x>EPA
         United States
         Environmental Protection
         Agency
          Industrial Environmental Research
          Laboratory
          Research Triangle Park NC 27711
EPA-600/7-78-197a
October 1978
Water-related
Environmental Effects
in Fuel Conversion:
Volume I. Summary
         Interagency
         Energy/Environment
         R&D Program Report

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                  RESEARCH REPORTING SERIES


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

    1. Environmental Health  Effects Research

    2. Environmental Protection Technology

    3. Ecological Research

    4. Environmental Monitoring

    5. Socioeconomic Environmental  Studies

    6. Scientific  and Technical  Assessment Reports (STAR)

    7 Interagency Energy-Environment Research and Development

    8. "Special"  Reports

    9. Miscellaneous Reports

This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded  under the  17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the  nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related  pollutants and their health and ecological
effects;  assessments  of,  and development of,  control  technologies for energy
systems; and integrated assessments of a wide'range of energy-related environ-
mental issues.
                        EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for  publication. Approval does  not signify that the contents necessarily reflect
the  views and policies of the Government, nor does mention of trade names or
commercial products  constitute endorsement or  recommendation for use.

This document is available to the public through  the National Technical Informa-
tion Service, Springfield, Virginia 22161.

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                 I         UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
                                INDUSTRIAL ENVIRONMENTAL RESEARCH LABORATORY
                                          RESEARCH TRIANGLE PARK
          '•V PRO^"                            NORTH CAROLINA 27711

   DATE:   November 20,  1978


SUBJECT:   Water-Related Environmental  Effects in Fuel  Conversion
   FROM:  William J.
          Program Manager, Synthetic Fuels
          Fuel  Process Branch
          Energy Assessment and Control  Div.  (MD-61)

     TO:  Distribution
          The attached multi-volume report presents results of water-related
          effects that can be expected from siting conversion plants in major U.S.
          coal  and oil shale bearing regions.  Ninety plant site combinations were
          studied from the Eastern, Central, and Western U.S.

          The results include the water requirements, considerations in optimizing
          the use of water, costs and energy requirements for wastewater treat-
          ment, and ranges of residual solid wastes.  All water requirements of
          this  study are based on complete water reuse which is no direct water
          discharge to streams or rivers.
          This report includes work performed for EPA and DOE.
          grated into one report to be more effective.

          Attachment
          Distribution

          Ann Alford
          Walt Barber
          Del Barth
          Thomas Belk
          David Berg
          K. E. Biesinger
          Rudy Boksleitner
          W. E. Bye
          A. Corson
          Stan Cuffe
          Tom Duke
          Al El 1ibun
          J. E. Fitzgerald
          Al Galli
          Tom Ha user
          Stan Hegre
          Bill Horning i/"
          Joel 1 en Huisingh
          Nick Humber
          B. M. Jarrett
J. W. Jordan
W. W. Kovalick
R. W. Kuchkuda
John Lehman
A. Levin
K. Mackenthun
W. N. McCarthy, Jr.
L. A. Miller
Don Mount
John Nader
Eric Preston
Gerry Rausa
Walt Sanders
Robert Schaffer
David Shaver
Jerry Stara
George Stevens
Bill Telliard
John Lum
W. G. Tucker
                             The work was inte-
Jerry Walsh
Mike Waters
Eugene Wyszpolski
Morris Altschuler
Josh Bowen
P. P. Turner
A. B. Craig
Don Goodwin
R. P. Hangebrauck
T. K. Janes
Steve Jelinek
J. D. Kilgroe
A. Lefohn
G. D. McCutchen
E. L. Plyler
F. T. Princiotta
N. D. Smith
D. A. Schaller
R. M. Statnick

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                                 EPA-600/7-78-197a

                                       October 1978
Water-related  Environmental
Effects in Fuel  Conversion:
        Volume  I.  Summary
              Harris Gold and David J. Goldstein

               Water Purification Associates
                   238 Main Street
              Cambridge, Massachusetts 02142
                 Contract No. 68-03-2207
               Program Element No. EHE623A
              EPA Project Officer: Chester A. Vogel

           Industrial Environmental Research Laboratory
             Office of Energy, Minerals, and Industry
              Research Triangle Park, NC 27711
                    Prepared for

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

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                                    PREFACE

     The work presented  in  this  report was supported  by  the  U.S.  Environmental
 Protection Agency  (EPA)  under  Contract No. 68-03-2207 and  the  U.S.  Department
 of Energy  (DOE) under  Contract No. EX-76-C-01-2445.   The site  specific  studies
 of the Western  states  were  supported principally by EPA, while those  of the
 Eastern and Central  states  were  supported by DOE.  In addition the  results of
 the Western site studies were  synthesized into  the DOE program in order to
 generalize the  results to the  United States as  a whole.  It  seemed  appropriate
 to incorporate  all of  the results  into one document in order to increase the
 usefulness of the report rather  than to fragment the  study into separate reports.
 The report consists  of a summary volume and an  appendix  volume and  will be
 issued separately by each of the sponsoring agencies  to  receive as  wide a
 distribution as possible.
     The authors gratefully acknowledge the help and  support of Mr. John A.
 Nardella, Program Manager,  and Mr. James C. Johnson of DOE and Mr.  Chester A.
 Vogel, Program Manager, and  Mr. T.  Kelly  Janes  of EPA.   We are grateful to
 D. Morazzi, C. Morazzi,  P.  Gallagher and P. Qamoos for carrying out the detailed
process-site calculations.  We wish also to acknowledge  Resource Analysis, Inc.
 and Richard L. Laramie,  John H.  Gerstle and David H.  Marks in  particular for
 supplying information  on water resources developed under several joint  programs
with Water Purification  Associates.
                                        11

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                                   CONTENTS
                                                                       Paqe
PREFACE
FIGURES . „ ......... _ ............................ ......... ..... ....... V
TABLES „ .............................................. . ...............
CONVERSION FACTORS ......................................... . ......... xll
1.   EXECUTIVE SUMMARY .................. .................. ..... . ........ !
     1. 1  Process and Site Selections ..... . ..... . ..... . ................. 1
     1 . 2  Water Supply and Demand .................. ...... ........... .... 3
     1 . 3  Process-Site Results ..... . . ........................... ....... 15
     1 . 4  Recommendations ................ „ ......... ... ...... ........... 2 7
          References .... ..... .... ........ ... .............. . ............ 28
2 .   INTRODUCTION ........... . ...... . ......... ....... ____ . . ....... ...... 30
3.   PROCESS AND SITE SELECTIONS .............. . ...... . ............ . ____ 33
     3 . 1  Introduction ..... .......... ....... ................ ........ ... 33
     3. 2  Process and Plant Selection ......... ..... ........... ......... 38
     3. 3  Site Selection . „ ............. ............ .................    41
     3 . 4  Process-Site Combinations ..... ............. ..... . ........ .... 60
     3 . 5  Coal Analyses ......... .... ......... . . ........... . ............ 60
     3 . 6  Water Analyses .............. ........... . ..... . ............... 72
          References ......... ............. . . ..... .... .......... . .....   74
4.   WATER SUPPLY AND DEMAND ...... . ....... . ..... . ..................... .77
     4. 1  Introduction . ..... „ ..... . ..... . ............ . ......... . .....   77
     4 . 2  Eastern and Central Regions .... ......... . ............. ....... 7 8
     4 . 3  Western Region ...... .......... . .......... ... ............. ... 104a
     4. 4  Water Supply to Chosen Sites ... ........... . ...... ........... 143
          References ..... ................... ... .....                    154
                                        111

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                           Contents (Cont.)                                  pa e
5.    WATER REQUIREMENTS AND  RESIDUALS 	 156
     5. 1  Total Water Consumed  and  Residuals  Generated	1-*^
     5. 2  Process Water Requirements . „	• •  • 178
     5.3  Cooling Water Requirements
     5.4  Other Water Requirements	
     5. 5  Residuals	i96
          References	197
6.   CONTROL TECHNOLOGY	1"
     6.1  Water Treatments	198
     6. 2  Costs	207
     6.3  Energy Requirements 	 212
          References	213
 7.  GENERALIZATION OF RESULTS  	 218
     7.1  Process-Coal Combinations .	218
     7. 2  Process-Site Combinations	  . 227
     7.3  Large Scale Synthetic Fuel  Production 	 229
          Reference	229

Appendices:
Al.  CALCULATIONS  ON SOLVENT REFINED  COAL			......*
A2.  CALCULATIONS  ON THE  SYNTHOIL PROCESS	  *
A3.  CALCULATIONS  ON THE  HYGAS  PROCESS	  *
A4.  CALCULATIONS  ON THE  BIGAS  PROCESS	  *
A5.  CALCULATIONS  ON THE  SYNTHANE PROCESS		  *
A6.  CALCULATIONS  ON THE  LURGI  PROCESS	   *
A7.  COOLING WATER REQUIREMENTS	   *
A8.  BOILERS,  ASH  DISPOSAL AND  FLUE GAS  DESULFURIZATION 	   *
A9.  ADDITIONAL WATER NEEDS	   *
AID. WORK SHEETS FOR NET  WATER  CONSUMED  AND WET SOLIDS RESIDUALS GENERATED ..   *
All. WATER  TREATMENT PLANTS	   *
A12. CALCULATIONS  ON OIL  SHALE	   *
A13. WATER  AVAILABILITY AND  DEMAND  IN  EASTERN AND CENTRAL REGIONS	_   *
A14. WATER  AVAILABILITY AND  DEMAND  IN  WESTERN REGION 	   *
A15. COST OF SUPPLYING WATER TO CHOSEN SITES	            *
 (*) All appendices are in Volume II.
                                        IV

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                                    FIGURES
Number                                                                Page
1-1       Coal conversion site locations in Eastern and Central
          states [[[ 6
1-2       Coal and oil shale conversion site locations in Western
          states ........... ..... ......................................... 8
1-3       Water availability in the Appalachian coal region ............ 10
1-4       Water availability in the Illinois coal region  . „ „ . ..... ..... 11
1-5       Cost of transporting water to specific site locations
          in the Western states  ........................ ......... ...... 14
1-6       Cost of transporting water to coal regions in the
          Western states .............................. ..... ............ 16
1-7       Average total water consumed normalized with respect to
          the heating value of the product fuel ............... ...... ... 21
1-8       Water treatment flow diagram for coal conversion plant
          generating dirty process water ....... ..... . ........ .......... 26
3-1       Methods of producing clean synthetic gaseous,  liquid and
          solid fuels ..... ........ ............................. ....... . 40
3-2       Coal fields of the conterminous United States ................ 45
3-3       Oil shale areas of the Green River Formation in Colorado,
          Utah and Wyoming ..... ......... ..... ....... ..... .............. 48
3-4       Coal conversion site locations in Eastern  and  Central states . 55
3-5       Coal and oil shale conversion site locations in Western
          states . ...... ........ ........... .......... ...... ............. 58a
4-1       High-yield sources of groundwater .. ................. ...... .... 92
4-2       Water availability in the Appalachian coal region. ........... 103
4-3       Water availability in the Illinois coal region .............. 104
4-4       Subbasin boundaries - Upper Missouri Basin ......... ...... ... 107
4-5       Major rivers in the Upper Missouri River Basin.. ............ 110
4-6       Subbasin boundaries - Upper Colorado River Basin . . ......... . 112
4-7       Major rivers and runoff producing areas in the Upper
          Colorado River Basin ............................ ............ 114
4-8       Groundwater supply availability ...,....., ..... ... ........ . . . 118
4-9       Total annual costs for transporting water  as a function
          of pipe diameter ..................... ....... ................ 145
4-10      Unit cost of water supply. . . ........ . ........ ............... 146
4-11      Cost of transporting water to specific site  locations. ...... 150

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                             Figures (Cont.)
Number                                                                     ZS2£

5-1       Summary of average net water consumed for standard size
          coal conversion plants located in the Central and Western
          states	  165

5-2       Summary of average net water consumed for coal conversion
          plants located in the Western states	  I67

5-3       Summary of net water consumed for oil shale conversion
          plants located in the Western states	  168

5-4       Summary of average wet-solid residuals generated from
          standard size coal conversion plants located in Central
          and Eastern states	  175

5-5       Summary of average wet-solid residuals generated from
          standard size coal conversion plants located in the
          Western states	„	  176
5-6       Summary of average wet solid residuals generated from
          standard size oil shale plants located in the Western
          states	  I77
5-7       Range of process water flows for standard size synthetic
          fuel plants	  179
5-8       Range of process water flows in gal/10  Btu. .	 .  180

5-9       Summary of average process water flows for standard size
          fuel plants located in the Central and Eastern states............  182

5-10      Summary of average process water flows for standard size
          synthetic fuel plants located in the Western states	  183

5-11      Net process water  consumed in Lurgi process.	  184

5-12      Net process water  consumed in Synthoil process	  185

5-13      Net process water  consumed in SRC process - variation  with
          oxygen content	  186

5-14      Net process water  consumed in SRC process - variation with
          moisture content		  187

5-15      Percent of unrecovered heat removed by wet cooling	  190

5-16      Cooling water consumed by evaporation for standard size
          synthetic fuel plants	192

5-17      Cooling water consumed by evaporation in gals/10  Btu	  193
5-18      Average cooling water consumed for coal conversion in the
          Illinois and Appalachian  coal regions and consumed for oil
          shale conversion in Green  River Formation	  194

5-19      Average cooling water consumed for coal conversion in the
          Western states	  195

 6-1       Simplified  water  use  diagram	  200
                                        VI

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                              Figures (Cont.)
Number                                                                     Page

6-2       Water treatment flow diagram for coal conversion plant
          generating dirty process water	 202

6-3       Water treatment block diagrams ................................... 203

6-4       Regional summary of average costs  of water treatment in
          coal conversion plants  located in  the Central and Eastern
          states	 210

6-5       Regional summary of average costs  of water treatment in
          coal conversion plants  located in  the Western states ............. 211

6-6       Regional summary of the average energy consumed for water
          treatment in percent of the heating value of the product
          fuel in coal conversion plants located in the Central and
          Eastern states	 216

6-7       Regional summary of average energy consumed for water
          treatment in percent of the heating value of the product
          fuel in coal conversion plants located in the Western states ..... 217

7-1       Summary of process-site results	 222
                                     Vll

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                                      TABLES


Number
1-1    PRODUCT FUEL OUTPUT  OF STANDARD SIZE SYNTHETIC FUEL PLANTS-
1-2    PLANT-SITE COMBINATIONS FOR EASTERN AND CENTRAL  STATES	
                                                                        Paqe
1-3    COAL AND OIL SHALE CONVERSION PLANT-SITE COMBINATIONS  FOR
       WESTERN STATES	    5
1-4    SUMMARY OF RESULTS BY  CONVERSION PROCESS	   17
1-5    COMPARISON OF NET WATER CONSUMED	   22
3-1    SITE AND PROCESS CRITERIA  AND PRINCIPAL CHARACTERISTICS  FOR
       CENTRAL, EASTERN AND WESTERN COAL BEARING REGIONS	   35
3-2    SITE AND PROCESS CRITERIA  AND PRINCIPAL CHARACTERISTICS
       FOR WESTERN OIL SHALE  BEARING REGIONS	   36

3-3    PRODUCT FUEL OUTPUT OF STANDARD SIZE SYNTHETIC FUEL PLANTS	   39
3-4    SUMMARY OF CONVERSION  PROCESSES AND REACTOR TYPES USED IN
       SITE STUDIES.	   42
3-5    REFERENCE DATA FOR THE DESIGN OF INTEGRATED CONVERSION PLANTS
       UTILIZING SPECIFIC COALS AND OIL SHALE.	   43
3-6    MATRIX OF COAL TYPE/COAL CONVERSION PROCESS COMBINATIONS
       USED IN SITE STUDIES	   44
3-7    DEMONSTRATED COAL RESERVE  BASE OF THE U.S. IN BILLIONS OF
       TONS BY REGION AND POTENTIAL METHOD OF MINING	   46
3-8    COAL MINING RATES & RESERVES REQUIRED FOR A SYNTHANE PLANT
       PRODUCING 250 MILLION  STANDARD CUBIC FT/DAY OF PIPELINE  GAS....   49
3-9    COUNTIES OF PRINCIPAL  COAL RESERVES IN CENTRAL AND EASTERN

3-10
3-11
3-12
3-13
3-14

3-15
3-16

3-17
STATES 	 	 	 	 	 	 	 	 	 .
COAL CONVERSION PLANT SITES FOR CENTRAL AND EASTERN STATES 	
COUNTIES OF PRINCIPAL COAL RESERVES IN WESTERN STATES. .........
COAL CONVERSION PLANT SITES FOR WESTERN STATES 	
PLANT-SITE COMBINATIONS FOR EASTERN & CENTRAL STATES
COAL & OIL SHALE CONVERSION PLANT-SITE COMBINATIONS FOR
WESTERN STATES 	 	 	 	 	
PLANT-SITE COMBINATIONS LISTED BY CONVERSION PROCESS. . .
BREAKDOWN OF PROCESS-SITE COMBINATIONS FOR EASTERN AND
CENTRAL STATES. 	 	 	 	
BREAKDOWN OF PROCESS-SITE COMBINATIONS FOR WESTERN STATES
50
53
54
57
61

62
63

65
66
                                        viii

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                              Tables  (Cont.)
Number                                                                   Pa9e


3-18   COAL ANALYSES  BY COUNTY FOR EASTERN AND CENTRAL COALS IN
       WT. PERCENT ......................................	...........  68

3-19   COAL ANALYSES  FOR WESTERN COALS IN WT. PERCENT ..................  70

3-20   RAW SOURCE WATER QUALITY FOR CENTRAL & EASTERN STATES ...........  73

3-21   RAW SOURCE WATER QUALITY FOR WESTERN STATES .....................  73

4-1    LIST OF  PRIMARY COAL CONVERSION PLANT SITES FOR CENTRAL AND
       EASTERN  STUDY  [[[  82

4-2    LIST OF  SECONDARY COAL CONVERSION PLANT SITES ...................  83

4-3    ASSESSMENT OF  POTENTIAL SURFACE WATER SOURCES ...................  84

4-4    ASSESSMENT OF  ADDITIONAL SURFACE WATER SOURCES ..................  86

4-5    ESTIMATED CONSUMPTIVE WATER USE AND SURPLUS SUPPLIES IN THE
       OHIO RIVER BASIN FOR 1975 AND 2000 .		  90

4-6    ASSESSMENT OF  GROUNDWATER AVAILABILITY AT PRIMARY SITES WITH
       INSUFFICIENT SURFACE SUPPLIES ...................................  94
4-7    ASSESSMENT OF  GROUNDWATER AVAILABILITY AT THE SECONDARY SITES...  95

4-8    WATER  AVAILABILITY SUMMARY ......................................  99

4-9    PLANT  SITE LOCATIONS IN THE WESTERN STUDY REGION ................ !04fo

4-10   AVERAGE  ANNUAL WATER YIELD - UPPER MISSOURI RIVER BASIN ......... 108

4-11   RECORDED SURFACE RUNOFF CHARACTERISTICS IN CUBIC FEET PER
       SECOND OF RIVERS AT SELECTED POINTS IN THE  UPPER MISSOURI
       BASIN [[[ 109
4-12   AVERAGE  ANNUAL WATER YIELD - UPPER COLORADO RIVER BASIN	..... 113

4-13   RECORDED SURFACE RUNOFF CHARACTERISTICS IN CUBIC FEET PER
       SECOND OF RIVERS AT SELECTED POINTS IN THE UPPER COLORADO
       RIVER  BASIN	 115

