKenzie
McLean
Mercer
Korton
Oliver
Slope
Stark
Ward
Williaos
TCTAL
WYOMING
Caapfcell
Johnson
Sheridan
TOTAL
SMRRY
ACRE-
FT/YR*

115,026
115,026
115,026




345,078















115,086
38,342
19,171
172,539
PIPEt.IHE
WET SOLIDST
106 TON/YR

-
_
-




-















-
-
-
-
LUR<
ACRE-
rr/YR*

18,472
13,854
13,854




46,180

3,307
3,307
3,307
3,307
3,307
6,614
6,614

3,307

6,614

3,307
42,991

12,618
4,206
4,206
21,030
I GAS
WET SOLIDST
106 TON/YR

5.08
3.81
3.81




12.70 .

1.20
1.20
1.20
1.20
1.20
2.40
2.40

1.20

2.40

1.20
15.60

2.16
0.72
0.72
3.60
SYNTBANii GAS
ACRE-
FT/YR*

15,616
7,808
7,808




31,232

7,671

7,671


7,671


15,342


7,671
46,026

7,776
7,776

15,552
WET SOLIDSt
106 TONAR

2.24
1.12
1.12




4.48

1.08

1.08


1.08


2.16


1.08
6.48

0.71
0.71

1.42
SYN
ACRE-
FTAR*


10,296





10,296



















THOIL
WET SOLIDS1
106 TON/XR


2.07





2.07



















Pj^a^j
ACRE-
FT/YR*

79,977
79,977
106,636




266,590

23,884
23,884
47,768
23.884
23,884
47,768
47,768

23,884
23,8,84
23,884

23,884
334,376

72,526
51,684
25,842
155,052
GPNPRArt0M
ffiT SOLIDS7
10s" TON/YR

9.03
9.03
12.04




30.10

2.65
2.65
5.30
2.65
2.65
5.30
5.30

2.65
2.65
2.65

2.65
37.10

3.96
2.64
1.32
7.92
TOf fHMJS
ACRE-
FT/YR*





























-------
 APPENDIX E.   STATE TOTALS  OF WATER CONSUMED AND RESIDUALS
            GENERATED FOR THREE ENERGY SCENARIOS
     The results presented in Appendix D are presented in a differ-
ent form in this appendix.  For each region and facility, state
totals for water consumed and residuals generated are presented by
year and for the three energy scenarios.  Table E-l shows the page
numbers on which the results for specific scenarios are presented
in this appendix.
                                245

-------
        Table E-l.  Location of results for specific
                    scenario by region and facility.
Facility
Slurry Pipeline*
Lurgi
Synthane
Gas Production
(Lurgi and Synthane)
Synthoil
Electrical Generation
Oil Shale
Page Number
Rocky Mountain
Region
247
248
249
250
251
252
253
Powder River
Region
254
255
256
257
258
259

For each facility, totals for consumed water and residuals
generated are presented by state for each energy scenario
and for each year.
                             246

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                                           STATE TOTALS

                       FACILITIES SITED AFTER 1975  IN ROCKY MOUNTAINS  REGION

                       FACILITY  SLURRY  PIPELINE  (25 x 1Q6 tons/yr @ 100% load factor)

NOMINAL
DEMAND CASK
COLORADO
NEW J'JEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEW MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 10 TONS
PER YEAR* PER YEARt














1985
ACRE-PT 106 TOMS
PER YEAR* PER YBART


19,171



19,171

>


19,171


1990
ACRE-FT 106 TONS
PER YEAR* PER YEARt


19,171



19,171




19,171


2000
ACRE-FT J.O TONS
PER YEAR* PER YEARt


19,171



19,171




38,342


*  Water Consumed
t  Residuals   (Wet Solids)
                                             247

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                                        ;TATE TOTALS
                    FACILITIES SITED AFTER 1975 IN ROCKY MOUNTAINS REGION
                    FACILITY LURGI  (25Q_x 1Q6 scf/stream day @ 90% load factor)



NOMINAL
DEMAND CASE
COLORADO
NEW MEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEW MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 10 TONS
PER YEAR* PER YEARt







1985
ACRE-FT 106 TONS
PER YEAR* PER YEARt







1990
6
ACRE-FT 10 TONS
PER YEAR* PER 'YEARt







2000
ACRE-FT -106 TONS
PER YEAR* PER YEARt


5,639 3.00

5,639 3.00

5,639 3.00
Water Consumed
Residuals  (Wot Solids)
                                          248

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                                          STATE TOTALS
                      FACILITIES SITED AFTER 1975 IN ROCKY MOUNTAINS REGION
                      FACILITY _SYNTHANE  (250 K 1Q6 scf/stream day @ 90% load factor)