4-14   WATER  USE -  UPPER MISSOURI RIVER BASIN .......................... 127

4-15   WATER  USE -  UPPER COLORADO RIVER BASIN.......................... 130
4-16   PROJECTED FUTURE WATER AVAILABILITY (YEAR 2000) IN 1000 AF/YR... 133

4-17   NUMBER OF STANDARD SIZE PLANTS REQUIRED TO PRODUCE 1X1Q6
       BBLS/DAY OF  SYNTHETIC CRUDE OR EQUIVALENT OF 5.8X1012 BTU/DAY.. . 135
4-18   SUMMARY  OF WATER REQUIREMENTS FOR COAL AND OIL SHALE CONVER-
       SION IN  EACH OF THE DRAINAGE SUB-AREAS .......................... 136

4-19   SUMMARY  OF WATER SUPPLY ALTERNATIVES	 .    138

4-20   LOCAL  SUPPLY TO INDIVIDUAL PLANTS ............................... 147


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Number                             Tables (Cont. )

5-1    STUDY SITES  COMPRISING COAL AND OIL SHALE BEARING  REGIONS ......  158
5-2    COAL & OIL SHALE  MINING RATES FOR STANDARD SIZE  SYNTHETIC
       FUEL PLANTS ......... . ................. ... .................... . .  159
5-3    REGIONAL SUMMARY  OF  COAL AND OIL SHALE MINING RATES  IN 1000
       TONS PER DAY FOR  STANDARD SIZE SYNTHETIC FUEL PLANTS ..........
5-4    REGIONAL SUMMARY  OF  COAL AND OIL SHALE MINING RATES  NORMALIZED
       WITH RESPECT TO HEATING VALUE IN THE PRODUCT FUEL  IN 100
       LBS/106 BTU ........................... . ...................... - •  161
5-5    SUMMARY OF NET WATER CONSUMED FOR STANDARD SIZE  SYNTHETIC FUEL
       PLANTS ............ . ............... . ............ .... ....... .....  I62
5-6    REGIONAL SUMMARY  OF  NET WATER CONSUMED IN 10  GPD  FOR STANDARD
       SIZE SYNTHETIC FUEL  PLANTS ................... . ...... ...........  164
5-7    REGIONAL SUMMARY  OF  NET WATER CONSUMED NORMALIZED  WITH RESPECT
       TO THE HEATING VALUE IN THE  PRODUCT FUEL  IN GAL/106 BTU .......  165
5-8    SUMMARY OF WET SOLIDS RESIDUALS GENERATED FOR STANDARD SIZE
       SYNTHETIC FUEL PLANTS .................................. . .......
5-9    REGIONAL SUMMARY  OF  TOTAL WET RESIDUALS GENERATED  IN  10  TONS/
       DAY FOR STANDARD  SIZE  SYNTHETIC FUEL PLANTS ... ..... . ...........  173
5-10   REGIONAL SUMMARY  OF  TOTAL WET RESIDUALS GENERATED  NORMALIZED
       WITH RESPECT TO THE  HEATING VALUE IN THE PRODUCT FUEL IN
       LBS/106 BTU . . ........................... . .......... ............  174
5-11   OVERALL CONVERSION EFFICIENCY AND PERCENT UNRECOVERED HEAT
       DISSIPATED BY WET COOLING ...... ............ ... .......... .......  189
6-1    SUMMARY OF WATER  TREATMENT COSTS FOR STANDARD SIZE SYNTHETIC
       FUEL PLANTS . . ..................... . ......... ...... ........ .....  208
6-2    REGIONAL SUMMARY  OF  THE  COST OF WATER TREATMENT IN SYNTHETIC
       FUEL PLANTS IN C/106 BTU ..... . .............. . .............. ....  209
6-3 ,   SUMMARY OF THE ENERGY  CONSUMED IN WATER TREATMENT  IN  STANDARD
       SIZE SYNTHETIC FUEL  PLANTS ..... . ........ . . .......... . ........ . .  212
6-4    REGIONAL SUMMARY  OF  THE  ENERGY CONSUMED IN WATER TREATMENT
       IN SYNTHETIC FUEL PLANTS IN PERCENT OF PRODUCT ENERGY ..........  214
6-5    ENERGY REQUIRED FOR  WATER TREATMENT AS A PERCENTAGE OF THE
       TOTAL ENERGY REQUIREMENTS FOR PROCESS CONDENSATE TREATMENT.....  215
7-1    SUMMARY OF RESULTS BY  CONVERSION PROCESS ..... ............. .....  219
7-2    SUMMARY OF RESULTS BY  CONVERSION PROCESS AND COAL  RANK OR
       GRADE OF OIL SHALE ....... ........ ........ . . ..... ...............  220
7-3    TOTAL NET WATER CONSUMPTION FOR INTERMEDIATE AND MINIMUM
       PRACTICAL WET COOLING  AS A PERCENTAGE OF TOTAL NET WATER
       CONSUMPTION FOR HIGH WET COOLING. ...................... ........   229

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                                   Tables (ConL)
7-4    TOTAL NET WATER CONSUMED  BY  CONVERSION  PROCESS- .....-.•.-•<••••••  230

7-5    NUMBER OF STANDARD  SIZE PLANTS  REQUIRED TO  PRODUCE  1x10
       BEL/DAY OF SYNTHETIC  CRUDE OR ITS  EQUIVALENT OF  5.8xl012
       BTU/DAY .................................. 0 ................••••••  23°
7-6    SUMMARY OF RESULTS  FOR THE PRODUCTION OF 1x10 BBL/DAY OR ITS
       EQUIVALENT IN "OTHER FUELS OF 5. 8xl012 BTU/DAY. ..................  231
                                     XI

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                                              CONVERSION  FACTORS
 ACCELERATION
  ENERGY/AREA-TIME
 MASS/TIME
 MASS/VOLUME
 MISCELLANEOUS
to International System (SI) Units
Multiply
2
foot/second
free fall, standard

acre
feet

Btu (mean)
calorie (mean)
kilowatt-hours
Btu/foot hour
Btu/foot minute
Btu/foot second
calorie/cm minute

dyne
kilogram force (Kg )
pound force ( Ib r avoirdupois )

foot
mile
pound (avoirdupois)
ton (metric)
ton (short, 2000 Ib)
pound/hour
pound/minute
ton (short) /hour
ton (short)/day
gram/centimeter
pound/foot
pound/gallon (U.S. liquid)
2
Btu/hr-ft ~*F
Btu/kw-hr
Btu/lb
Btu/lbm-°F
gal/10 Btu
kilocalorie/kilogram
Btu/hour
Btu/minute
Btu/second
calorie/hour
calorie/minute
calorie/second
horsepower
atmosphere
foot of water (39.2*F)
psi (lbf/in )
lbf/foot2
foot/minute
foot/second
mi le/hour

51
.
3.048 x 10
9.807
3
4.047 x 10
9.290 x 10"
3
1.056 x 10
4.190
3.60 x 10
3.152 x 10"
1.891 x 10
1.135 x 10*
6.973 x 10
-5
1.00 x 10
9.807
4.448
-1
3.048 x 10
1.609 x 10
4.536 x 1C"1
1.00 x 10
9.072 x 10
1.260 x 10"^
7.560 x 10 j
2.520 x 10 *
1.050 x 10
1.00 x 103
1.602 x 10,
1.198 x 10

5.674
2.929 x 10"
2.324 x 10
4.184 x 10
3.585 x 10~12
4.184 x 10
2.929 x 10"1
1.757 x 10*
1.054 x 10
1.162 x 10*
6.973 x 10
4.184
7.457 A 10
1.013 x 105
2.989 x 103
6.895 x 10
4.788 x 101
5.08 x 10~3
3.048 x 10~7
4. 470 x 10
                                                                                      meter/second
                                                                                      meter/second
                                                                                       joule
                                                                                       joule
                                                                                       joule
 watt/meter
 watt/meter.
 watt/meter
 watt/meter
 newton
 newton
 newton


 meter
 meter


 kilogram
 kilogram
 kilogram


 kilogram/second
 kilogram/second
 kilogram/second
 kilogram/second


 kilogram/meter
 kilogram/meter_
 kilogram/meter


 joules/sec—m -*C
 joules/kw-sec
 joule/kg
 jouleAg-°C

 meter /joule
 joule/kg

 watt
 watt
 watt
watt
watt
watt
watt
                                                                                      pascal (=
                                                                                      pascal
                                                                                      pascal
                                                                                      pascal
                                                                                     meter/second
                                                                                     meter/second
                                                                                     meter/second
                                                                                                newton/m  )
TEMPERATURE
                                                             0.556  (DF  +  459.7)
                                                                                 (continued)
                                                            xii

-------
                                          Conversion Factors  (Cont.)
VOLUME
                        acre foot
                        barrel  (oil, 42 gal)
                        foot
                        gallon  (U.S. liquid)
1.590 x 10
1.233 x 10
2.B32 x 10_
3.785 x 10
                                                                        -1
                                                -2
                                                                                               To Obtain
VOLUME/TIME
                        { c /mi n
                        ft /sec
                        gal  (U.S. liquid)/day
                        gal  (U.S. llquid!/min
                                                              4. 7*9 x 10
                                      2.832
                                      4.381
                                      6.309
                                                -2
          -S
                        meter./second
                        meter /second
                        meter /second
                        meter /second
Other Conversion^ Factors

     Tfte following  table is his-zd on a density of water of 62.3 pounds per cubic foot.   This  is.  the density

of water at 6S"F  (20*C) and corresponds to 8«33 pounds of water per gallon.
acres
acres
acre-feet
acr^-f set
acre-f eet/year ............. .
acre- feet /year
acre-f eet/ytffl£-
acre-feet/year
barrels ,  oil
Btu ......... ............
Btu
cubic feet
cubic feet
cubic feet of water
cubic f eee/second. ,,.,.,
cubic feet/second
gallons
gallons
gallons
gallons of vster ........... , . ,
gallons/minute
gallons/minute
gallons/minute
gallons of vater/siinute
horsepower. „ . ...... , ........ ..
horsepower
kilowatt-hours
milligrams/liter
million gallons/day
million  gallons/day. . „
million gallons/day
million gallons of water/day
pounds of water
pounds of water
pound moles of gas . . ..... .....
square feet
t e mp e r a t ur e ,  * C
temperature,  *F-32
thousand pounds/hour
thousand pounds/hour
thousand pounds of water/hour
thousand pounds of water/hour
tons (short)
tons (short)
tons/day ........ „
tons/year
watts
4. 36
1.56
4. 36
3.26
1.3S
3.91
6.20
8.93
4.2 )
2.52
3.93
2.30
7.48
6.23
4. 49
6.46
3.07 x
2.38 x
1.34 x
8.33
1.61
2.23 x
l.<<4 •>,
5.00 x
6.11 x
2.55 x
3.41 x
1
1.12 x
1.55
6.34 x
3.47 x
1.20 *
1.60 x
3.80 x
2.30 x
1.8
5.56 x
1.2 x
4.38 x
2.00
2.88 x
2 x 10
9.07 x
8.33 x
2. 28 x
3.41
« 10
x 10'
» 10
x 10
x 10'
X 10'
y 10'
x 10'
: 10
x I1
x 10
X 10'
                                                                       -5
                                                                   x 10
                                                                       '
                                                                       -1
                                                                     10
                                                                     10"
                                                                     10
                                                                     10
                                                                     10
                                                                     10
                                                                     10
                                                                    10
                        square feet
                        nquare miles
                        cubic feet
                        gallons
                        .cubic feet/second
                        cubic iaeters/second
                        gallons/minute
                        million gallons/day
                        gallons
                        .calories
                        horsepowe r-hours
                        acre-feet
                        gallons
                        pounds of water
                        ,galIons/minute
                        Billion gallons/day
                        acre-feet
                        barrels, oil
                        cubic feet
                        .pounds of water
                        acre-feet/year
                        cubic feet/second
                        million gallons/day
                        thousand pounds of water/hr
                        .Btu/day
                        Btu/hour
                        Btu
                        parts/million
                        acre-fset/year
                        .cubic feet/second
                        gallons/minute
                        thousand pounds of water/hr
                        gallons of water
                        cubic feet of water
                        „standard cubic feet of gas
                        acres
                        32   *F
                        °C
                        tons/day
                        .tons/year
                        gallons of water/minute
                        millions gals of water/day
                        pounds
                        metric tons
                        .thousand pounds/hour
                        thousand pounds/hour
                        Btu/hour
                                                          Kill

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                            1.  EXECUTIVE SUMMARY
1-1  Process and Site Selections
     The synthetic fuel technologies examined include:  coal gasification to
convert coal to pipeline gas; "coal liquefaction to convert coal to low sulfur
fuel oil; coal refining to produce a de-ashed, low sulfur solvent refined
(clean) coal; and oil shale retorting to produce synthetic crude,,  A number
of processes were chosen for each conversion.  Detailed conceptual designs
for integrated mine-plant complexes were made for each of the representative
conversion processes in order to compare water requirements, types of water
treatment plants, and the quantities of wet-solid residuals generated.  The
processes and products chosen for comparison are shown in Table 1-1.  Except
for the commercially available Lurgi process, the processes chosen are repre-
sentative of those that have undergone extensive development and which are
sufficiently described in the available literature so that detailed process
calculations can be made.  The products chosen are synthetic fuels; the
production of chemicals from coal or shale, e.g., ammonia or methanol production
via coal gasification, was not considered.  Specific designs in the appendices
are based on standard size plants with the given product output.

     TABLE 1-1  PRODUCT FUEL OUTPUT OF STANDARD SIZE SYNTHETIC FUEL PLANTS
                                                                Product
 Technology and                                              Heating Value
Conversion Process            Product         Output         (10   Btu/day)
Coal Gasification           Pipeline Gas   250x10  scf/day        2.4
    Lurgi
    Synthane
    Hygas
    Bigas
Coal Liquefaction            Fuel Oil      50,000 barrels/day     3.1
    Synthoil
Coal Refining             Solvent Refined  10,000 tons/day        3.2
                              Coal
    SRC
Oil Shale                 Synthetic Crude  50,000 barrels/day     2.9
    Paraho Direct
    Paraho Indirect
    TOSCO II

-------
     Many site and process criteria combinations were studied in order to
obtain meaningful assessments on a regional and national level from detailed
local results.  Process criteria for the conversion of coal have been defined
based upon the quality of the foul condensate recovered after gasification or
liquefaction.  Low temperature gasifiers (e.g., Lurgi and Synthane), produce a
very dirty process condensate (typical values for bituminous coals:  BOD ^
10,000 mg/1, phenol ^ 3,000 mg/1 and ammonia ^ 7,000 mg/1).  High temperature
gasifiers (e.g., Koppers-Totzek and Bigas), produce a relatively clean condensate'
(typical values: ammonia i> 4,500 mg/1, BOD and phenol 'v small).  The intermediate
temperature Hygas gasifier produces a process condensate of intermediate
quality.  Both the Solvent Refined Coal  (SRC) and Synthoil processes have the
foulest condensates.  For oil shale conversion, the degree of water management
depends on the type of retort used.  For direct-heated retorting processes
(e.g., Paraho Direct), most of the water is recovered; however, for indirect-
heated processes (e.g., Paraho Indirect and TOSCO II), the water in the
combustion products is generally lost up the furnace stack and not recovered.
     As for site criteria, brackish ground water would have to be considered
an important conjunctive supply to surface waters in the West, while surface
waters are considered primarily in the East.  Eastern and Central States have
humid climates, while climates in the West are arid and semi-arid.  Eastern
and Central coals are both underground and surface mined, while Western coals
are primarily surface mined.  In the West, underground mining followed by
surface retorting of oil shale has been  investigated extensively.  In-situ
'retorting was not considered in the present study because it is still under
development and cannot yet be considered commercially, although it could
drastically reduce the water consumption.
     Site selection was based primarily  on the availability of coal and oil
shale, the rank of coal or oil shale, the type of mining  (underground or
surface) and the availability of surface and groundwater.  Coal mining regions
chosen were those where the largest and most easily mined deposits are
located.  In the West, these include the Powder River and Ft. Union regions
in Montana, Wyoming, and North Dakota, and the Four Corners region in New
Mexico.  In the Central and Eastern regions, the Illinois and Appalachian

-------
coal basins were selected.  Western coals are principally low sulfur sub-
bituminous and lignite, while Eastern and Central coals are mainly high
sulfur bituminous.  The only oil shale considered was high grade shale from
the Green River Formation.  Specific design examples were restricted to
shales with yields of about 30 to 35 gallons per ton, as might be found in
Colorado or Utah.
     Tables 1-2 and 1-3 list the plant-site combinations for the Eastern and
Central States, and Western States, respectively.  The number of plant-site
combinations chosen are sufficient to enable generalized rules to be derived
concerning the quantities of water consumed and wet-solid residuals generated
as a function of conversion technology and coal or oil shale region.  The
locations of these sites with respect to the major energy reserves and the
primary water resources characteristics are shown in Figures i-1 and 1-2.
The maps show more sites than the ones given in the tables.  Primary sites      I
correspond to the sites listed in Tables 1-2 and 1-3 and secondary sites were
selected to provide a larger study area with respect to water availability.
1.2  Water Supply and Demand
     A general assessment of the water resources data in the major U.S. coal
and oil shale regions was made.  Potential water supply sources for each site
were evaluated on a site specific basis in terms of total available water supply.
the needs and rights of other competing water users, and water quality.  Factors
which were considered were the extent and variability of nearby stream flows or
ground-water aquifers, legal institutions regulating the use of these waters,
environmental considerations, and the implications of competing users for
limited supplies in certain areas.  The institutional constraints include the
legal doctrines governing the use of water.  In the East this is generally the
Riparian Doctrine, which defines surface water rights as ownership of land next
to or traversing the natural stream.  In the West the Appropriation Doctrine
usually applies:  first appropriation of water conveys priority, independently
of the location of the land with respect to the water.  Other constraints may
involve competing claims, such -as Indian water rights.
         Principal among environmental considerations are the possibility of
the disruption of natural underground aquifers from the mining operation, and

-------
                 TABLE  1-2    PLANT-SITE  COMBINATIONS  FOR EASTERN AND  CENTRAL STATES

State
Alabama

Illinois







Indiana



Kentucky



Ohio


Pennsylvania

West Virginia





County
Jefferson
Marengo
Bureau
Shelby
St. Clair
White
Bureau
Fulton
St. Clair
Saline
Gibson
Vigo
Sullivan
Warrick
Floyd
Harlan
Muhlenberg
Pike
Gallia
Tuscarawas
Jefferson
Armstrong
Somerset
Fayette
Kanawha
Honongalia
Preston
Mingo
Water Source
Surface Ground
Alabama R.
Tombigbee R. X
X
Ohio R.
Ohio R.
Ohio R.
Illinois R.
X
Ohio R.
Ohio R.
White R.
White R.
Ohio R.
Ohio R.
Ohio R.
Ohio R.
Green R.
Ohio R.
Ohio R.
Muskijigun R. X
Ohio R.
Allegheny R.
Allegheny R.
Kanawha R.
Kanawha R.
Allegheny R.
Kanawha R.
Kanawha R.
a b
Mining Coal
U B
S L
U B
U B
U B
U B
S S
S B
S B
S B
U B
U B
S B
S B
U B
U B
S B
S B
U B
U B
S B
U B
U B
U B
U B
U B
U B
S B
Coal Gasification
High Temp. Gas if ier
Hygas Bigas
X
X
X
X


X



X
X

X





X
X
X

X

X

X
Low Temp. Gasif ier
Lurgi Synthane
X
X
X

X


X
X

X

X

X

X

X

X
X


X

X

Coal Liquefaction
and Coal Refining
Synthoil SRC
X
X
X


X

X

X
X


X

X

X

X
X

X




X
Plant-Site Combinations
No. Total State
3
6 9
3
1
1
1
1
2
1
1 11
3
1
1
2 7
1
1
1
1 4
1
4
3 8
2
1 3
1
1
1
1
2 6
a U • Underground; S - Surface.
b B - Bituminous; L - Lignite

-------
   TABLE  1-3   COAL AND OIL SHALE CONVERSION PLANT-SITE COMBINATIONS  FOR  WESTERN STATES


State
Montana







New
Mexico

North
Dakota






Wyoming










Mine
Decker-Diets
Foster Creek
U.S. Steel Chupp Mine
East Moorhead
Pumpkin Creek
Otter Creek
Colstrip
Coalridge
Gallup
El Paso
We sco
Scran ton
Bentley
Underwood
Knife River
Center
Slope
Dickinson
Williston
Belle Ayr
Glllette-Wyodak
Spotted Horse Strip
Hanna
Antelope Creek Mine
Lake-de-Smet
Kerrraerer
Jim Bridger
Rainbow #8

Water Source
Surface Ground
X
Tongue R.
Yellowstone R.
Powder R.
Tongue R.
JC
Yellowstone R.
Missouri River
X
San Juan R.
San Juan R.
Grand R.
Knife R.
L. Sakakawea
Knife R.
Knife R.
Yellowstone R.
L. Sakakawea
Missouri R.
Crazy Womaji Cr.
Crazy Woman Cr.
Powder R.
Medicine Bow
Beavsr Cr. M
Tongue R-
Hams Fork
Green R.
Green R.

fa
Hining Coal
S S
S S
S L
S L
S L
S L
S S
S L
S S
S S
S S
S L
S L
S L
S L
S L
S 1
S L
E L
S S
S S
S S
E S
S S
S S
S B
S S
U B
Coal Gasification
High Temp.Gasifier Low Temp. Gasif ier
Hygss Bigas Lurgi Synthane
X X
X
X
X


X >

X X
X X
X
X


X
X
X

X
X
X
X
X
X X

X X


Coal Liquefaction
and Coal Refining
Synthoil SRC




X
a
X
X
X



X
X



X


X


X
X

X
X

Plant-Site Combinations
No. Total State
2
1
1
1
1
1
3
1 11
3
2
1 6
1
1
1
1
1
1
1
i e
i
2
1
1
3
I
2
2
1 14
State
Colorado
Mine
Parachute Creek
Water Source
Surface Ground
Colorado R,
B c
Mining Shale
U HG
Direct Retort
Psraho Diract
X
Indirect Retort
ParaJio Indirect TOSCO II
X X
Plant-Site Combinations
No. Total State
- 	
3 3
0 =* Underground;  S «» Surface
B ffl Bituminous; L « Lignite; S
HG =* High grace shale
Subbi tuminous

-------
                                  1
SITE J^CATiQNS
 H PRIMARY SITES
 n SECONDARY SITES
   ILLINOIS COALREGION

Figure 1-1  Coal conversion site locations in
       Eastern and Central states.
 (continued)

-------
                                      SITE  LOCATIONS
                                CAMBRIA
                                a
                             ARMSTR
                                SOMERSET
                                          PRIMARY SITES
                                        D SECONDARY SITES
APPALACHIAN COAL REGION
 Figure 1-1  (concluded).

-------
                                                              NORTH DAKOTA,
                                                  KNIFE RIVER

                                                DICKENSONa
                                                 I
                                                SLOPE m   BBENTLY

                                                     • SCR ANTON
                                                        UPPER
                                                        MISSOURI
          UTAH
                     RAIN80W8
               HANNAH COAL FIELD
           BRIDGER
KAIMCHjm »«  «l"l Dn.uwtJiH —


j	/,TRACTW-a/VK^  WYOMING
                           ®JTRACT U-a/U-b
                               H TRACT C
                                     ^? DEVELOPMENT
UPPER   COLORADO'X
   RIVER  BASIN
                                      SITE  LOCATIONS

                                         PRIMARY SITES
                                       • SECONC&RYSITES
      Figure 1-2  Coal and oil shale conversion site locations in Western states.

-------
surface and groundwater contamination from the leaching of disposed wastes or
from acid mine drainage; the latter particularly presents problems in the
Appalachian coal region.
     The adequacy of the water supply at each primary site having a stream as
its water source was assessed through a comparison of a typical plant use
with expected low flows in the stream.  In the Appalachian coal region, where
coal is available, there are a number of large rivers contiguous or adjacent
to many of the sites that can provide a sufficient and reliable supply of water
to support one or more large mine-plant coal conversion complexes.  This applies
to all plant sites in the vicinity of the Ohio, Allegheny, Tennessee, Tombigbee
and Kanawha-New Rivers.  In most of these instances present water use data and
future demand projections indicate a significant surplus beyond expected use,
even under low flow conditions.
     The surface water supplies are much less reliable in the smaller streams,
away from the major rivers.  Regions generally found to have limited water
supplies for energy development include:  the upper reaches of the Cumberland
and Kentucky Rivers in eastern Kentucky;  the eastern Kentucky and adjacent
West Virginia coal regions in the Big Sandy River Basin; and northern West
Virginia and western Pennsylvania in the Monongahela River Basin, except those
areas that can be supplied from the Allegheny, Ohio or Susquehanna Rivers.
Under future conditions a minor surplus will exist for the Tuscarawas River in
Ohio.  In these water-limited areas extreme low flows are practically zero and
a coal conversion complex could easily represent a significant portion of the
seasonal low flow.  In order for a plant to be sited here an alternative or
supplemental supply must be assured.  Figure 1-3 shows the availability of
water in the Appalachian coal region.
     Within the Illinois coal region, the Ohio and Mississippi Rivers have
sufficient and reliable water supplies to support one or more large mine-plant
coal conversion complexes.  The lower section of the Kaskaskia, Illinois and
Wabash Rivers in Illinois; the Wabash and White Rivers in Indiana; and the
Green River in Kentucky also have reliable supplies.  Under future conditions
in the year 2000 deficit supplies are indicated for the Wabash River in Illinois
Figure 1-4 shows the availability of water in the Illinois coal region.

-------
                                                  SITE LOCATIONS
                                                  •  primary sll«8
                                                  a secondary sltei
                                             WATER AVAILABILITY
                                                        marginal
                                                        adequate
              APPALACHIAN COAL REGION
Figure  1-3  Water  availability in the Appalachian  coal  region.
                            10

-------
                                      SITE LOCATIONS
                                          primary sites
                                         secondary sites
                       	,  WATER AVAILABILITY
                                 I        ^^\ inadequate
                                              marginal
                                              adequate
INDIANA

    ILLINOIS  COAL REGION
Figure 1-4.  Water availability in the Illinois coal region.

-------
     Groundwater was also specified as a water source for some sites located
in Illinois and Ohio.  The Wabash and White subbasins probably have the highest
potential of all Ohio River subbasins for additional groundwater development.
Conditions appear to be most favorable for groundwater development in parts of
Alabama.
     The water resources in the major coal and oil shale bearing regions of
the Western United States can be conveniently separated into two major water
shed regions:  the Upper Missouri River Basin and the Upper Colorado River
Basin.  Each one of the Basins was further divided into several hydroXogic
subregions of interest with respect to water availability for energy development.
Estimates were made of water availability within each subregibn for coal and
oil shale production.
     In the Powder River and Ft. Union coal regions shortages occur in parts
of the Yellowstone River Basin during periods of low flow.   Water can be
obtained by appropriation and transferred by transbasin diversions.  However,
there are a number of serious institutional conflicts in the region, particularly
in Montana and Wyoming, concerning the authority to allocate water.  Competitive
pressures from agricultural water users are very high and irrigation needs are
large because of the semi-arid climate. . Environmental problems associated
with the disruption of natural underground reservoirs by mining may also be
important.            '
     The coal and oil shale regions of the Upper Colorado River Basin are situated
in an arid area marked by an inadequate water supply of poor quality.  The
region is subjected to highly variable annual stream flows I  It may be possible
to utilize groundwater as a conjunctive supply, but this water is generally of
a poor quality and often drawn from underground reservoirs which would
eventually be depleted.  However, we should note that for some proposed oil shale
developments, the quantity of groundwater produced by mine dewatering would exceed
the plant water requirements.  Strong competition exists'among agricultural,
municipal and industrial users for the available supply, most of which is now
either appropriated or over-appropriated.  Serious institutional conflicts
involving Indian water rights also exist in the area.
     Because agriculture has long been an important part of the Western economy,
numerous storage reservoirs have been built throughout both Basins to more
evenly distribute spring runoff during the year, particularly the growing season.
                                        12

-------
     Two limiting cases were examined with respect to water availability in
the West:  low water demand and high water demand.  For low water demand, two
standard size coal or oil shale conversion plants  (without regard to type)
were located in each of the hydrologic subregions.  This corresponds to the
production of from 0.5 to 1.0x10  barrels/day of synthetic crude, or its
equivalent in other fuels.  For high water demand, 1x10  barrels/day of
                                                           12
synthetic crude, or its equivalent in other fuels of 5.8x10   Btu/day, were
produced in each of the three principal coal bearing regions  (Ft. Union,
Powder River and Four Corners) and in the principal oil shale region (Green
River Formation), for a total production of 4x10  barrels/day.
     Low water demand can be accommodated by available supplies in most of the
subregions.  However, chronic water shortages do exist, especially in the
northern Wyoming area of the Powder River coal region and the Tongue-Rosebud
drainage area in the Ft. Union coal region.  In the Four Corners-San Juan
region in northwestern New Mexico and the Belle-Fourche-Cheyenne basin in
northeast Wyoming, the water demands are greater than about twenty percent of
the total water availability, which may be considered to be excessive.   For  high
water demand, projected loads cannot be accommodated by available supplies in
most subregions.  Only in the Yellowstone, Upper Missouri, Lower Green and
Upper Colorado mainstem basins does it appear that sufficient supplies are
available for the expected loads of energy production.  However, water avail-
ability in the Upper Colorado River Basin may be limited because all of the
water rights to most of the free flowing water in the Basin are already
allocated.  These rights would have to be transferred to support additional
energy development or water transferred by transbasin diversion.
     Estimates have been made of the cost of transporting water to the point
of use from major interstate rivers and riverways.  Figure 1-5 shows the cost
of transporting water to all sites for low water demand.  The cost of water
determines the degree to which wet cooling should be used.  If water costs
less than $0.25/1000 gals, a high degree of wet cooling should be used; if it
costs greater than $1.50/ 1000 gals, a minimum degree of wet  cooling should be
used; in between these extremes, intermediate wet cooling should be used.
Figure 1-5 shows that except for plants located near the mainstem of major rivers
or near large reservoirs, intermediate or minimum practical wet cooling is
desirable for most of the sites in the Western study area.
                                        13

-------
                                            NORTH DAKOTA
                                        UPPER
                                        MISSOURI
                                        RIVER BASIN
                        WYOMING
                                         Cost Of \\bter
                                         (S/IOQO GALS)
                                              <0-25
                          NEW MEXJCQ
UPPER  COLORADO
  RIVER  BAS!
                                          SITE LDCATiONS
                                           primary sites

                                           secondary site
Figure 1-5 Cost of transporting water to specific site

         locations in the Western states.
                   14

-------
     For large scale synthetic fuel production, it is more  economical  to  have
a large single pipeline built to transport water  to  a large number of  plants
than to have a large number of individual pipelines  supplying  individual
plants.  Figure 1-6 shows the cost of transporting large quantities of water
(high water demand) to some of the major coal producing areas  and indicates
that except for large scale development near the  mainstem of   major rivers,
intermediate cooling is desirable for most of the study region.
1.3  Process-Site Results
     The process-site results are summarized in Table 1-4.  They are presented
by conversion process with no distinction made between coal rank, except  for
the mining rates.   Results have been normalized  with respect  to the heating
value of the product.  The difference in mining rates is due to the variation
in the heating values of the different rank coals and the different conversion
efficiencies of the processes considered.
Water Consumed
     Estimates of water consumption  are net; all  major effluent streams
are assumed to be recycled or reused within the mine or plant  after any neces-
sary treatment.  These streams include the organically contaminated waters
generated in the conversion process, which are unfit for disposal without
treatment, and the highly saline water blown down from evaporative cooling
systems.  Water is only released to  evaporation ponds as a  method of salt
disposal, when the usual inorganic concentration  of  released wastes is about 2
percent  (for example, ion exchange regeneration wastes and  cooling tower
blowdown when more than 10 cycles of concentration are used and less than 10
percent of the intake water is released).  However,  we have generally  assumed
that these wastes are usually disposed of with the coal ash.   The rest of the
water consumed leaves the plant as vapor, as bonded  hydrogen  (after hydrogenation)
in the product, or as occluded water in the solid residues. Dirty water  is
cleaned, but only for reuse and not  for returning it to a receiving water.
     In general the total quantity of net water consumed depends primarily on
the quantity of water evaporated in  cooling.  The cost and  availability of
water determine the degree to which  wet cooling should be used.  Three cooling
options were considered representing different kinds of wet evaporative cooling
for turbine condensers and gas-compressor interstage coolers.
                                        15

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                                                      UPPER
                                                      MISSOURI
                                                      RIVER BASIN
UPPER  COLORADO
  RIVER  BASIN
                                                       Cost Of Water
                                                       ($/iooo  GALS)
                                                            <0-25
                                                               25- 1-50
                                                            > I -50
SITE LOCATIONS
a primary sites
• secondary sites
  pipeline
        Figure 1-6  Cost of transporting water to coal regions

                    in the Western states.
                                16

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            TABLE  1-4  SUMMARY OF RESULTS BY  CONVERSION  PROCESS

Coal Gasification
Lurgi
Synth Mis
Hygas
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC
Oil Shale
Paraho Direct
Paraho Ind.
TOSCO II
Reactor Type

Fixed Bed
Fluid Bed
Fluid Bed
Hydrogaci tier
Entrained Flow

Catalytic Fixed
Bad

Diseolver

Direct Retorting
Indirect Retort.
Indirect Retort.
Hinlrni_Rate3 (lb/10 Btui
Subbi-
Lignite tuminous Bituainous

250-360 160-220 140-160
250s 180-220* 130-160
200-240 120-160 110-140
220-270 - 110-140

120-170 100-120

130-280 1&0-180 110 -140
High Grade Shale
630
720
510
$
N«t Water Consuwpt^on (aal/10 Btu!
High Wet Intermediate Min. Practical
Cooling Wet Cooling Het Cooling

18-30 9-22 7-21
22-27 16-19 15-17
21-26 16-19 15-19
25-27 16-18 14-17

17-21 11-14 10-14

13-21 8-13 7-11

IS
28
39
Wet Solid
Residuals
(lb/106 Btu)

59-126
40-56
32-64
27-61

7-28

12-40

520
630
470
Water Treatment
Cost
K/iO6 Btu)

5.4-14.0
1.7-4.3
2.3-4.1
1.6-2.8

0.3-1.1

0.7-1.6




Energy
(ft Prod. Energy)

2.2-8.3
1.3-2.2
1.0-4.0
1.7-3.0

0.04-0.6

0.1-1.0




frcsa Ref. 3.  Refers only to niffnber arid not to

-------
      Where water  is plentiful  and  inexpensive  to transport,  high wet cooling
 should be used.  The cooling  loads  on  both  the  turbine  condensers and inter-
 stage coolers  are  taken  to be all wet  cooled.   For the  Lurgi  process a detailed
 thermal  balance was not  available:  wet  cooling was assumed to be used to
 dispose  of  33  percent  of the  total  unrecovered  heat.  The same value was one
 estimated  for  the  Synthane process  to  facilitate comparison.   This value falls
                                                           4
 within  the  range of Lurgi design data.   The El  Paso design  indicates that 36
 percent of  the unrecovered heat is  dissipated by evaporative  cooling, while
 the Wesco  design   indicates  26  percent.
      Where water  is marginally  available or moderately  expensive to transport,
 intermediate cooling  should  be  used.    Intermediate cooling assumes that wet
 cooling handles 10 percent of the  cooling load  on the turbine condensers and
 all of the load on the interstage  coolers.   For the Lurgi process, 18 percent
 of the unrecovered heat is assumed to  be dissipated by  wet cooling.  Again,
 this is based on  Synthane process  estimates.  The oil shale processes are
 assumed to use an  intermediate  degree  of wet cooling.   For the Paraho Direct
 process, 28 percent  of the unrecovered heat is  dissipated by  wet cooling.   For
 both the Paraho Indirect and TOSCO  II  processes 18-19 percent is dissipated.
      Where water  is  scarce or expensive  to  transport, minimum practical wet
 cooling should be  used.   Minimum practical  wet  cooling  assumes that wet cooling
 dissipates  10 percent  of the cooling  load on the turbine  condensers and 50
 percent of  the load on the interstage  coolers.   For this  case the Lurgi process
 is assumed  to  dissipate  15 percent  of  the unrecovered heat by wet cooling;
 again  it is  based  on the estimates  for the  Synthane process.
     High wet  cooling  does not  mean that all of the unrecovered heat is
 dissipated by  wet  cooling, since an appreciable fraction  will be lost directly
 to the atmosphere.  Minimum practical  wet cooling does  not mean that none  of
 the unrecovered heat is  dissipated  by  wet cooling,  since  this is not economical.
 For a given size conversion plant,  the quantity of water  consumed by cooling
 mainly depends on  the  overall conversion efficiency and the percent of unrecovered
 heat dissipated by wet cooling.  All of  the unrecovered heat  not dissipated by
 wet cooling is lost directly to the atmosphere  while the  rest of the heat  is
 transferred to the atmosphere by direct  cooling.
     For coal gasification and  liquefaction the total net  water consumption
 for a given process at a  given  site with intermediate wet  cooling  is  about  72
percent of the total net  water  consumption  for  high wet cooling, and  66 percent
with minimum practical wet cooling; the  percentages for coal refining are 63
and 56 percent, respectively.
                                       18

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     Besides cooling,  the water  consumption  estimates  include  the process
water requirements, the water  required  for the  mining  and preparation  of the
coal and shale, and for the  disposal  of ash  or  spent shale which is  a  function
of location through the amount of material that must be  mined  or disposed.
Sulfur removal also consumes water:   the amount depends  not  only on  the coal,
but also on the conversion process.   Water is also needed for  a number of
other purposes  (e.g.,  land reclamation)  that depend on climate.  Generally any
one requirement is not large and the  needs can  be  met  with lower quality
water.  Nevertheless,  when the requirements  are taken  together, they are
significant and cannot be  neglected  in any  plant  water  balance, although
general rules for  the  amount consumed are not easily stated.   Differences in
consumption in this category for a  given coal conversion process, however, do
not vary by more than  15 percent between regions,  except for the Four  Corners
region.  The difference is somewhat greater  when this  region is compared with
others, since larger amounts of  water are needed there for handling  the high
ash Navajo coal and for dust control  and revegetation.
     In general the net water  requirements are  largest for coal gasification,
followed by coal liquefaction  and coal  refining.  The  difference between the
latter two processes is relatively  small. The  differences in  net water
consumption as a function  of coal rank  are small,  except for the Lurgi process
for which the smallest requirement  is for wet lignite  coals,   The Lurgi process
accepts wet coal and the  large quantities of dirty condensate  produced are
treated for reuse  and  are  subtracted  from the process  requirement.   For inter-
mediate wet cooling the water  requirements for  the proposed  Paraho Direct
process designs are comparable with those for the  Synthoil process,  which
produces roughly the same  product.  However, the proposed Paraho Indirect and
TOSCO II process designs have  the largest net water requirements due mainly to
the larger requirements for  spent shale disposal and revegetation.
     The maximum difference  in water  consumption between high  cooling  and
minimum practical  wet  cooling,across  all the sites and gasification  processes
of this study,is about a  factor  of  4, pointing  up  the  importance of  the choice
of process  and cooling design in the amount of water  consumed in  synthetic
fuel production. The maximum difference in water consumption between high wet
                                        19