NOMINAL
DEMAND CASE
COLORADO
NEW MEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEVJ MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 10 iuNS
PER YEAR* PER YEARt














1985
ACRE-FT 106 TONS
PER YEAR* PER YEARt














1990
ACRE-FT 10 TONS
PER YEAR* PER YEARt














2000
ACRE-FT 10 TONS
PER YEAR* PER YEARt



8,670 2.84








8,670 2.84

*  Water Consumed
t  Residuals   (Wet Solids)
                                             249

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                                          STATE TOTALS
                      FACILITIES SITED AFTER 1975 IN ROCKY MOUNTAINS REGION
                      FACILITY GAS  PRODUCTION  (LURGI and  SYNTHANE)



NOMINAL
DEMAND CASE
COLORADO
NEW MEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEW MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 10 TONS
PER YEAR* PER YEARt







1985
ACRE-FT 10 TONS
PER YEAR* PER YEARt







1990
ACRE-FT 10 TONS
PER YEAR* PER YEARt







2000
6
ACRE-FT 10 TONS
PER YEAR* PER YEARt


14,309 5.84

5,639 3.00

14,309 5.84
*  Water Consumed
t  Residuals   (Wet Solids)
                                             250

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                                          STATE TOTALS
                      FACILITIES SITED AFTER 1975 IN ROCKY MOUNTAINS REGION
                      FACILITY SYNTHOIL (100.000 bbl/stroam  day @  90% load  factor)



NOMINAL
DEMAND CASE
COLORADO
NEW MEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEW MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 10 TONS
PER YEAR* PER YEARt







1985
ACRE-FT 106 TONS
PER YEAR* PER YEARt







1990
ACRE-FT 106 TONS
PER YEAR* PER YEARt







2000
ACRE-FT ' 106 TONS
PER YEAR* , PER YEARt







*  Water Consumed
t  Residuals   (Het  Solids)
                                             251

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                                          STATE TOTALS

                      FACILITIES SITED AFTER 1975 IN ROCKY MOUNTAINS REGION

                      FACILITY ELECTRICAL GENERATION  (3,uOO MWe  @  35% eff.  and  70%  load factor)



NOMINAL
DEMAND CASE
COLORADO
NEW MEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEW MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
i
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 106 TONS
PER YEAR* PEE YEARt


29,206 5.00
29,816 5.30

29,816 5.30

29,206 5.00
29,816 5.30
1985
ACRE-PT 106 TONS
PER YEAR* PER YEARt


28,482 1.14
29,206 5.00
29,816 5.30

29,206 5.00
29,816 5.30

28,482 1.14
58,412 10.00
59,632 10.60
1990
ACRE-FT 10 TONS
PER YEAR* PER YEARt


28,482 1.14
29,206 5.00
59,632 10.60

29,206 5.00
29,816 5.30

28,482 1.14
58,412 10.00
89,448 15.90
2000
ACRE-FT 106 TONS
PER YEAR* PER YEARt


28,482 1.14
29,206 5.00
59,632 10.60

29,206 5.00
29,816 5.30

56,964 2.28
87,618 15.00
119,264 21.20
*  Hater Consumed
f  Residuals   (Wet Solids)
                                             252

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                                          STATE TOTALS

                      FACILITIES SITED AFTER 1975 IN ROCKY MOUNTAINS REGION

                      FACILITY  OIL SHALE (100.000 bbl/scream day  @  90%  load  factor)



NOMINAL
DEMAND CASE
COLORADO
NEW MEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEW MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 10 TONS
PER YEAR* PER YEARt







1985
ACRE-FT 106 TONS
PER YEAR* PER YEARt


25,848 81.62

25,848 81.62

25,848 81.62
1990
ACRE-FT 10 TONS
PER YEAR* PER YEARt


64,620 204.05

64,620 204.05

. 51,696 163.24
2000
ACRE-FT 106 TONS
PER YEAR* PER YEARt


91,112 1,550.78
51,696 163.24

413,568 1,305.92
38,'772 122.43

478,188 1,509.97
51,696 163.24
*  Water Consumed
t  Residuals   (Wet  Solids)
                                             253

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                                          STATE TOTALS

                         FACILITIES SITED AFTER 1975 IN POWDER RIVER REGION

                         FACILITY SLURRY PIPELINE (25 x 10  tons/yr & 100% load factor)



NOMINAL
DEMAND CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW DEMAND
CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW NUCLEAR
AVAILABILITY
CASE
MONTANA
NORTH DAKOTA
WYOMING
1980
 6
ACRE-FT 10 TONS
PER YEAR* PER YEARt