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 cooling  and minimum practical wet  cooling  at  a given  coal gasification  site  is
 approximately 10  gal/10   Btu.   Minimum practical wet  cooling will  be  used  if
 water is relatively expensive,  that  is about  $1.50/1000  gal or  more.  Even
 so,  minimum practical cooling will cost  about 1.5C/10 Btu more than  high  wet
 cooling  because of the higher annual capital  investment  costs of dry  cooling
 systems.
      Differences  in water consumption are  relatively  small between the  Illinois
 and Appalachian coal regions  for bituminous  coals,  and the Powder  River and
 Ft.  Union coal regions for subbituminous coals  for  a  given coal conversion
 process  and cooling option: differences  are  no more than 15 percent,  with  the
 absolute difference no more than 2.5 gal/10   Btu.   However, for lignite coals,
 the differences between  the Eastern  and  Western  regions  are larger: the
 maximum  is about 6 gal/10  Btu  for the Lurgi  process  and 4 gal/10   Btu  for
 the SRC  process.
      In  a particular coal bearing  region,  differences in the  water requirements
 between  the four coal gasification processes  that we  have considered are due
 principally to the differences  in  the process water requirement and in  the
 estimated overall plant  efficiency resulting  in different cooling water
 requirements.
      For each process the average  water  consumed is relatively  insensitive to
 the  coal bearing  region; variations  for  a given cooling option  from site to
 site  within the region are small for all of the processes except possibly  for
 the  Lurgi and SRC processes,  for reasons which  were discussed above.  However,
within a given region there might  be large variations in water  availability
 and water costs:  different cooling options at different  sites will produce
 large differences in cooling water consumption  and plant water  requirements
 (see  Figures  1-3  to 1-6).
      Figure 1-7 shows the total water consumed,  normalized with respect to the
heating  value  of  the product  fuel, for each  cooling option:   coal  rank  and
regional  difference are  averaged out for each coal  conversion technology.
      Table  1-5  compares  the results  of the present  study with those of  two
recently published  studies  in which  regional  and national fuel production  was
estimated based on  water  availability.   Except for  the oil shale results
                                        20

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                                     WET COOLING OPTION
30
25  _
20
10
                 ! HIGH

                 | INTERMEDIATE

                 I MINIMUM PRACTICAL
                                                               DIRECT
                                                               RETORT
INDIRECT
 RETORT
        COAL GASIFICATION
                          COAL LIQUEFACTION
                                               COAL REFINING
                                                                   OIL SHALE
            Figure  1-7    Average  total water  consumed  normalized with

                  respect to  the heating value  of  the product fuel

-------
             TABLE 1-5  COMPARISON OF NET WATER CONSUMED  (GAL/10  BTU)
                            Ref. 1
Ref.  2
Present Study
Coal gasification
  (Pipeline gas)
     Eastern  coals
     Western  coals

 Coal liquefaction
      Eastern  coals
      Western  coals
 Coal refining
      Eastern  coals
      Western  coals
 Oil Shale
      Surface  mine
      Underground mine
25-173

25-212

25-221
25-271


19-28
18-30
66-69
124-126*
27-32+
56-60*
100-114
44-48
20-22
10**
19-27
19-31
7-28

12-30

12-21
10-19
6-17
7-21

18-29
  Fixed bed gasifier
 *Fluidized bed gasifier
 **Includes moisture in raw  coal
which  are  based  on  design data,  the  results of  the  present study for net water
consumed are  considerably lower  than those of the other two studies.  The Lurgi
                  4          5
designs of El Paso   and Wesco give  a net water consumption of 37 and
30 gal/10  Btu,  respectively, which  are comparable  to the high wet cooling
estimates  of  the present study.  Our high wet cooling estimates are comparable
to the low values of Ref. 1.
     Not enough detail was given in  References  1 a_nd  2 to explain the widely
differing  quantities.  However,  in a comparison of  earlier assessments,
Goldstein  and Probstein  point out that the principal difference is in the
method of  estimating the cooling water makeup requirements.   Another important
difference, although not as important as the difference  in the  cooling water
requirements, is the water consumed  for mining,  reclamation,  evaporation,
                                        22

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solids disposal and other uses, which is very much site specific.  In any
event some of the higher estimates of References 1 and 2 are unrealistic.  For
example, for a coal gasification plant designed to be extremely .wasteful of
water, the total net water consumption could be as high as 100 gal/10  Btu,
which is about 3 times the Lurgi design values, and about one-half of the
largest value shown in Table 2-4.  The largest part is the water consumed for
cooling, estimated to be 45 gal/ 10° Btu,  This is based on a conversion
efficiency of 65 percent with  all of the unrecovered heat dissipated by wet
cooling, a condition which is  not realistic..  In the Lurgi process,, if all of
the dirty process condensate were to be disposed of by evaporation and not
reused in the cooling system,  then the total process water consumed would be
the total steam fed to the reactors, about 30 gal/10  Btu.  Mining, flue gas
desulfurization, reclamation and all other water requirements should not
exceed 25 gal/10  Btu,
     In a plant designed for a relatively high, degree of water reuse and
conservation, only about 33 percent of the unrecovered heat would be dissipated
by wet cooling, so that 15 gal/10  Btu would be consumed by cooling, compared
to 45 gal/10  Btu.  All of the process water condensate would be reused and
the mining, flue gas, and all  other water requirements could be reduced by 75
                      fi                       6
percent from 25 gal/10" Btu to about 7 gal/ 10  Btu.,  The total water consumed
for a plant not wasteful of water, but at the same time not designed for
                                                   6
minimum water consumption,, would be about 22 gal/10  Btu, as compared to 100
gal/10  Btu for a plant extremely wasteful of water.  Coal liquefaction and
coal refining processes are more efficient and do not produce as much dirty
condensate so that the high estimates for these processes would be much lower.
Wet-Solid.Residuals
     Solid residues generated  in coal and oil shale conversion plants are
generally disposed of wet with occluded water.  The principal residuals in
coal conversion plants are coal ash and where flue gas scrubbing is used, flue
gas desulfurization sludge.  In oil shale plants, the principal residual is
spent.shale.  Sludges from water treatment plants have also been considered.
                     ^
Between 3 and 15 x 10" tons/day of wet solids are disposed of for  coal
gasification plants,, "L and 4 x 10  tons/day for coal  liquefaction  plants, and
2 and 6 x 10  tons/day for solvent refined coal.  Outstripping all of the coal
conversion residuals by an order of magnitude are those from oil shale processing:
                                        23

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                        -J                          O
between  68  and  104  x 10  tons/day  (62  and 97  x  10 metric tons/day)  of wet
solids are  generated for  the  three  oil shale  conversion processes considered
here. In-situ or modified in-situ processing  have not been considered in this
study.   A summary of the  wet-solid  residuals  generated by each conversion
process, normalized with  respect to the heating value of the product, is
shown in Table  1-4.
     The quantity of the  residuals  depends on:  the ash content of coal, the
salt content of the source water, and  the sulfur content of coal when flue gas
desulfurization is  used on coal-burning plant boilers.   The maximum residuals
produced by each process  depend on  the site.
     The largest quantities  of  residuals for  the Lurgi, Hygas, and Synthoil
processes  occur in  areas  with the highest ash coals;  i.e., in parts of Alabama
 and Four Corners,   New Mexico.  For the Synthane and  SRC processes the largest
 residuals  are generated at sites using brackish groundwater.  For the Bigas
process  the quantities of both  ash  and flue gas desulfurization sludge deter-
mine the sites  with the largest residuals.
     Except for the Lurgi process,  the wet-solids generated by the three other
coal gasification processes  are relatively insensitive to process.  In general
the Lurgi process generates  more wet-solids because of the large quantity of
boiler feed treatment wastewater required.  The total wet residuals, normalized
with respect to the heating  value of the product, are comparable for the
Synthoil and SRC processes;  the SRC process has a slightly higher value.  The
larger quantities of wet  residuals  for coal gasification are attributed to
flue gas desulfurization,  which is  not required for the liquefaction and coal
refining processes.
Wastewater  Treatment
     In  estimating  consumptive  water requirements and wet-solid residuals, it
was assumed that no  water  streams leave the mine-plant boundaries and that all
effluent streams are recycled or reused within  the mine or plant after treatment.
The water treatment  plants are  not  designed to  return flow to receiving waters.
Returning water to  a source  is  not  economic when the  water must be cleaned to
a quality equal to  or  better  than the  source  water in order to meet  environ-
mental regulations.
     Cost and energy estimates  for water  treatment are much  less  well defined
than the  water and solid residual quantities.   Although the water treatment
                                        24

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technologies considered are achievable,  experimental evidence  for  coal
conversion process waters is not  available  to  fully assess  them.   For this
reason designs and costs must be  regarded with a greater degree  of uncertainty
than the estimates of water quantity  requirements.   Because of the large
number of plant-site combinations,  all various water treatment options  for
each plant-site combination were  not  examined.   Instead one or two water  flow
diagrams, each applicable to one  or more processes,  were used  at many sites.
     In any synthetic fuel plant, high quality water is required for the
process, intermediate quality is  required for  cooling and low  quality for
disposal and mine uses.  The two  largest water treatment costs are for  the
treatment of the raw water to boiler  water  quality  and for  the treatment  of
the low quality process condensate  to make  it  suitable for  use in  the cooling
tower.  The lowest cost is for  treatment within the cooling tower.  Figure 1-8
is a general water treatment scheme for  a coal conversion plant  generating
dirty process water.  The scheme  is not  unique, but does contain the main
components of any water treatment plant:  boiler feed water preparation,
process water or condensate cleanup,  and cooling water treatment*   The  three
main streams are shown with heavy lines.  Details of the water treatment  block
diagrams used for all of the processes are  given in Appendix 11.
     Boiler feed water preparation  includes occasional lime soda softening,
electrodialysis on all plants when  the raw  intake water is  brackish, and.  ion
exchange.  Foul condensate treatment  includes  phenol extraction, ammonia
separation, and biotreatment. Phenol  extraction, involving  solvent extraction
of phenolic compounds in which  phenol is recovered  and sold to help defray
treatment costs, is used only when  the foul condensate is highly concentrated.
The process was not used for Lurgi  or Synthane processes fed by  bituminous
coal, nor was it used for the Hygas and  Bigas  processes. Ammonia  separation,
used for all process-site combinations,  is  a distillative extractive process,
where the ammonia is assumed recovered as a 30 wt % solution and sold to  help
defray costs.  Because of the lack  of information on how much  organic contami-
nation is accept. _ole in cooling water, biotreatment is used on dirty condensate
from all plants except Bigas.   Cooling water treatment involves  lime soda
                                         25

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                                     RAW WATER
                                       0
                                                  EVAPORATION
Figure 1-8   Water  treatment flow diagram for coal conversion plant
 generating dirty process water (dashed boxes indicate the require-
 ments are not necessary for every plant).  (Reprinted from Ref. 3
 with the permission of The  MIT Press.   Copyright 1978 by the
 Massachusetts Institute of  Technology)
                            26

-------
softening of the raw water for cooling tower makeup, filtration of  the
effluent water from biotreatment, acid treatment  of all high alkalinity
cooling water makeup streams, the addition  of biocide  anticorrosion chemicals
and suspending agents., and lime  soda  softening  of the  cooling tower blowdown.
     Table 1-4 also summarizes the  costs  of water treatment, not including the
cost of residuals disposal,.  The costs of water treatment for oil shale were
not calculated.  For each process,  except Bigas,  the largest water  treatment
cost corresponds to the use of brackish water as  a raw water source and reflects
the high costs of boiler feed water treatment associated with demineralization.
The highest cost is for the Lurgi process;  the  quantities of steam  required
and dirty condensate produced are greater than  those for the coal liquefaction
and coal refining processes.  Although the  process condensates for  these last
two processes have the poorest quality, the costs are  determined primarily by
the quantities of process condensate  produced and boiler feed water required,
which are quite low for the Synthoil  and  SRC processes.  The cost of water
treatment, after taking credit for  byproduct ammonia,  is not expected to exceed
7 percent of the sale price of the  product  fuel for any of the plants.
     The energy required for the water treatment  plants is controlled by the
amount needed for ammonia separation, an  amount directly proportional to the
rate of foul condensate  production.  Referring to Table 1-4, the largest energy
requirements for any conversion process are for the Lurgi process,  followed
by the three other gasification processes   Again  the liquefaction and clean
coal processes have the lowest energy requirements.  Large amounts  of energy
are also required if electrodialysis  is required  to demineralize brackish
water for boiler feed water.  The total energy  requirements for the water
treatment plants fall in the range  of 0.04  to over 8 percent of the product
energy, or about 0.03 to 6 percent  of the energy  in the feed coal.
 1.4  Recommendations
     1.   The water  quantity  estimates and estimating procedures given  in  this
 report  are  intended for use  in  determining the  impact  of  a  coal conversion plant
 on local  water supplies.   Some  current estimates, as  noted  in  this  report,  are
 considered  excessive.  Quantity estimates in large excess  of  those  given  here
 should  be considered excessive;  transference of quantity  estimates  from one  site
                                       27

-------
to another is not usually accurate; transference of quantity estimates from
one process to another is not usually accurate.  The most reliable full-scale
engineering designs published to date are within the ranges of water  consumption
given in this report.
     2.  The major use of water in coal conversion plants is water evaporated
for cooling.  Since much of the nation's coal is in areas where water is
critically lacking, further study into the cost and methods of conserving
cooling water is justified.  Investigations of interstage coolers on  hydrogen
compressors, oxygen compressors and synthesis gas compressors will require
only a small effort and give important guidance.  In addition, condenser
cooling on the acid gas absorber regenerator should also be investigated.
     3.  The quantity  estimates made in this report are predicated on complete
water  reuse.  It is extremely probable that technology exists to treat effluent
waters adequately, and general cost and energy estimates have been made.  Only
reasonably  standard technologies have been considered in this study,  such as
liquid-liquid extraction or biological oxidation.  Advanced innovative
technologies such  as resin adsorption and the use of sequenced treatments
instead of  single  unit treatments could be considered.  A careful selection of
innovative  technologies could be undertaken to show the potential savings and
to recommend the type  of research or development work needed to validate the
estimated saving.
     4. The disposal of solid wastes should also be addressed.
     5.  This study refers to individual conversion plants at individual sites.
No conclusions have been reached to determine whether certain conversion
processes are most appropriate at certain sites.  No conclusions should be
reached until the study of waste solids disposal is complete.  Upon completion
of the study of waste solids disposal, the question of matching processes to
sites, coals and water supplies can, and should, be addressed.
References - Section 1
1.   Harte, J.  and El-Gasseir, M., "Energy and Water", Science, 199,
     February 10, 1978.
2.   Energy Research and Development Administration,"Alternative Fuels
     Demonstration Program.  Final Environmental Impact Statement,"
     ERDA-1547,  Washington, D.C.,  September 1977.
3.   Probstein,  R.F.  and Gold, H., Water in Synthetic Fuel Production -
     The  Technology and Alternatives, MIT Press, Cambridge, Mass. 1978.
                                       28

-------
4.    Gibson, C.R., Hammons, G.A., and Cameron, D.S.,  "Environmental
     Aspects of El Paso's Burnham I Coal Gasification Complex,"  in
     Proceedings, Environmental  Aspects of Fuel  Conversion Technology
     (May 1974, St. Louis, Missouri), pp 91-100,  Report No, EPA-650/2-74-118
     (NTIS No.. PB 238304), Environmental Protection Agency, Research Triangle
     Park, N.C., October  1974.

5.    Berty, T.E. and Moe, J.M.,  "Environmental Aspects of the Wesco
     Coal Gasification Plant," in Proceedings, Environmental. Aspects of
     Fuel ConversionJTechnol_og_y_	(M£V_f__1974 ,.  St.  Louis , _Missouri ?
     pp 101-106, Report No.~Ep"A-650/2-"74^118 (NTIS No. PB 238304"), Environ-
     mental Protection Agency, Research Triangle Park,. N.C., October 1974.

6,    Goldstein, D.J, and  Probstein, R.F.,  "Water Requirements for an
     Integrated SNG Plant and Mine Operation," in Symposium Proceedings^
     Environmental Aspects of Fuel Conversion Technology II, pp  307-332,
     Report No. EPA-600/2-76-149 (NTIS No. PB 257 182), Environmental
     Protection Agency, Research Triangle  Park,  N.C., June  1976.
                                        29

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                                2.  INTRODUCTION
     Development  of  a  synthetic fuel  industry in  the United States  could be
severely  impaired because  of  local environmental  problems associated with the
large  consumptive use  of water required  for  coal  and  oil shale conversion
processing  and because of  the large quantities  of environmentally unacceptable
solid  wastes  that leave these plants  and for which a  disposal site must be •
found.  Moreover, water for synthetic fuel development in a given locale,
where  coal  can be economically mined,  may be in short  supply, or there may be
strong competition  for the water  among alternative uses including agricultural,
power  production, municipal,  industrial,  and recreational.
     High water  consumption has been  a frequent reason cited for stifling the
development of  a synthetic fuel industry, particularly in the water-short
Western States.   These high water consumption estimates may be both excessive
and misleading.   They  may  be  excessive because  of the  large quantity of water
assumed to  be evaporated for  cooling,  since  cooling water is most often the
prime  determinant of total consumption.   They may be misleading because the
estimates,  with  few exceptions, have  been regional, rather than derived from
local  site-,  process-,  and  design-specific calculations.
     The  overall objective of the work presented  in this paper was to determine:
the feasibility  of  siting  specific conversion plants  at given locations in the
major  U.S.  coal  and  oil shale bearing regions;  and the extent of the environ-
mental impacts that  could  be  expected from local  water-related site, process
and plant design  criteria. Of the 90  plant-site combinations studied, 48 were
in  the  Central and Eastern coal bearing  regions and 42 in the Western coal and
oil shale bearing regions.  The plants were  sited taking into account the
following broad categories of water-related  site  criteria:  water supply and
alternative demands, climate, coal rank  or grade  of oil shale, and mine type.
Plant design  considerations included  the  following broad categories of water-
related process criteria:  low temperature gasifiers, high temperature gasifiers,
coal refining and liquefaction processes, and direct and indirect heated oil
shale retorting.  The  plants  were assumed to be designed so as not  to waste
water.   Effluent  process waters were  assumed to be  reused,  and different
cooling options were selected based on the availability and cost of water.
Estimates  were made of  the total net water consumed, wet  solid  residuals
                                        30