19,171

19,171

19,171
1985
ACRE-FT 10 TONS
PER YEAR* PER YEARt


57,513
19,171

38,342
19,171

76,684
38,342
1990
ACRE-FT 10 TONS
PER YEAR* PER YEARt


76,684
38,342

57,513
38,342

115,026
76,684
2000
ACRE-FT - 10 TONS
PER YEAR* PER YEARt


210,881
115,026

172,539
76,684

345,078
172,539
*  Water Consumed
t  Residuals   (Wet Solids)
                                              254

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                                          STATE TOTALS

                         FACILITIES SITED AFTER 1975 IN POWDER RIVER  REGION

                         FACILITYLURGI  (250 x  1Q6 scf/stream day @ 90% load factor)



NOMINAL
DEMAND CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW DEMAND
CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW NUCLEAR
AVAILABILITY
CASE
MONTANA
NORTH DAKOTA
WYOMING
1980
6
AC RE -FT 10 TONS
PER YEAR* PER YEARt







1985
ACRE -FT 10 TONS
PER YEAR* PER YEARt







1990
ACRE -FT 10 TONS
PER YEAR* PER YEART


4,618 1.27
6,614 2.40

6,614 2.40

4,618 1.27
3,307 1.20
2000
ACRE-FT 106 TONS
PER YEAR* PER YEARt


46,180 12.70
46,298 16.80
25,236 4.32

27,708 7.62
26,456 9.60
12,618 2.16

46,180 12.70
42,991 15.60
21,030 3.60
*  Water Consumed
t  Residuals    (Wet Solids)
                                             255

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                                            STATE TOTALS

                           FACILITIES SITED AFTER 1975 IN POWDER RIVER  REGION

                           FACILITY  SYSTHAHE  (250 x 10  scf/stream day @ 90% load factor)



NOMINAL
DEMAND CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW DEMAND
CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW NUCLEAR
AVAILABILITY
CASE
MONTANA
NORTH DAKOTA
WYOMING
1980
ACRE-FT 10 TONS
PER YEAR* PER YEARt







1985
ACRE -FT 106 TONS
PER YEAR* PER YEARt







1990
6
ACRE-FT 10 TONS
PER YEAR* PER YEARt







2000
ACRE-FT 106 TONS
PER'.YEAR* PER YEAR*


39,'040 5.60
53,697 7.56
23,328 2.13

23,424 3.36
38,355 5.40
15,552 1.42

31,232 4.48
46,026 6.48
15,552 1.42'
*  Water Consumed
t  Residuals   (Wet Solids)
                                            256

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                                          STATE TOTALS

                         FACILITIES SITED AFTER 1975 IN POWDER RIVER REGION

                         FACILITY  GAS PRODUCTION  (LURGI AND  SYNTHANE)



NOMINAL
DEMAND CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW DEMAND
CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW NUCLEAR
AVAILABILITY
CASE
MONTANA
NORTH DAKOTA
WYOMING
1980
ACRE -FT 10 TONS
PER YEAR* PER YEARt







1985
6
ACRE -FT 10 TONS
PER YEAR* PER YEARt







1990
ACRE -FT 10 6 TONS
PER YEAR* PER YEARt


4,618 1.27
6,614 2.40

6,614 2.40

4,618 1.27
3,307 1.20
2000
ACRE-FT "106 TONS
PER YEAR* PER YEARt


85,220 18.30
99,995 24.36
48,564 6.45

51,132 10.98
64,811 15.00
28,170 3.58

77,412 17.18
89,017 22.08
36,582 5.02
*  Water Consumed
t  Residuals    (Wet Solids)
                                              257

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                                           STATE TOTALS

                          FACILITIES SITED AFTER 1975  IN POWDER RIVER REGIChN

                          FACILITY  SYNTHOIL  (100.000 bbl/stream day  @  90%  load  factor)



NOJ-SINAL
DEMAND CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW DEMAND
CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW NUCLEAR
AVAILABILITY
CASE
MONTANA
NORTH DAKOTA
WYOMING
1980
ACRE -FT 106 TONS
PER YEAR* PER YEARt







1985
ACRE -FT 106 TONS
PER YEAR* PER YEARt







1990
ACRE-FT 106 TOMS
PER YEAR* PER YEARt







2000 -
ACRE-FT ' 106 TONS
PER YEAR* PER YEARt


5,1*8 I-04
10,085 2.00

10,296 2.07
9,227 1.23

10,296 2.07
*  V!ater Consumed
t  Residuals    (Wet Solids)
                                              258

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                                           STATE TOTALS