-------
generated, and the cost and energy  required  for water  treatment  for  each
plant-site combination and then generalized  to each  one  of  the major U.S.coal
and oil shale bearing regions.  The environmental  impacts resulting  from  the
consumptive use of water were  evaluated.   Other elements of an overall environ-
mental assessment, such as population  growth and waste disposal,  were not
considered.
     A corollary objective was to generalize from  the  individual site-, process-,
and  design-specific   results  to arrive  at guides  for  the expected extent of
water-related local environmental impacts  in their dependence on process  and
plant design, water supply, climate, and other site  factors.  From the generali-
zations, the following results were obtained:
      (1)  The range of consumptive  water requirements  was calculated and  the
conditions found for narrowing the  range and optimizing  the use  of water.
      (2)  Ranges of residual solid  wastes, their quantity and nature were
estimated, and the conditions  found for  narrowing  the  ranges and minimizing
disposal problems.
      (3)  Localities ware selected  where local water-  related environmental
impacts are large, moderate, or small.
      (4)  Localities were selected  where certain processes  are more  suitable
than others to minimize local  water- related environmental  impacts.
      (5) Site and process criteria  used  in estimating  local environmental
impacts were ranked in order of their  importance.
     Calculations of water consumption and wet-solid residuals were  made  from
block flow process diagrams at each site.  Included  in these calculations  are
estimates of the individual cooling loads  for determining whether wet or  dry
cooling should be used and the quantity  of water consumed by evaporation.
Throughout the study the assumption was  made that  if wastewater was  treated to
a Quality sufficient for return to  the river, it was good enough  for reuse in
the plant.  Non-wasteful consumption of  water following  the best  common engin-
eering practice was followed throughout.   Results  were found for  specific
processes at specific sites and then generalized to  conversion technology and
coal or oil shale bearing region.   Specific  conclusions  for a particular  process
apply only to that process.  However,  general conclusions may be  used more
broadly.
                                        31

-------
     The report has been divided into two volumes.  The first volume is a
summary of the entire study.  The second volume contains 15 appendices which
details all the process, cooling and water treatment calculations.  In addition
the second volume contains water supply and demand data for the Eastern,
Central and Western coal regions and the water transportation cost calculations.
                                       32

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                          3.   PROCESS  AND SITE SELECTIONS
3.1  Introduction
     The overall objective of this study  is  to  determine  the  general environ-
mental impacts that can be expected from  local  water-related  site,,  process
and plant design criteria.  Site considerations include:  water supply and
alternative demands, climate and rank of  coal and  mine  type.   Plant design
considerations include the following broad categories of  water related process
criteria: (i)  low temperature gasifiers,  (ii) high temperature gasifiers, and
 (iii) coal refining and liquefaction processes.  The water requirements and
water uses within the plant, the waters to be treated within  the  plant and the
waste effluents are dependent on the site of the coal and shale oil conversion
complex, as well as on the process itself.  Furthermore,  the  water  control
technology and disposal of the waste solid residues are dependent on the
quality of the supply water, which is also dependent on 'the site.
     Many site and process criteria combinations were studied in  order to
obtain meaningful assessments on a regional and national  level from detailed
local results.  Site and process criteria used  to  define  a plant  location,  process,
product and plant design have already been broadly categorized above.   It is
clear, however, that not every category of site and process criteria,,  with all
of their subcategories, could be used in every  possible combination,  without
arriving at an inordinately large number of configurations.   Moreover,  a great
many of the configurations would be without meaning, since they could not be
found in some of the coal and oil shale regions.   We have therefore  chosen to
associate with each of the criteria the minimum number  of principal  characteristics
associated with that criterion and will then define the physically meaningful
number of site-plant combinations in,terms of those characteristics.   It is
only with such an approach that generalized rules  could be derived  as  to the
feasibility of ^ny given siting and its subsequent environmental  impact resulting
from the consumptive use of  water at that site.
                                       33

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     In Tables 3-1 and 3-2 we have listed the broad categories of site  and
plant criteria and next to each have set out the minimum number of important
characteristics.  We emphasize that this is a minimum number and does not
include all of the details to be discussed in forthcoming sections.  Rather
these items are defined only to find the number of plant-site combinations it
is necessary to examine in the Western, Central and Eastern coal bearing
regions of the United States and in the Western oil shale bearing regions,  in
order to arrive at general results.  The total number of important site character-
istics were obtained by taking the product of each of the principal  site
characteristics.  The number of process-site combinations were obtained by
taking the product of the total number of process characteristics and the
total number of site characteristics.
     For the conversion of coal to either gas, oil or solvent refined coal, we
have defined three process criteria relating to the quality of the foul
process condensate recovered after gasification or liquefaction.  The low
temperature gasifiers, for example, Lurgi  and Synthane  produce a very dirty
process condensate (typical values for bituminous coals: BOD ^ 10,000 mg/1,
phenol ^ 3,000 mg/1 and ammonia '^ 7,000 mg/1).  The high temperature gas-
ifiers, for example, Koppers-Totzek , Winkler and Bigas produce a relatively
clean process condensate  (typical values:  ammonia ^ 4,500 mg/1, BOD and
                                                              4
phenol ^ small).   The intermediate temperature Hygas gasifier  produces a
process condensate of intermediate quality. The process condensate from the
                                                 4
liquefaction sections of the Solvent Refined Coal  process is dirtier than  the
process condensate from the low temperature gasifier sections.  The  Synthoil
foul process condensate from the liquefaction section is comparable  in  contami-
nation to the SRC process (typical values: BOD ^ 30,000 mg/1, phenol ^  5,000
mg/1 and ammonia ^ 8,000 mg/1).  As for site criteria, brackish groundwater
would have to be considered as an important conjunctive supply in the West,
while surface waters are considered primarily in the East and Central States.
Eastern and Central climates have humid climates, while the climates in
the West are arid and semi-arid.  Eastern and Central coals are both underground
and surface mined, while Western coals are primarily surface mined.
                                       34

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                    TABLE 3-1  SITE AND PROCESS CRITERIA AND PRINCIPAL CHARACTERISTICS

                            FOR CENTRAL, EASTERN AND WESTERN COAL BEARING REGIONS
Criteria
Process
Low temperature gasifiers
High temperature gasifiers
Coal refining & liquefaction
Total
Site
Water supply and
alternative demands
Climate
Rank of coal
Mine type
Total
Process-site combinations:
Central and Eastern Regions
Principal
Characteristics Number
As defined ^
As defined ) 3
As defined J
3
Surface water I
Ground water J
Humid- temperate 1
Bituminous- 1
Subbituminous \ 1
-v
Surface \
Underground J —
4
12
Western Region
Principal
Characteristics Number
As defined "1
As defined > 3
As defined J
3
Surface water '}
Brackish ground- r
water ^
Arid \1+ ++
Semi-arid J 1
Lignite 2
Subbituminous- ;
bituminous _.. 1+
Surface 1 1
2 4
18
'rSubbituminous coal is primarily mined in the arid region of New Mexico.
'"Both lignite and subbituminous coals are mined in the  semi-arid regions  of Wyoming,  Montana and North Dakota.

-------
                             TABLE 3-2  SITE AND PROCESS CRITERIA  AND  PRINCIPAL CHARACTERISTICS


                                           FOR WESTERN OIL SHALE BEARING REGIONS
Criteria
Process
Oil shale retorting
Total
Site
Water supply and alternate demands
Climate
Rank of shale
Mining
Total
Process-site combinations:
Principal Characteristics
As defined

Surface Water and
Brackish Groundwater
Semi-arid
High grade
Surface-underground


Number
_2_
2
2
1
1
:L
2
4
ui
en

-------
Twelve plant-site combinations are required to cover the  characteristics
denoted for the Central and Eastern coal bearing regions  and  18 plant-site
combinations are required for the Western region,
     The pyrolysis or destructure distillation of  shale to produce  crude  shale
oil is termed retorting.  Two retorting options have been investigated  exten-
sively;  mining followed by surface retorting and  in_ situ retorting '   in
which the shale oil is released by underground heating and pumping  the  shale
to the surface,  The primary advantage of in situ  retorting is that the
disposal of spent shale is simplified considerably and the water  required for
this purpose is drastically reduced.  However, in  situ processes  are under
development and cannot yet be considered suitable  for commercial  operation.
In this study we will only consider underground mining followed by  surface
retorting.  Oil shale retorts are classified into  two basic types,  those  that
are direct heated, such as the Paraho Direct '  process,  and  those  that are
indirect heated, such as the TOSCO II  and Paraho  Indirect  '  processes.  From
the point of view of water management, the type of retort is  quite  important.
When the retort is direct heated,  most of the water is recovered,  while  with
indirect heated retorts, the water in the combustion products is  generally
lost up the furnace stack and not recovered. Furthermore, for direct heated
retorts, no intermediate medium is used to transfer heat  from the pyrolysis
and the thermal efficiency is high, resulting in reduced  cooling  loads, as
compared to the indirect heated retorts.  Finally, large  amounts  of water are
required for the disposal and revegetation of the  spent shale piles.  Different
procedures with considerably different water needs have been  proposed for the
disposal of the TOSCO and Paraho spent shales.  Thus, two different types of
surface retorting methods are sufficient to characterize  the  process  criteria.
We have only considered shale oil deposits in the West, since most  of the high
grade oil shale is found in areas in Colorado, Utah and Wyoming underlain by
what is called the Green River Formation and where the greatest promise for
commercial production lies. Large amounts of lower grade  shale are  found  in
many areas of the United States, but particularly  in the  same regions as  the
coal basins o  the East and Central states.  However, the economics  of  convert-
ing the lower grade material is considerably less promising and will not  be
                                       37

-------
considered.  About four plant-site combinations will suffice for shale oil
conversion.
     Therefore, a minimum of 34 plant-site combinations should be  studied in
order to arrive at general results.  Another 10 plant-site combinations
should account for any additional unusual site characteristics.
3.2  Process and Plant Selection
     The synthetic fuel technologies examined include the conversion of  coal
to clean gaseous, liquid and solid fuels, and the conversion of oil shale to
clean liquid fuels.  The conversion is basically one of hydrogenation in which
the weight ratio of carbon to hydrogen is higher in the raw material than for
the gaseous or liquid synthetic fuel.  In the conversion, sulfur and nitrogen
are reduced to produce a cleaner fuel; and ash, oxygen, and nitrogen are
reduced to produce a synthetic fuel with a higher heating value.
     We have compared several fuel technologies in this study:
     1.  Coal gasification to convert coal to pipeline or high-Btu gas,  which
has a heating value of about 920 to 1000 Btu/scf and is normally composed of
more than 90 percent methane.  Because of its high heating value, high-Btu gas
is a substitute for natural gas and can be transported economically by pipeline
We have not considered low-Btu gas (termed producer or power gas) which  will
probably have its greatest utility in gas-steam combined power cycle for
steam-electric power generation, nor have we considered medium-Btu gas,  which
may be used as a source of hydrogen for the production of methanol and other
liquid fuels, or as a fuel for the production of high-Btu gas.
     2.  Coal liquefaction to convert coal to low sulfur fuel oil.
     3.  Coal refining to produce a de-ashed, low sulfur solvent refined
(clean) coal, and
     4.  Oil shale retorting to produce synthetic crude.
For each of the technologies we have examined a standard size mine-plant
complex.  The size of the plants have been selected so that the product
heating values are approximately equal, although the products are different.
The products chosen are synthetic fuels;  the production of chemicals from coal
or shale,  e.g., ammonia or methanol via coal gasification, was not considered.
Table 3-3 lists the technologies and the processes chosen to illustrate  them,
together with a summary of the product fuel output and heating value for the
                                       38

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      TABLE  3-3  PRODUCT  FUEL OUTPUT  OF  STANDARD SIZE SYNTHETIC FUEL PLANTS
 Technology and
Conversion Process
Coal Gasification
    Lurgi
    Synthane
    Hygas
    Bigas
Coal Liquefaction
    Synthoil
Coal Refining
     SRC
Oil Shale
    Paraho Direct
    Paraho Indirect
    TOSCO II
    Product
  Pipeline Gas
   Fuel Oil
   Output
250xl06 scf/day
   Product
Heating Value
(1011 Btu/day)
     2.4
50,000 barrels/day     3.1
Solvent Refined  10,000 tons/day
    Coal
                       3.2
Synthetic Crude  50,000 barrels/day     2.9
standard size plants examined.
     Except for the commercially available Lurgi process, the processes that we
have chosen are representative of those that have undergone extensive development
and which are sufficiently described in the available literature so that
detailed process calculations can be made.  The gasification and liquefaction
sections of the processes are characteristic of the three coal conversion
technologies; the three oil shale conversion processes are representative of
the different surface retorting techniques.
     Figure 3-1 (adapted from Refs. 8 and 9) show the different methods of
producing clean synthetic gaseous, liquid and solid fuels.  Synthetic gases
can be produced from coal by indirect hydrogenation in which the gasification
takes place by reacting steam with the coal, or by direct hydrogenation or
hydrogasification, in which hydrogen is contacted with the coal.  Clean liquid
fuels can be produced in a number of different ways.  For example, direct
hydrogenation as for a synthetic gaseous fuel.  Coal can be gasified first and
then the liquid fuel synthesized from the gas. Another process is pyrolysis in
                                       39

-------

COAL —
1 	 	 ~1 (
SHALE J

H70 +
AIR OR

WHEN AIR LOW-BIU
CO,. H2S

_~| GASIFICATION) H2S


..___, '
WHEN 02 Htu'uw-"u SHIFT CONVERSION
CO.^S AND PURIFICATION
HjS
t
. 	 1 MtUIUM-BIU
HYDRO- CO H CH — SHIFT COMVERSION -f
GASIFICATION ' '• ' AND PURIFICATION "S
J
H2. STE
SYNTHE
G>
1 1
-i-j PYRO
\U OR
SIS GAS


H,S
t >,
_ «. PURIFICATION 1 * LOW-Btu


CO+ H,
	 ^] METHANATION |— - HIGH-Blu


_*- METHANATION — *- HIGH Blu
/

METHANOL METHANOL "1
SYNTHESIS MtlHANUL

FISCHER-
SYNTHESIS


T" J t
H2 CHAR H2
COAL-DERIVED LIQUID
SLURRY CATALYTIC
~*~ PREPARATION "* HYDROGENATION


DI-OLUTIOH . FILTRATION AND " 	 \
— DI-OLUTION SOLVENT REMOVAL


1
H ASH
PYRITIC SULFUR
—.1. .» i
DIRECT
DESULFURIZATION
BY PHYSICAL.

H2S
4

TREATING IIYDnOCAnDON ,
1
»,


CLEAN
S GASEOUS
' FUELS
CLEAN
S LIQUID
FUELS
1 CLEAN
S SOLID
[ FUELS
CHEMICAL OR ' 	 "^J
THERMAL
TREATMENT

Figure 3-1   Methods of producing clean synthetic gaseous,
                liquid and solid fuels
                      40

-------
which natural oil is distilled  out of  the  coal or shale.   The last procedure
involves dissolving coal  in  a hyrogen  donor solvent,  removing sulfur,  filtering
out the ash and recovering the  solvent,  cleaning the  resultant heavy synthetic
crude, and upgrading it to the  desired liquid fuels.   Solvent refined coal is
obtained by cooling down  the synthetic crude instead  of hydrotreating it.
Physical, chemical or  thermal treatment to desulfurize the coal also results
in a cleaner solid fuel.
     Table 3-4 summarizes the coal technologies, the  methods of producing
synthetic fuels from coal and shale, the reactor types, and the specific
conversion processes considered in the site studies.   Detailed descriptions
and characteristics of the gasifier systems are found in Refs. 10, 11,  and
12; the Synthoil process  are found in  Refs. 13 and 14; the SRC process  are
found in Refs. 4 and 15;  and the Paraho and TOSCO II  processes are found in
Refs. 5, 6 and 7.  In  addition  process details are given in the Appendices to
this report.
     The selection of  the representative conversion processes was partially
based on the availability of pilot plant data and integrated plant designs.
Table 3-5 briefly summarizes the reference data used in our integrated plant
 designs.   The table also shows the type of coal and oil shale on which the
 reference data is based.  Table  3-6 shows the matrix of coal type and coal
 conversion process combinations used in our site studies and those coal/
process combinations where design data were available  in the literature. All
 other combinations required  our own plant designs.  All plant designs are
 given in Appendices 1  through 6.
 3.3  Site Selection
     Site selection was based on the availability of coal and oil shale, the
 type of coal  (bituminous, anthracite or lignite) or oil shale  (high grade  or
 low grade), the type of mining   (underground or surface) and the availability
 of surface and groundwater,   Only mine-mouth plant complexes  are considered.
     The coal fields of the  conterminous United States and the rank of the
 coal found in these fields  are  shown in Figure 3-2.  Coal rank refers  to the
percentage of carbon and  heat content of the coal.  The coal  of  lowest rank
 is lignite, followed in increasing rank by subbituminous coal, bituminous
 coal and anthracite.   The fraction of  carbon in the coal increases  from
 lignite to anthracite, and  the  moisture fraction decreases.   The  fact  that
                                        41

-------
                    TABLE 3-4  SUMMARY OF CONVERSION PROCESSES  AND REACTOR TYPES USED  IN SITE  STUDIES
         Technology

         Coal Gasification
SO
         Coal Liquefaction


         Coal Refining


         Oil Shale
 Conversion Process

 Indirect Hydrogen-
  ation
 -Partial Oxidation
 -Hydrogasification


 Direct Hydrogenation
 -Hydroliquefaction

Indirect Hydrogenation
-Solvent Extraction

Pyrolysis
Reactor Type

Fixed Bed Gasifier

Fluid Bed Gasifier

Entrained Flow
 Gasifier

Fluid Bed Hydro-
 gasifier

Catalytic Fixed Bed


Dissolver


Direct Retorting

Indirect Retorting
Indirect Retorting
Process

Lurgi

Synthane


Bigas


Hygas

Synthoil


SRC


Paraho Direct

Paraho Indirect
TOSCO II
                                            Product
Pipeline Gas
 Fuel Oil
Solvent Refined
 Coal
Synthetic Crude

-------
       TABLE 3-5  REFERENCE  DATA FOR THE  DESIGN OF INTEGRATED CONVERSION
                 PLANTS  UTILIZING SPECIFIC COALS AND OIL SHALE
Coal Gasification
     Hygas


     Bigas

     Lurgi

     Synthane
Coal Liquefaction
     Synthoil

Coal Refining
     SRC
Oil Shale
     Paraho Direct
     Paraho Indirect
     TOSCO II
Plant
Design
W.Va. Bit,
Wyoming Sub.
No. Dakota Lig.
Montana Sub.
Kentucky Bit.
Bit.
Navajo Sub.
Wyoming Sub .
Pittsburg Bit.



Wyoming Sub.
New Mexico Sub.
Wyoming Sub.
New Mexico Sub.
No. Dakota Lig.





Refs.
16
16,4
4
17
17
18
19
20,4
20



21
4
4
4
4


5
6
7
Pilot Plant
Data
Illinois #6 Bit.
Montana Lig.



Montana Sub.

Illinois #6 Bit.
No. Dakota Lig.
W. Kentucky Bit.
Pittsburgh Bit.
Wyoming Sub.


Pittsburgh Bit.
Illinois Bit.
Kentucky Bit.
No. Dakota Lig.
Wyoming Sub.
Anvil Points
Anvil Points

Refs.
4
4



1

2
2
2
2
2


22,23
22,23
22
24
24
5
27,6
7
                                         43

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       TABLE 3-6  MATRIX OF COAL TYPE/COAL CONVERSION PROCESS COMBINATIONS USED IN SITE STUDIES
                                               Coal Gasification
  Coal          Coal
Liquefaction  Refining

Site Locations
West


East-Central


Coal Type
Lignite
Subbituminous
Bituminous
Lignite
Bituminous
High Temp. Gasifier Low Temp. Gasifier
Hygas Bigas Lurgi Syn thane Synthoil
X X
X* X* X* X*
X X
X XX
X* X* X* X* X

SRC
X*
X*
X
X
X*
*Based on pilot plant data and plant designs
 available in literature.

-------
                                          NORTHERN GREAT
                                          I tLAINS REGION
                                         I   WESTERN
                                            INTERIOR
                                              BASIN
Medium- «nd High- Volatile
   Bituminous Coal
  Subbitumlnoui Coal
                     Anthracite and
                     Ssmlanthraelts   \./
       Lignite
 Low- Voistib
Bitumlnou« Cos'
    Figure  3-2    Coal fields  of  the  conterminous  United  States

-------
The fact that the coal moisture varies considerably with the  type  of coal can
affect the process water requirements in a synthetic fuel plant.   The heating
value increases from lignite to low-volatile bituminous coal.   For a given
synthetic fuel output, the heating value of the coal determines the actual
quantity of coal required. We have not considered anthracite  coal  since it is
not suitable for conversion.
     The demonstrated coal reserve has been tabulated according to region as
                                                     25
shown in Table 3-7, compiled from the data of Averitt   .  This  reserve refers
to identified resources suitable for mining by present methods,  where at
least 50 percent is recoverable and the coal lies less than 1000 feet below
the surface.  Table 3-7 shows the potential methods by which  the coal can be
mined.  In the Northern Great Plains and Rocky Mountains region, where almost
half of the Nation's coal is to be found, more than 40 percent  of  the coal
can be surface mined.  Surface, or strip mining can be done more economically
than underground mining and in most cases with a much higher  percentage of
the coal recovered.

        TABLE 3-7  DEMONSTRATED COAL RESERVE BASE OF THE UNITED STATES
         IN BILLIONS OF TONS BY REGION AND POTENTIAL METHOD OF  MINING
                                                                 Percent of
          Region                   Underground  Surface  Total   Grand Total
     Northern Great Plains
        and Rocky Mountain             113        86      199       46
     Appalachian Basin                  97        16      113       26
     Illinois Basin                     71        18       89       20
     Other                              16        r?       33        8
          Grand Total                  297       137      434      100

     Oil shale can be classified according to its organic content  and yield.
High grade oil shale is shale with an organic content greater than 14 percent
yielding 25 gallons or more of oil per ton of shale and is found in beds at
least 10 feet thick.   Large amounts of lower grade shale are  found in many
areas of the United States, particularly in the same regions  as  the coal
                                       46

-------
basins of the East and Central states.  However, the greatest promise for
commercial production lies in the mining of high grade shale, which is the
only shale considered in this study.  High grade shale is found in areas in
Colorado, Utah and Wyoming underlain by what is called the Green River
Formation  (Figure 3-3)  .  The identified high grade shales with yields
between 25 and 65 gallons per ton have an oil equivalence of about 570 to 620
billion barrels.  About 80 percent of the high grade material is located in
                                    27
Colorado in the Piceance Creek Basin
     The U.S. Bureau of Mines lists the quantity of coal available by county
                                                                            28,29
and state, in millions of short tons, in underground and strippable reserves
The amount of coal needed for coal conversion at any plant site will vary with
the capacity and type of plant and the nature of the coal.  For a given
conversion efficiency and a fixed plant size (determined by the heating value
of the product) the rate of coal mined is set by its heating value.
     For the three major coal ranks the following average heating values are
used:  bituminous, 13,000 Btu/lb; subbituminous, 9,800 Btu/lb; and lignite,
6,800 Btu/lb.   .  Table 3-8 shows the quantities of different rank coals that
must be mined daily for a Synthane plant producing 250 million standard cubic
feet per day of pipeline gas.  Also shown are the total recoverable reserves
required and the total coal reserves required for both underground and surface
mining.  The recoverable reserve is the amount of coal actually mined or
recovered  as distinguished from the amount of coal present in the ground, or
coal reserve.  The total recoverable coal reserve is about 50 percent of the
total coal reserve for underground mining and about 80 percent for surface
mining   '  .  The total coal reserves required to produce clean fuel oil and
solvent refined coal by the specific processes and in the standard size plants
previously noted  do not exceed approximately 110 percent of those listed in
Table 3-8.
     Site  selection in the Central and Eastern regions of the United States
was limited to those states having the largest coal reserves.  These states
are Alabama, Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia.
Table 3-9  lists the counties by state in which the criteria shown in Table 3-8
                                       47

-------
     OF OIL SHALE DEPOSITS
 AREA OF 25 GAL/TON OR RICHER
i OIL SHALE 10 FT OR MORE THICK
Grand Ji^ction  GRAND MESA
               0     25    50
  Figure 3-3    Oil shale areas of  the Green River

     Formation  in Colorado,  Utah  and Wyoming
                          48

-------
        TABLE  3-8  COAL MINING RATES AND RESERVES REQUIRED FOR A SYNTHANE PLANT

          PRODUCING 250 MILLION STANDARD CUBIC FEET  PER  DAY  OF PIPELINE  GAS
Coal Rank  (Heating Value)

Bituminous  (13,000 Btu/lb)

Subbituminous  (9,800 Btu/lb)

Lignite  (6,800 Btu/lb)
    Daily
Production Rate
  (tons/day)

    15,800

    20,900

    30,100
Total Recoverable
Reserve Required*

   (10  tons)

      154
      204
      294
                                                                       Total  Coal  Reserve Required**
                                                                                   6
         (10
Underground
  Mining

   308
  (300)

   408
  (400)

   588
  (600)
                                                                                     tons)
Surface
Mining

  193
 (200)
  255
 (250)
  368
 (350)
 *Based on 325 day/year production and a  30 year mine  life.
**Numbers in parenthesis are rounded off  and  used  as criteria  for  the  reserve  requirements.

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               TABLE 3-9    COUNTIES  OF  PRINCIPAL  COAL RESERVES  IN  CENTRAL AND EASTERN  STATES
                                                                                                              MINING
Ln
O
(million shor'
Alabama Jefferson
Walker
Marengo
Illinois Bond
Bureau
Christian
Clinton
Crawford
Douglas
Edgar
Fayette
Franklin
Gallatin
Hamilton
Je f f erson
LaSalle
Lawrence
Livington
Logan
Macon
Macoupin
Madison
Marion
Marshall
McLean
Menard
Montgomery
Perry
Putriajn
St. Clair
Saline
Sangajnon
Shelby
Vermilion
Washington
White
Williamson
U
U
s
u
u
u
u
u
u
u
u
u
u
u
u
u
u
u
I
t
u
u
u
I)
u
u
u
u
u
L
u
u
u
u
u
u
u
B
B
L
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
758
630
500
1831
1029
3347
1322
442
412
1750
1173
3038
1761
2440
1800
1083
693
586
613
439
3421
1366
421
358
420
1460
3906
1201
586
951
2553
3540
712
1544
1555
992
1573
    U - underground mining; S - surface mining.

    8 - bituminous; L •= lignite.

(Illinois,
continued)













Indiana









Kentucky





















Bureau
Fulton
Greene
Grundy
Henry
Jackson
Knox
Madison
Peoria
Perry
Randolph
St. Clair
Saline
Vermilion
Williamson
Gibson
Knox
Posey
Sullivan
Vanderburgh
Vermilion
Vigo
Warrick
Sullivan
Harrick
Breathitt
Fletcher
Floyd
Harlan
Henderson
Hopkins
Knott
Leslie
McLean
Muhlenberg
Perry
Pike
Union
Webster
Harlan
Henderson
Hopkins
Muhlenberg
Ohio
Perry
Pike

S
S
S
S
S
S
s
S
s
s
s
s
s
s
s
u
u
u
u
u
u
u
u
s
s
u
u
u
u
u
u
u
u
u
u
u
u
u
u
s
s
s
s
s
s
s

B
B
B
B
E
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
I,
L
B
B
B
B
£
B
B
B
B
B
B
B
B
B
B
B
B
B
B
(million shor
221
1810
423
381
381
299
605
509
355
973
417
1162
431
353
529
1301
1453
720
1922
451
497
1212
532
316
313
410
730
952
1406
1503
1605
1248
619
723
896
560
2170
1926
1436
363
504
769
1091
593
454
504
                                                                                                                                          (continued)

-------
TABLE 3-9   (continued)





   STATE               COUNTY








Ohio
Pennsylvania

Athens
Belinont
Carroll
Columbians
Gallia
Guernsey
Harrison
Jefferson
Lawrence
Hahonlng
Meigs
Monroe
Morgan
Huskingum
Noble
Perry
Stark
Tuscarawas
Vinton
Je f f erson
Noble
Allegheny
Arrrxs trong
Beaver
Butler
Cambria
Clarion
Clearf ield
Faye tte
Greene
Indiana
Je f f erson
Somerset
Washington
Westmoreland

U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
s
s
U
U
U
U
U
U
U
U
U
U
U
U
U
U

B
B
E
E
B
B
E
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
(million Bhon
1326
3927
758
748
340
1184
1523
1356
477
308
396
468
453
720
570
644
376
841
301
338
343
881
1092
435
863
1454
640
1102
1023
6515
1716
456
1240
3604
747
West Virginia
Barbour
Boone
B rax ton
Clay
Faye tte
Grant
Harrison
Kanawha
U
U
U
U
U
U
U
U
B
B
B
B
B
B
B
B
948
1868
467
695
796
313
380
1120
RESERVES

(West Virginia,
continued) Lewis
Lincoln
Logan
Marion
Marshall
McDovell
Mingo
Monongolia
Nicholas
Ohio
Preston
Randolph
Rayleigh
Taylor
Upshur
Wayne
Webster
Wetzel
Wyoming
Boone
Fayette
Kanawha
Logan
McDowell
Mingo
Rayleigh


U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
U
s
s
s
s
s
s
s


B
B
B
B
B
B
B
B
E
E
B
£
S
B
B
B
B
B
B
B
B
B
B
B
B
B
(million shor

730
360
3760
2599
3043
912
1887
3008
1433
379
837
757
1656
388
876
403
1098
846
1642
579
275
563
557
324
444
339

-------
(in parenthesis)  have been met, together with the total reserves found  in  the
each county28.  Not all of the coal reserve is available for mining.  For
example, the amount of coal found under towns, roads, railroads, etc. must be
subtracted from the total reserve.  However, the total coal reserve  is  still
a good measure of the coal available for mining.  Furthermore, we have  assumed
that if a plant is located in one of the counties listed in Table 3-9,  the
mine will have a large enough coal reserve to meet the criteria  shown in
Table 3-8.  This may not be the case and we have not subdivided  the  county to
determine where the required coal reserve may be found.
     From the list of total reserves, 26 sites were selected in  the  Central
and Eastern states  (Table 3-10 and Figure 3-4).  In Alabama sufficient  bitu-
minous  coal is found in the central portion of the state and sufficient
lignite is found in one county in the south central region.  Most of the
surface mining sites are found in Illinois.  In Indiana there  are a  few
counties in the southwest with sufficient coal beds.  Kentucky has concentra-
tions of coal reserves in the eastern and western parts of the state, while
Ohio's  coal reserves are located principally in two counties in  the  south-
eastern region. Bituminous coal is found in Pennsylvania in the  western part
of  the  state, while the largest coal reserves in West Virginia are located in
four counties in the southwest.  The sites were distributed geographically in
each of the states.  Table 3-10 also lists the water sources for each of the
sites.  The selection is based upon a sufficient and reliable water  supply
 (Section 4.1 and Appendix 13) and available water quality data  (Section 3.6).
     In a similar manner, we have listed in Table 3-11 the counties  by  state
in  the Western states that meet the criteria for total reserves.  Site
selection was limited to the states of Montana, New Mexico, North Dakota and
Wyoming.  A total of 28 coal conversion sites were selected in the Western
states.  These sites are listed in Table 3-12 and shown on Figure 3-5.
     In the Western states the areal extent of a county is much  larger  than
those found in the Central and Eastern states.  As a result the  plant sites
were identified with either a particular existing mine, a town,  or a quadrangle
on a U.S.  Geological Survey topographical map.  Table 3-12 also  lists the
water source for each of the sites.   As noted above the water sources were
selected on the  basis of a sufficient and reliable water supply  (Section 4.2
                                       52

-------
     TABLE 3-10  COAL CONVERSION  PLANT SITES  FOR CENTRAL AND EASTERN STATES
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
                     COUNTY

                   Jefferson
                   Marengo
Bureau
Shelby
St.  Clair
White
Bureau
Fulton
St.  Clair
Saline

Gibson
Vigo
Sullivan
Warrick

Floyd
Harlan
Muhlenberg
Pike

Gallia
Tuscarawas
Tuscarawas
Jefferson

Somerset

Armstrong

Fayette
Kanawha
Monongalia
Preston

Mingo
                      MINING
COAL
                                                                  WATER SOURCE
u
s

u
u
u
u
s
s
s
s
u
u
s
s
u
u
s
s
u
u
u
s
u

u
u
u
u
u

s
B
L

B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
(MV, LV)
B
B
B (HV)
B (HV)
B
(HV, MV, LV)
B (HV)
Alabama River
Tombigbee River and
Well Water
Well Water
Ohio River
Ohio River
Ohio River
Illinois River
Well Water
Ohio River
Ohio River
White River
White River
Ohio River
Ohio River
Ohio River
Ohio River
Green River
Ohio River
Ohio River
Muskingum River
Well Water
Ohio River
Allegheny River

Allegheny River
Kanawha River
Kanawha River
Allegheny River
Kanawha River

Kanawha River
1.   U = Underground mining; S = Surface mining
2.   B = Bituminous; HV = High  volatile,  MV  =  Medium volatile;
    LV = Low volatile.
                                       53

-------
       TABLE
              3-11   COUNTIES OF PRINCIPAL COAL RESERVES IN WESTERN STATES
   STATE
Montana
 New Mexico
 North Dakota
 Wyoming
                    COUNTY
Big Horn
Custer
Custer
Dawson
MeCone
MeCone
Powder River
Powder River
Roosevelt
Rosebud
Sheridan
Treasure
Wibaux

CoIfax
McKinley
San Juan
San Juan

Billings
Bowman
 Dunn
Hettinger
McClean
McKenzie
Mercer
Morton
 Oliver
 Slope
 Stark
Ward
Williams

 Campbell
 Carbon
Converse
Johnson
Lincoln
Sweetwater
                                       MINING
                                  COAL
S
S
S
S
S
S
S
S
S
S
S
S
S
U
S
S
U
S
S
S
S
S
S
S
S
S
S
S
S
S
S
S
S
S
S
S
S
S
L
L
L
S
S
L
L
S
L
s:
L
B
s
s
s
L
L
L
L
L
L
L
L
L
L
L
L
L
S
S
S
S
S
S
    RESERVES
(million short tons)

       10621
        1150
        1168
        1101
         464
         707
       15217
        1252
         431
        7313
         454
         327
        1000
        1381
         250
        2008
         442

        1078
         785
        2000
         980
        1009
         825
        1986
         342
         629
        2326
        1275
         501
        1130

        19591
         464
         565
        1013
        1000
        1115
 1.   U = Underground mining; S = Surface mining
 2.   B = Bituminous; L = Lignite;  S  = Subbituminous
                                         54

-------
                                                 SITE LOCATIONS
                                                  H PRIMARY SITES
                                                  D SECONDARY SfTES
      ILLINOIS  COALREGION

Figure 3-4  Coal conversion site locations in
      Eastern and Central states.
                       55

-------
                                                   SITE  LOCATIONS
                                              QCLEAR1ELD

                                             CAMBRIA
                                       VI    a
                                          ARMSTR
                                                       PRIMARY SITES
                                                     D SECONDARY SITES
• MARENGO
            APRXLACHIAN  COAL REGION
              Figure 3-4   (concluded)
                       56

-------
                      TABLE  3-12  COAL CONVERSION PLANT  SITES  FOR WESTERN STATES
   State
Coal Conversion
   County
      Mine, Seam or Coal Region
            (location)	
        Coal o;
Mining   Shale''
                                                                            Water Source
Montana
New Mexico
North Dakota
Big Horn
Custer
Dawson

Powder River
Powder R. -Custer
Powder R.-Rosebud
Rosebud
Sheridan

McKinley
San Juan
San Juan

Bowman
Hettinger
McLean
Mercer
Oliver
Slope
Stark
Williams
Decker-Dietz (Quad)*               S
Foster Creek (S.W.Custer)          S
U.S. Steel Chupp Mine (Intake
  N.W. Quad)                       S
East Moorhead (Moorhead)           S
Pumpkin Creek (Elk Ridge Quad)     S
Otter Creek (Otter)                S
Colstrip (Colstrip)                S
Coalridge (Coalridge)              S

Gallup (Gallup)                     S
El Paso (BistiTrading Post Quad)   S
Wesco (Newcombe Quad)              S

Scranton (Quad)                     S
Bentley (Quad)                      S
Underwood (Quad)                   S
Knife River (Beulah-Zap)           S
Center (Center)                     S
Slope (Amidon)                      S
Dickinson (Dickinson)              S
Williston (Quad)                   S
           S     Well Water
           S     Tongue River

           L     Yellowstone River
           L     Powder River
           L     Tongue River
           L     Underground water
           S     Yellowstone River
           L     Missouri River

           S     Brackish groundwater
           S     San Juan River
           S     San Juan River

           L     Grand River
           L     Knife River
           L     Lake Sakakawea
           L     Knife River
           L     Knife River
           L     Yellowstone River
           L     Lake Sakakawea
           L     Missouri River
*Quad = U.S. Geological Survey Quadrangle  on  topographical  map.
1 - U = Underground mining;  S =  surface mining.
2 - B = Bituminous coal;  L = lignite  coal;  SB =  subbituminous  coal,  HG = high grade shale.

-------
        TABLE  3-12  (concluded)
           State
        Wyoming
   County

Campbell
Campbell
Campbell
Carbon
Converse
Johnson
Lincoln
Sweetwater
Sweetwater
   Mine,  Seam or Coal Region
   	(location)	

Belle Ayre Mine (Caballa)
Gillette-Wyodak  (Gillette)
Spotted Horse Strip(Spotted Horse)
Hanna (Hanna)
Antelope Creek Mine  (Verse)
Lake-de-Smet (Quad)
Kemmerer (Quad)
Jim Bridger  (Superior Quad)
Rainbow #8 (Rock Springs Quad)
Mining
S
S
0 S
S
S
S
S
S
u
Coal or
Shale?
S
S
S
S
S
S
B
S
B
           Water Source

      Crazy Woman Creek
      Crazy Woman Creek
      Powder River
      Medicine Bow Reservoir
      Brackish Groundwater
      Tongue River
      Hams Fork
      Green River
      Green River
        Shale Oil Conversion
Ul
CO
        Colorado
Garfield
Parachute Creek (Forked Gulch Qd)  U
HG
Colorado River

-------
                        OTTER CREEK J PUMPKIN CREEK
                      BANNER-,,/     •«•"-*••*

                 0  / HEALY <,y/  /     r>y7/;v        i
                        HANNAH COAL FIELD

                  •JIM 8RiDGER|
        I      I          1
        j 1     / ©TRACT W-a/W-b


        /	^	*
                                     COLORADO
                               NEW  MEXICO
  	^-^              .     '   ^//^^

UPPER  COLORADO\j«^co^


   RIVER  BASIN
                                                SITE  LOCATIONS


                                                   PRIMARY SITES


                                                   SECONDARY SITES
Figure 3-5  Coal and oil shale conversion  site locations



                in Western states.
                      58a

-------
and Appendix 14) and/or available water quality data  (Section 3.6).


     Most of the coal found in the Northern Great Plains, which includes the


states of Wyoming, North Dakota, Montana, South Dakota and Nebraska, is


either lignite or subbituminous.  Nine sites were chosen in Wyoming where


most of the coal is subbituminous.  Subbituminous coal is found in southeastern


Montana andlignite is found in Eastern Montana.  Eight sites were selected in


Montana.  All eight sites in North Dakota have lignite and all three sites in


New Mexico have subbituminous coal.


     The location of some active strip mines were found on a U.S. Geological


Survey map of the stripping coal deposits of the Northern Great Plains


Most of these mines are located in the areas of the largest coal reserves.