                          FACILITIES SITED AFTER 1975 IN POWDER RIVER REGION

                          FACILITY ELECTRICAL GENERATION (3,000 MWe @ 35% eff.  and 70% load facto*'



NOMINAL
DEMAND CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW DEMAND
CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW NUCLEAR
AVAILABILITY
CASE
MONTANA
NORTH DAKOTA
WYOMING
1980
ACRE -FT 10 TONS
PER YEAR* PER YEARt


53,318 6.02
47,768 5.30
25,842 1.32

26,659 3.01
47,768 5.30
25,842 1.32

53,318 6.02
47,768 5.30
51,684 2.64
1985
ACRE -FT 10 TONS
PER YEAR* PER YEARt


106,636 12.04
119,420 13.25
51,684 2.64

79,977 9.03
95,536 10.60
51,684 2.64

133,295 15.05
167,188 18.55
51,684 2.64
1990
ACRE -FT 10 TONS
PER YEAR* PER YEARt


133,295 15.05
143,304 15.90
51.684 2.64

79,977 9.03
95,536 10.60
77,526 3.96

159,954 18.06
191,072 21.20
77,526 3.96
2000
ACRE-FT 106 TONS'
PER YEAR* PER YEARt


159,954 18.06
214,956 23.85
77,526 3.96

133,295 15.05
143,304 15.90
77,526 3.96

266,590 30.10
334,376 37.10
155,052 7.92
*  Water Consumed
t  Residuals    (Wet Solids)
                                             259

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                                   TECHNICAL REPORT DATA
                            (Please read Instructions on the reverse before completing)
1. REPORT NO.
   EPA-600/7-77-037
                                                          3. RECIPIENT'S ACCESSION NO.
 .. TITLE AND SUBTITLE
 Water Requirements for  Steam-Electric Power Generation
 and Synthetic Fuel Plants  in the Western United States
                                                          5. REPORT DATE
                February, 1977
             6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
  H.  Gold, D.J. Goldstein,  R.F.  Probstein, J.S. Shen &
  D.  Yung
             8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
  Water Purification Associates
  Cambridge, Massachusetts  02142
             10. PROGRAM ELEMENT NO.

                  EHE 624C
             11. CONTRACT/GRANT NO.

                  68-01-1916
12. SPONSORING AGENCY NAME AND ADDRESS
       Office of Energy, Minerals  and  Industry
  Office of  Research and Development
  U.S. Environmental Protection Agency
  Washington, D.C.  20460    	  	
             13. TYPE OF REPORT AND PERIOD COVERED
               Final, 5/76-8/76
             14. SPONSORING AGENCY CODE
               EPA/600/17
15. SUPPLEMENTARY NOTES
16. ABSTRACT
       The study describes the procedures for the detailed  determination of the water
  consumed for mining  and processing coal and oil shale,  and  for determining the
  residuals generated.   The processes considered are  Lurgi, Synthane, and Synthoil
  for coal conversion,  TOSCO II for shale conversion,  coal-fired steam electric power
  generation and slurry pipeline.  In addition, determiniations are also made of  the
  water consumed for process cooling, flue gas desulfurization, revegetation of mined
  land, solids disposal and by evaporation and other  uses within the mine-plant
  complex.  In these determinations it is assumed that there  is no discharge to
  receiving waters  and that there is a reasonably high level  of recycle and reuse
  of process effluent  waters.  Wasteful evaporation of wastewater is not permitted.
  Economic studies  of  water treatment are not included in this assessment except  for
  some of the process  cooling studies.

       The consumptive water use and solids residuals are determined for a total  of
  21 plant-site combinations.  The sites are: Beulah,  North Dakota; Colstrip, Montana;
  Gillette, Wyoming; Kaiparowits/Escalante, Utah; Navajo/Farmington, New Mexico;  and
  Rifle, Colorado.  A  detailed breakdown by consumptive water use category is presented
  in tabular form  for  each plant-site combination.  Approximately twenty water use
  categories are considered.	
17.
                                KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
   Water Supply
   Energy Conversion
                                              b.IDENTIFIERS/OPEN ENDED TERMS
    Coal Conversion
    Oil Shale Conversion
    Water Consumption
                          c.  COSATI Reid/Group
                                                                               13B
18. DISTRIBUTION STATEMENT

   Release to Public
19. SECURITY CLASS (This Report)
  UNCLASSIFIED
21. NO. OF PAGES
        276
                                              20. SECURITY CLASS {Thispage)
                                               UNCLASSIFIED
                                                                        22. PRICE
EPA Form 2220-1 (9-73)
                                                          aU.S. GOVERNMENT PRINTING OFFICE: 1977 7^0-U7/1982 1-3

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