For example, in Campbell County, Wyoming, seven strip mines are shown, all of


which are located in the coal deposits running from Spotted Horse in the


northwestern part of the county down through the Gillette deposit to the


southern tip.  These deposits have 19,591 million short tons of subbituminous


coal of which 17,000 million short tons are found in strippable reserves.  In


New Mexico two of the sites selected were those proposed for coal gasification.


     Depending on the shale grade and the particular process, approximately


75,000 to 100,000 tons of high grade shale must be mined daily from an under-


ground shale mine integrated with a shale oil plant to produce 60,000 to


75,000 barrels/day of shale oil.  This is the range of shale oil needed to


produce 50,000 barrels/day of synthetic crude in a self-sufficient integrated


plant.  For one plant this means a total recoverable reserve of from 600 x


10  to 730 x 10  barrels of shale oil is needed, assuming 325 days/year


production and a 30 year mine life.  About 30 percent of the shale remains


underground with conventional room-and-piliar mining techniques  , so that a


total reserve of from 860 x 10  to 1,040 x 10  barrels of shale oil is required
for a plant producing 50,000 barrels/day of synthetic  crude.  This may be


                                             x ]

                                             26
                                                 9            9
compared to identified reserves of about 370 x 10  to 620 x 10  barrels from
high grade shale in the Green River Formation


     One oil shale site has been selected in Colorado  in Garfield County near


the Colorado River (Table 3-12).  This is near Anvils  Point in the Piceance


Creek Basin where a number of Bureau of Mines shale oil test facilities are


located.
                                       59

-------
3.4  Plant-Site Combinations
     Tables 3-13 and 3-14 list the plant-site combinations for the Eastern
and Central states and the Western states, respectively.  Table 3-15 lists
the plant-site combinations by conversion process.  In the East and Central
states, 48 plant-site combinations for coal conversion were chosen; in the
West 39 plant-site combinations for coal conversion and 3 plant-site combina-  -
tions for shale oil conversion were chosen.
     Tables 3-16 and 3-17 show a breakdown by the major process and site
characteristics of the process-site combinations selected for the study.  The
tables also show a comparison of the selected combinations with the minimum
number of process-site combinations given in Tables 3-1 and 3-2.  Two combina-
tions involving groundwater were not considered due to an oversight:  one in
the Eastern states for a high temperature gasifier using surface mined
bituminous coal; and one in the Western states for a high temperature gasifier
using surface mined lignite coal.  In a recently completed study   , two
combinations involving surface water in the Western States were considered:  a
low temperature gasifier using surface mined lignite coal, and liquefaction-
coal refining using, surface mined subbituminous coal.  The results of the study
will be included in the present study.  For oil shale conversion the groundwater
combinations were eliminated in favor of another indirect retorting process.
3.5  Coal Analyses
     Both proximate and ultimate coal analyses for each of the sites are
shown in Table 3-18 and 3-19; the proximate analysis are given in the top
block, while the ultimate analysis is given in the bottom block.  The analyses are
typical of those found in the vicinity of each of the sites.  They were obtained
from Refs. 30 and 34 and from data published by the U.S. Geological Survey,
U.S. Bureau of Mines, and various state geological surveys.
     The heating value of the coal determines the actual quantity of coal
required and the quantity of ash to be disposed of while the moisture can
affect the process water requirements.  The carbon associated with the volatile
content of the coal is highly reactive at temperatures of about 1400°F to
2000°F while the fixed carbon is less reactive and requires temperatures of
about 2000°F for conversion.  Sulfur in coal is found principally in the form
of either pyritic or organic sulfur and must be removed.  In the Western low
                                      60

-------
             TABLE  3-13   PLANT-SITE COMBINATIONS FOR EASTERN AND CENTRAL  STATES


State
Alabama

Illinois







Indiana



Kentucky



Olio


Pennsylvania

West Virginia






County
Jefferson
Marengo
Bureau
Shelby
St. Clair
White
Bureau
Fulton
St. Clair
Saline
Gibson
Vigo
Sullivan
Warrick
Floyd
Harlan
Kohlenberg
Pike
Callia
Tuscarawas
Jefferson
Armstrong
Somerset
Fayette
Kanawha
Monongalia
Preston
Mingo


Surface Ground
Alabama K.
Tombigbee R. X
X
Ohio R.
Ohio R.
Ohio R.
Illinois R.
X
Ohio R.
Ohio R.
White R.
White R.
Ohio K.
Ohio R.
Ohio R.
Ohio R.
Green R.
Ohio R.
Ohio R.
Muskingum R. X
Ohio R.
Allegheny R.
Allegheny R.
Kanawha R.
Kanawha R.
Allegheny R.
Kanawha R.
Kanawha R.

» b
Mining Coal
U B
S L
U B
U B
U B
U B
S B
S B
S B
S B
1 B
U B
S B
S B
U B
U B
S B
S B
U B
U B
S B
U B
U B
U B
U B
U B
U - B
S B
Coal Gasification
High Temp.Gasif iar
Kygas Bigas
X
X
X
X


X



X
>

X





X
X
X

X

X

X
Low Temp.Gasif ier
Lurgi Synthane
X
X
X

X


X
X

X

X

X

X

X

X
X


X

X

Coal Liquefaction
and Coal Refining
Synthoil SRC
X
X
X


X

X

X
X


X

X

X

X
X

X




X

Plant-Sita Combinations
Ho. Total State
3
6 9
3
1
1
1
1
2
1
1 11
3
1
1
2 7
1
1
1
1 4
1
4
3 8
2
1 3
1
1
1
1
2 6
a U = Underground; S a Surface.
t B « Bituminousj  L = Lignite
                                                                                              TOTAL
                                                                                                      48

-------
                       TABLE  3-14   COAL AND OIL SHALE  CONVERSION PLANT-SITE COMBINATIONS FOR WESTERN  STATES
en

State
Montana






New
Mexico

North
DaXota






Wyoming









Mine
Decker-Dietz
U.S. Steel Chupp Mine
East Moorhead
Pumpkin Creek
Otter Creek
Colstrip
Coalridge
Gallup
El Paso
We SCO
Scran ton
Bentley
Underwood
Knife River
Center
Slope
Dickinson
Williston
Belle Ayr
Gillette-Wyodak
Spotted Horse Strip
Hanna
Antelope Creek Mine
LaXe-de-Smet
Ke irenerer
Jim Bridger
Rainbow 18

Water Source
Surface Ground
X
Yellowstone R.
Powder R.
Tongue R.
X
Yellowstone R.
Missouri River
X
San Juan R.
San Juan R.
Grand R.
Knife R.
L. SakaXawea
Knife R.
Knife R.
Yellowstone R.
L. SaXakawea
Missouri R.
Crazy Woman Cr.
Crazy Woman Cr.
Powder R.
Medicine Bow
Beaver Cr. x
Tongue R.
Hams Fork
Green R.
Green R.

a b
Mining Coal
S S
S S
S L
S L
S L
S L
S S
E L
S S
S S
S S
S L,
S L
S L
S L
S L
S L
S L
S L
S S
S S
S S
S S
S S
S S
S B
S S
U B
Coal Gasification
High Temp.Gasifier Low Temp.Gasif ier
Hygai Bigas Lurgi Synthane
X X
X
X
X


X X

X X
X X
X
X


X
X
X

X
X
X
X
X
X X

X X


Coal Liquefaction
and Coal Refining
Eynthoil SRC



X
X
X
X
X



X
X



X


X


X
X

X
X

Plant-Site Combinations
No. Total State
2
1
1
1
1
1
3
1 11
3
2
1 6
1
1
1
1
1
1
1
1 8
1
2
1
1
3
1
2
2
1 14
                                                                                                                         TOTAL
State


Mine


Water Source
Surface Ground
Colorado R.

a c
Mining Shale
U HG

Direct Retort
Paraho Direct
X

Indirect Retort
Paraho Indirect TOSCO II
X X




Plant-Site Combinations
No. Total State
3 3

               a  U - Undergroundj S - Surface
               b  B - Bituminous; L - Lignite; S - Subbituminous
               c  HG - High grade shale

-------
                          TABLE  3-15     PLANT-SITE  COMBINATIONS  LISTED BY  CONVERSION PROCESS

Raw-water Source
Alabama R. at SelAa, Alabama
Tombigbee R. at Jackson, Ala.
Well-water, Marengo, Alabama
White R. at Hazleton, Indiana
Ohio R. at Cannelton Dam, Ky.
Muskingura R. at McConnelsville, O.
Wall-water from alluvial ground
Ohio R. at Cannelton Dam, Ky.
Allegheny R. at Oakmont, Pa.
Kanawha R. at Kanawha Falls. W.Va.
Allegheny R. at Oakmont, Pa.
Kanawha R. at Kanawha Falls, W.Va.
Cra2y Woman Creek nr. Arvada, Wy.
Brackish Water at Beaver Creek
near Newcastle, Hy.
Crazy Woman Creek nr. Arvada, Wy.
Medicine Bow R. above Seainoe
Reservoir, Wy.
Well-water nr. Decker, Montana
Powder R. at Arvada, Wyoming
Yellowstone R. , Montana
San Juan R. , New Mexico
Brackish Groundwater, New Hex.
Illinois R. at Marseilles, 111.
Well-water from alluvial ground
at Bureau, 111.
Ohio R. at Grand Chain, 111.
White R. at Hazleton, Indiana
Coal
Rank
B
I
L
B
B
B
B
B
B
B
B
B
S

S
S

S
S
L
S
S
S
B

B
B
E
•\
Mine
U
S
S
U
S
U

U
S
U
U
U
S
S

S
S

S
S
S
S
S
S
S

U
D
U
Process:  Hygas

East: Jefferson, Alabama
      Marengo,  Alabama
      Marengo,  Alabama
      Gibson,  Indiana
      Warrick,  Indiana
      Tuscarawas, Ohio
      Tuscarawas, Ohio

      Jefferson, Ohio
      Armstrong, Pa.
      Fayette,  w. Virginia
      Monongalia, W. V&.
      Mingo, w. Virginia

West: Gillette, Wyoming
      Antalope  Cr. Mine, Wy.

      Belle Ayr Mine, Hy.
      Hanna Coal Field, Wy.

      Decker,  Montana
      E.Moorhead Coal
        Field,  Montana
      Colstrip, Montana
      El Paso,  New Mexico
      Gallup,  New Mexico

process;  Bigas

East: Bureau,  Illinois
      Bureau,  Illinois

      Shelby,  Illinois
      Vigo, Indiana
1. B = Bituminous coal,  L » lignite  coal,  S  »  aubbitustinous coal,
   HG =• high grade shale.
2. S » Surface, U «* Underground.
       Site

West: Keomerer, Wyoming
      Slope, N. Dakota
      Center, N.  Dakota
      Scranton, N.  Dakota
      U.S.  Steel,  Chupp
       Mine, Montana

Process:   Lurgi

Easti Marengo, Alabama
      Marengo, Alabama
      Bureau, Illinois

      St.  Clair,  Illinois
      St.  Clalr,  Illinois
      Fulton, Illinois
      Muhlenberg,  Kentucky

West: Jim Bridger Mine, Hy.
      Kemnerer, Wyoming
      Knife River,  N.Dakota
      Williston,  N.  Dakota
      Decker, Montana
      Foster Creek,  Montana
      El  Paso, New Mexico
      Heseo, New Mexico
      Gallup, Mew Mexico

Processi   Synthane

Easti Jefferson,  Alabama
      Gibson, Indiana
      Sullivan, Indiana
      Floyd, Kentucky
      Gallie, Ohio
      Jefferson,  Ohio
      Armstrong,  Pa.
      Kanawha, West Virginia
      Praston, West Virginia

Hesti Antelope Cr.  Hina, Hy.

      Spotted Horse, Wyoming
      Coletrip, Montana
        Raw-water Source

Hams Fork near Granger, Wy.
Yellowstone R. at Terry, Mont.
Knife River at Hazen,  N. Dakota
Grand River at Shadehill, S.  D.

Yellowstone River,  Montana
Tombigbee R.  at Jackson,  Alabama
Hell-water, Marengo,  Alabama
Well-water from alluvial  ground
 at Bureau, Illinois
Ohio R. at Grand Chain,  Illinois
Ohio R. at Grand Chain,  Illinois
Groundwater nr. Fulton,  Illinois
Green R.  at Beech Grove,  Ky.

Green k.  below Green  R. ,  Wyoming
Hams Fork, near Granger,  Wyoming
Knife R.  at Hazen,  N.  Dakota
Missouri  R. nr. Hilliston,  N.  D.
Well-water nr. Decker, Montana
Tongue R., Montana
San Juan  R.,  New Mexico
San Juan  R.,  New Mexico
Brackish  groundwater.  New Mexico
Alabaaa R.  at Selma,  Alabama
White R.  at Hazleton,  Ind.
White R.  at Hazleton,  Ind.
Ohio R. at Cannelton  Dam, Ky.
Ohio R. at Cannelton  Dam, Ky.
Ohio R. at Cannelton  Dam, Ky.
Allegheny R.  at Oakmont, Pa.
Xanawha R.  at Kanawha Falls, W.Va.
Kanauha R.  at Kanawha Falls, W.Va.

Blackish water at Beaver Creak
 near Newcastle, Hy.
Powder River at Arvada, Hy.
Yellowstone River, Montana
Coal
Rank
B
L
L
L
L
L
L
B
B
B
B
B
S
B
L
L
S
S
S
S
S
B
B
B
B
B
B
B
B
B
S
S
S
Mine2
S
S
S
S
S
S
S
U
S
U
S
S
S
S
S
S
S
S
S
S
S
U
U
S
U
U
S
U
U
U
S
S
S

-------
TABLE 3-1S  (continued)



Site

Raw- water Source
Coal
Rank

Mine
Process : Synthoil
East:









West i



Jefferson , Alabama
Gibson , Indiana
Warrick, Indiana
Marian, Kentucky
Pike , Kentucky
Tu scar a was , Ohio
Tu scar a was , Ohio
Je f far son, Ohio
Somerset, Pa.
Mingo, W. Virginia
Lake-de-Smet, Wyoming

Jim Bridger Mine, Wy.
Gallup, New Mexico
Alabama R. at Selma, Alabama
White R. at Hazleton, Indiana
Ohio R. at Cannelton Dam, Ky.
Ohio R. at Cannelton Dam, Ky.
Ohio R. at Cannelton Dajn, Ky.
Muskingum R. at McConnelsville , 0.
Well-water from alluvial ground
Ohio R. at Cannelton Dan/ Ky.
Allegheny R. at Oakmont, Pa.
Kanawha R. at Kanawha Falls, W.Va.
Tongue R. at Goose Creek below
Sheridan, Hy.
Green R. below Green River , Wy .
Brackish Groundwater, New Mexico
B
B
B
B
B
B
g
B
B
B

S
S
S
U
U
S
U
S
U
M
S
U
S

S
S
S
Process: SRC
East:






West:










Marengo, Alabama
Marengo, Alabama
Bureau, Illinois

White, Illinois
Fulton, Illinois
Saline, Illinois
Gillette , Wyoming
Antelope Cr. Mine, Wy.

Rainbox , Wyoming
Dickinson , N. Dakota
Bentley, N. Dakota
Underwood, N. Dakota
Otter Creek, Montana
Pumpkin Creek , Montana
Coalridge , Montana
Colstrip, Montana
Tomb ig bee R. at Jackson, Alabama
Well-water, Marengo, Alabama
Well-water from alluvial ground
at Bureau, Illinois
Ohio R. at Grand Chain, Illinois
Groundwater nr. Fulton , Illinois
Ohio R. at Grand Chain, Illinois
Crazy Woman Creek nr. Arvada, Wy.
Brackish water at Beaver Creek
near Newcastle, Wy.
Green R. below Grean River, Wy.
Lake Sakakawea , N. Dakota
Knife R. at Hazen, N. Dakota
Lake Sakakawea, N. Dakota

Tongue R. , Montana
Missouri R. at Culbertson, Mont.
Yellowstone R. , Montana
L
L

B
B
B
B
S

S
B
L
L
I,
L
L
L
S
S
S

U
U
S
S
S

S
0
5
S
S
S
S
S
S
                                                                                                                                        Raw-water Source
                                                                                                         Site

                                                                                                  Oil Shale Conversion

                                                                                                  Processi  Paraho Direct

                                                                                                  West: Parachute Creek, Colorado     Colorado  R.  nr.  Glenvood
                                                                                                                                       Springs,  Colorado

                                                                                                  Proces-St  paraho Indirect

                                                                                                  West: Parachute Creek, Colorado     Colorado  R.  nr.  Glenwood
                                                                                                                                       Springs,  Colorado

                                                                                                  Process:  TOSCO II

                                                                                                  West: Parachute Creek, Colorado     Colorado R.  nr.  Glenwood
                                                                                                                                       Springs,  Colorado
                                                                                                                                                                Shale1   Mine

-------
             TABLE 3-16 BREAKDOWN OF PROCESS-SITE  COMBINATIONS FOR EASTERN AND CENTRAL STATES





                                           High  Temperature     Low Temperature     Liquefaction and

      Site/Process Criteria                    Gasifiers             Gasifiers         Coal Refining



Surface Water  (Humid-temperature climate)



     Underground mining-bituminous coal          8  (1) *                 8 (1)                6 (1)



     Surface mining-bituminous coal              4  (1)                  4 (1)                5 (1)



     Surface mining-lignite coal                 1  (0)                  1 (0)                1 (0)



               TOTAL                           13  (2)                 13 (2)               12 (2)



Groundwater  (Humid-temperature climate)
    • ~ •  '' " '~~ ~ "~                 '        .                  »


     Underground mining-bituminous coal          2  (1)                  1 (1)                2 (I)



     Surface mining-bituminous coal              0  (1)                  1 (1)                1 (1)



     Surface mining-lignite coal                 1  (0)                  1 (0)                1 (0)



               TOTAL                             3  (2)                  3 (2)                4 (2)




Process-site Combinations - TOTAL              16  (4)                 16 (4)               16 (4)
*Numbers in parenthesis are the minimum number of

 process-site combinations given in Table 3-1.

-------
             TABLE 3-17 BREAKDOWN OF PROCESS-SITE COMBINATIONS FOR WESTERN STATES
     Site/Coal Conversion
       Process Criteria
High Temperature     Low Temperature     Liquefaction and
   Gasifiers            Gasifiers        Coal Refining
Surface Water  (Semi-arid)
     Surface mining-lignite
     Surface mining-bituminous coal
     Underground mining-bituminous coal
               TOTAL
Groundwater  (Semi-arid)
     Surface mining-lignite
     Surface mining-subbituminous-
                  bituminous coal
               TOTAL
Surface Water  (Arid)
     Surface mining-subbituminous coal
               TOTAL
Groundwater  (Arid)
     Surface mining-subbituminous coal
               TOTAL
Process-site Combinations - TOTAL
       3 (1)*
       7 (1)
      JO (0)
      10 (2)

       0 (1)
 0  (1)
 5  (1)
_0  (0)
 5  (2)

 2  (1)
 5' (1)
 4 (1)
JL (0)
10 (2)

 1 (1)
_2_ (1)
2 (2)
_i W
1 (1)
1 (1)
1 (1)
14 (6)
_2_
4
_2
2
_1
1
12
(1)
(2)
(1)
(1)
(1)
(1)
(6)
Ju vD
2 (2)
_0 (1)
0 (1)
_1 (1)
1 (1)
13 (6)
*Numbers in parenthesis are the minimum number of
 process-site combinations given in Table 3-1.
                                            (continued)

-------
         TABLE 3-17 (concluded)


              Site/Oil Shale Conversion
              	Process Criteria	

                  Surface Water
                  Underground Water

         Process-site  Combinations - TOTAL
en
Indirect Retorting    Direct Retorting
      2 (1)
      0 (I)
1 (1).
0 (1)
      2 (2)
1 (2)

-------
                         TABLE  3-18    COAL ANALYSES BY COUNTY FOR EASTERN AND CENTRAL  COALS  IN WT. PERCENT
en
03



Volatile Biatter
Fixed carbon
Ash


C



A»h

HHV*
ALABAMA
§
S 8-
V C
«M V
*4 M
v 5
r> S
23 48 7
26.0 23.1
55.6 23.4
16.1 4.8
100 100
23 48 7
71.0 32.1
44 22



16.1 4.B
100 100
12,790 5,340
ILLINOIS
M
•H
S >» «-t C «
•s ja u • o c
V r-l +1 ** -*
H v , S ,-, H
3 X w £ 9, ^
<*} W U) 5 fc" «

38 . 5 32 . 7 37 . 7 35 . 4 34 . 1 34 .0
38.0 38.9 39.9 47.1 40.3 49.7
100 100 100 100 100 100

60.1 56.0 61 . 1 66 . 6 58 . 8 67 . 9




100 100 100 100 100 100
10*760 10.190 11,070 12,100 10,650 12,260
INDIANA
c
4 M
C. > U
O -H -H
* O *H M
J3 ft H M
-4 -H 9 «
0 > « X

16.7 32.1 37. J 40.0
46.9 45.2 41.8 42.4
100 100 100 100

68.2 62.8 63.9 64.8


1

100 100 100 100
12,200 11,260 11,600 11,650
KENTUCKY
0*
i<
V •} U
5, ** •* «
o n .5 J<
rH « 3 -•
lu X X D.

36.4 38.3 34.5 33.2
57.3 54.3 47.3 59.0
1OO 100 100 100

79.8 77.6 64.8 79.6




100 100 100 100
14,300 13,900 11.800 14,300
                    •Btu/lb, calculated by Dulong formula (and differing leu than 2t from the reported value) .
                                                                                                                         (continued)

-------
                                    TABLE  3-18   (continued)
Ul



Volatile matter
Fixed carbon
Ash


c
H
O
N
S
Ash

HHV«
OHIO
a
« c.
1 0
« a
iq U M
~1 « 01
^ u "w
'H 01 «w
3 1 %

39.7 40.3 38.1
43.1 47.8 49.4
9.8 5.6 10.1
100 100 100

64.8 71.2 71.1
4.6 4.9 4.9
9.1 8.1 5.3
3.2 2.5 5.0
9.8 5.6 . 10.1
100 100 100
11,700 12,900 13,100
PENNSYLVANIA
en
c *J
O V
l< w
4J k*
i 1
C 0
< (/i

36.2 19.9
51.8 64.7
9.7 13.6
100 . 100

73.6 74.0
4.9 4.0
5.3 3.1
2.8 2.1
9.7 13.6
100 100
13,400 13,080
WEST VIRGINIA
a
~«
rH
e « « c
AJ £ V 0
i) > c -H 0
0 a O •> 0>
X C C « C
£l S £ i

23.6 34.5 29.1 29.5 36.1
65.4 54.3 61.4 57.3 56.8
8.0 9.3 6.4 10.7 4.9
100 100 100 100 100

78.5 75.1 78.8 74.6 79.5
4.6 4.9 4.9 4.7 5.2
3.7 6.7 4.2 3.3 5.9
0.8 0.7 1.1 2.7 0.9
8.0 9.3 6.4 10.7 4.9
1OO 10O 100 100 100
14,000 13,400 14,200 13,600 14,300

-------
                     TABLE  3-19    COAL ANALYSES  FOR WESTERN COALS  IN  WT.  PERCENT






£

1
V
4J
1-i
•rl
o
Mlsture 30.4
Volatile matter 30.1
Fixed carbon 31.7
Ash 7.8
100
Moisture 30.4
C 45.8
0 11.3
X 0.6
S 0.7
Ash 7.8
100
HHV« 7,920


»

„

2

V
«
a
i-t
£
3 i
23.6 26.2
31.9 31.9
34.8 37.4
9.7 4.5
100 100
23.6 26.2
48.3 52.6
13.2 12.0
0.7 0.6
1.0 0.5
9.7 4.5
100 100
8,200 9,OOO
H Y O H
•0
V
K
rH
£
i.

14
V
W
ft)
S

U1
28.0
31.7
32.5
7.8
100
28.0
46.8
12.3
0.7
0.9
7.8
100
8,060
INC





„

3 I
0» \t
2 S
a •
2 2
21.2 21.7
31.4 34.5
39.2 38.3
8.2 5.5
100 100
21.2 21.7
51.9 54.3
13.9 13.2
1.1 0.9
0.5 O.S
8.2 5.5
100 100
8,500 9.310

5
I
v
g

„

H
1
jj
3
11.8
40.1
40.0
100
11.8
60.5
12. S
1.5
1.1
8.1
100
10,660








i
«D

& a.
2.8 10.4
37.4 38.1
SO. 6 46.1
100 100
2.8 10.4
71.8 66.1
9.0 11.0
1.2 1.6
1.0 0.9
9.2 S.4
100 100
12,880 11,650








"c

$
w
44.4
25.2
23.7
100
44.4
32.9
11.0
0.6
1.8
6.7
100
5,620
N O








h
2 I
• •
•H U
C -H
35. 0 41.2
26.8 25.4
32.1 26.9
100 100
35.0 41.2
42.5 37.6
12.3 11.0
0.6 O.S
0.7 O.S
6.1 6.5
100 100
7,000 6.310
R T H D A K O








S
^ c
3 8
40.0 36.2
2G.O 26.2
28.4 29.0
100 100
40.0 36.2
39.1 39.9
11.2 11.0
0.7 0.6
0.6 0.9
5.6 8.6
100 100
6,580 6,720
T A








X
c
a
36.4
27.4
30.4
5.8
100
36.4
41.6
3 i
11.3
0.6
1.2
5.8
100
7,140









|
4)
•o
B
35.4
28.3
30.7
5.6
100
35.4
42.7
3 0
12.2
0.6
0.5
5.6
100
7,140









3
5
10
40.2
24.5
27. B
7.5
100
40.2
38.0
2.6
9.8
0.6
1.3
7.5
100
6,430
•Btu/lb, calculated by Dulong formula (and differing less than 2% froa reported value).
                                                                                                               (continued)

-------
TABLE 3-19  (continued)















Moisture
Volatile matter

Fixed carbon
Ash

Moisture
C
H
O
N
S
Ash

HHV*




H

V
-<






S
23.9
31.3

41.1
3.7
100
23.9
57.2
3.2
10.9
0.6
0.5
3.7
100
9,480

JS
^H
9
i


V
V





O
29.4
29.2

36.4
5.0
100
29.4
50.3
2.9
11.2
0.6
0.6
5.0
100
8,270














a
36.1
27.0

30.7
6.2
100
36.1
42.4
2.8
11.4
0.7
0.6
6.2
100
7,040
H O N T




a
it


u




03
e
30.7
27.2

34.4
7.7
100
30.7
45.7
2.9
11.8
0.7
0.5
7.7
100
7,550
ANA



M


14
O

c



I
30.7
28.5

32.9
7.9
100
30.7
44.6
3.1
12.5
0.7
0.5
7.9
100
7,460









0>
•a
•H


8
40.4
24.5

27.6
7.5
100
40.4
35.2
2.4
13.5
0.6
0.4
7.5
100
5,600

e
c
Q.
§•
e






tn


VI
D
38.3
24.4

30.0
7.3
100
38.3
40.4
2.5
10.6
0.6
0.3
7.3
100
6,600









Q,
-1
U


8
24.4
28.0

40.7
6.9
100
24.4
52.4
3.5
11.6
0.8
0.4
6.9
100
8,910
NEW









0

0

H
Id
16.3

64 5

19.2
100
16.3
49.2
3.6
10.2
o.e
0.7
19.2
100
8,620
H E











0

•
S
12.4
28.2

33.8
25.6
100
12.4
47.5
3.6
9.3
0.9
0.7
25. C
100
8,440
X I C 0










0,


3
15.1
34.2

45.6
5.1
100
15.1
63.2
4.7
10.4
1.1
0.4
5.1
100
11,300

-------
sulfur coals, the sulfur is in the organic form; in the high sulfur Eastern
coals, most sulfur is in the pyritic form.  High volatile coals agglomerate
at high temperatures and pressures causing blockages in the reactor.

3.6  Water Analyses
     The water analysis for each water source is shown in Tables 3-20 and 3-21.
 The surface water data were obtained from published U.S. Geological Survey
water supply-water quality reports, vjhile most of the groundwater data came
from STORET computer printouts.  The water source for each process-site
combination is given in Tables 3-15 and All-3 (Appendix 11);
                                        72

-------
TABLE 3-20   RAW SOURCE  WATER QUALITY FOR CENTRAL AND EASTERN  STATES (CONCENTRATION IN MG/LITER)


Ca* 1
M/+
HCO"
SV
TDS
Sl°2
pH (units)
•a si a
§ i § -1
5l 5 "S O
u J5 2 .S c
O fl O <0 M ft
> -4 U J3 H ftl -1
-H < 0 « < > -H
K > rH -H M
-H < ^ -  03 4J 3
3 w « « ioc ^ « X fi E 341 O 3t SI
-~H u $  1-1 IB? & (SJ
15 12 2.4 69 60
3.1 3.2 0.4 24 IS
53 53 600 247 200
18 92 17 102 90
91 76 880 466 360
9.1 7 9 7 7.5
6,9 7. 3 8.3 7.5 7.4
> s
a "o >,
«H 3 JC
Q WO
3 I 3
3 5 5 S 1
M O -H - 2
C -0 B
•H C 9
C r-s M Q C
-i ~i 5
R) MM »4~ C UO
t* £ Q v c h 0 ® tj
« 0 i> . So a v >u
> ^ ^-i
-j-O >0 « 41 -jo nlr
Kq T3i* ^) aic u
W C-H OJN C CflJ
— i o ot -HX -»U ®a
4p ^ tC -6 ^
o® o® 3®' o» o*a*
36 90 51 38 3S
9 50 15 10 S
106 250 166 97 115
60 100O 110 69 54
209 2000 269 216 191
S.5 9.0 i.7 4.6 5.9
7.4 7.7 7.7 7.1 6.9
1 *.
•$. o
— «
« *. jC
b .-i ^ B O
C *H If *-(
> ^H g • 1* ~4 fc
2> -H ™ « * Ift
w « e. > &„ ra
•-i H M a
§w >, • ece » &
C C C £ AJ U
(7- £ UQ «2 43Q
CO £E X« »U
-t O IP 5 5 c as
eor -10 CK ^tfi
3 --I 3 C
E an < «/ 2 & 3 a?
83 34 21 7S
17 10 5 20
132 17 62 21?
145 108 29 SO
582 215 134 363
6.3 7 7.3 7
7.2 6.2 7.1 7.5J
         TABLE  3-21    RAW SOURCE WATER QUALITY FOR WESTERN STATES  (CONCENTRATION  IN  iMG/LITER)



Ca++
Mcj+4
HCO"
SY
TDS
Sio2
en
g1 5
^ g |
O C N B
>, Lj lyi ^ ^ D
2 © C £ >i
> i-i O •> S
-H B ?*i l-<
c ni 0 S o
3 x > «
UTS 23 •> -^| X-H
eU-^< 0 M t-iK 4)4J
> LH ra • Q v ai si
S.C we MC MW Uy
10 CC Od B6J 3
ID -H(aa,u M no
33 UX O CO £02
D1 O -H f| W >
c -i Ti • | • « • a •
t- $ Sc re oc me
59 109 65 55 446
36 60 30 21 ).56
245 169 211 175 183
137 537 171 164 1802
451 945 429 394 4667
8.3 7.4 4.2 5.7 6,8
 •*-» ^
ffi -H C ffl ^ M *
fli « Q Q « 8) C
M 3G 3 > O
h O S) h • to -H -y
S e * e s ^5 * w
«0 SC7 -i" ^;*J -H=H
$4-> «M KG M 83 ® d «
O • H . -~t E .M ca •
Oc >-> e w®> iJE^c
70 54 69 49 62
100 21 39 19 21
600 173 511 161 191
1200 187 419 170 176
2200 424 1037 428 <336
12 9.6 11 7 9.3
<8
0 « *J
y 5
3-4 3
w X
o w c
| * g i
S . a I «
3 S i ? » 3
« > *J ~i •&
M C -H C g M
WO » Q 0 " «
? JJ £ M X M "•
MH ^ EP O © S 9) ^
9)-H KC g-> >s
H^ qp S5^« a -
cc « S G n >, T3 .
•0 3a sewia e^
•a « ^u* ok«> ?S
CJ= -HO-pM &•?•
flw e • ^u,|ee cu
O * WC > «; Oj ffi> S- "
39 55 40 136 52
21 9 14 69 36
363 143 138 247 222
412 114 109 769 167
931 300 284 1580 328
5.6 12 10 9.5 0
>H
V C 0
03 0 Si U -
BS ^ ~4 •
*> c « K tr-
et 0 c a* c
cxisr-Jrfep i S-5
j3 at c *j i*
£ c a 4) -=] £ S Q*
tJ • >. M S Q 8J U W
3- ffl£^UO 2 S«t
> e h >i > «
SO 30 C S »tH>>-4O
» £H | kit< e a a 6
-^k4 AJ S g@ it J* «! r-J 0 C
!- § @ a *o « o 9^> c] S jg T) S « t-i
0-) oe >.> Q cOMU
mp ^KMU ^ 3 o
m O ^-3 « < ~4° o°^H*
S«> >JW U© SC O C O C
63 55 133 13 12 61
21 21 66 6 13 20
197 183 216 1700 408 137
168 197 620 13 509 98
427 439 1046 2400 2655 589
6.3 10 7 S.6 14

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References - Section 3

 1.   Woodall-Duckham Ltd.,  "Trials of American Coals in a Lurgi Gasifier
     at  Westfield,  Scotland,"  Report No.  105  (NTIS Catalog No. FE-105) ,
     Energy Res.  &  Develop.  Admin., Washington,  D.C.,  Nov 1974.

 2.   Forney,  A.J.,  Haynes,  W.P.,  Gasior,  S.J.,  Johnson, G.E. and Strakey, J.P.,
     Jr.,  "Analysis of Tars,  Chars, Gases and Waters Found in Effluents from
     the Synthane Process," Technical Progress Report No. 76, Bureau of Mines,
     Dept.  of the Interior,  Pittsburg Energy  Research Center, Pittsburgh, Penn.,
     Jan 1974.

 3.   Farnsworth,  J.F., Mitsak,  D.M. and Kamody,  J.F.,  "Clean Environment with
     Koppers-Totzek Process,"  Symp. Proc.,  Environmental Aspects of Fuel Conver-
     sion Technology, pp.  115-130, Report No.  EPA-650/2-74-118, Environmental
     Protection  Agency, Research Triangle Park,  N.C.,  Jan 1974.

 4.   Goldstein,  D.J. and Yung,  D., "Water Conservation and Pollution Control
     in  Coal Conversion Processes", Report No.  EPA-600/7-77-065, Environmental
     Protection  Agency, Research Triangle Park,  N.C.,  June 1977.

 5.   Jones, J.B., Jr., "Paraho Oil Shale Retort,"  Quarterly Colorado School of
     Mines, 71,  (4), 39-48, Oct 1976.

 6.   McKee, J.M.  and Kunchal,  S.K., "Energy and Water Requirements for an Oil
     Shale Plant Based on Paraho Processes,"  Quarterly Colorado School of Mines,
     71, 49-64,  Oct 1976.

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

 8.   Bodle, W.W., Vyas, K.C.  and Talwalkar, "Clean Fuels from Coal, Technical-
     Historical  Background and Principles of  Modern Technology," Clean Fuels
     from Coal Symposium II,  pp.  53-84, Institute  of Gas Technology, Chicago,
     111.,  1975.

 9.   Tetra Tech,  Inc., "Energy from Coal - A  State-of-the-Art Review," ERDA
     Report No.  76-7, U.S.  Government Printing Office, Washington, D.C., 1976.

10.   Dravo Corp., "Handbook of Gasifiers and  Gas Treatment Systems," Report
     No. FE-1772-11, Energy Res.  & Develop. Admin.,  Washington, D. C., Feb 1976.

11.   Hendrickson, T.A., Synthetic Fuels Data  Handbook, Cameron Engineers, Inc.,
     Denver,  Colo., 1975.

12.   Probstein,  R.F. and Gold,  H., Water in Synthetic Fuel Production - The
     Technology  and Alternatives.   The MIT Press,  Cambridge, Mass., 1978.
                                      74

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13.   Freedman, S., Yavorsky, P.M. and Akhtar, S., "The Synthoil Process,"
     Clean Fuels from Coal Symposium II, pp 481-494, Institute of Gas
     Technology, Chicago, 111., 1975.

14.   Yavorsky, P.M., Akhtar, S. , Lacey, J.J., Weintraub, M., and Reznik, A.A.,
     "The Synthoil Process," Chemical Engineering Progress, 71, (4), 79-80,
     April, 1975.

15.   Schmid, B.K., "The Solvent Refined Coal Process," Symp. on Coal Gasification
     and Liquefaction, Univ. of Pittsburgh, Pittsburgh, Pa., Aug 1974.

16.   Institute of Gas Technology, Private communications, July 1976 and June  1977.

17.   Bureau of Mines, "Preliminary Economic Analysis of BCR Bi-gas Plant
     Producing 250 million SCFD High-Btu Gas from Two Coal  Seams: Montana
     and Western Kentucky," Report ERDA 76-48, FE-2083-2, UC-90-C, March 1976,

18.   Fluor Engineers and Constructors, Inc.,"Economics of Current and Advanced
     Gasification Processes for Fuel Gas Production," p. 85, Report EPRI-AF-244,
     Electric Power Research Institute, Palo Alto, Calif.,  1976.

19.   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 CP73-131, 1973.

20.   Bureau of Mines, "Preliminary Economic Analysis of Synthane Plant Producing
     250 million SCFD High-Btu Gas from Two Coal Seams: Wyodak and Pittsburgh,"
     ERDA-76-59, March 1976.

21.   U.S. Dept. of the Interior, "Synthoil Process Liquid Fuel from Coal Plant,
     50,000 Barrels per Stream Day.  An Economic Evaluation," Report No. ERDA
     76-35, Bureau of Mines, Morgantown, W. Va., 1975j summarized in Katell,  S.
     and While, L.G., "Economic Comparison of Synthetic Fuels Gasification and
     Liquefaction," presented at ACS National Meeting, Division of I&EC, New
     York, April 1976.

22.   Catalytic, Inc. for Southern Services, Inc., "SRC Technical Report No. 5,
     Analysis of Runs 19 through 40, 20 January  to 8 August 1974", Wilsonville,
     Alabama, unpublished report.

23.   Hydrocarbon Research, Inc., "Solvent Refining Illinois No. 6 and Pittsburg
     No. 8 Coals," Electric Power Research  Institute, Palo  Alto, California,
     Report EPRI 389, June 1975,

24.   Wright, C.H., et al, "Development of Process for Producing an Ashless Low-
     Sulfur Fuel from Coal, Vol. II, Laboratory  Studies, Part 2; Continuous
     Reactor Studies using Anthracane Oil Solvent," ERDA Research and Development
     Report No. 53, Interim Report No. 7, September 1975  (NTIS Cat. No. FE-496-T4)
                                        75

-------
25.   Averitt,  P.,  "Coal Resources of the United States, January 1, 1974.",
     Geological Survey Bulletin No.  1412, U.S.  Gov't Printing Office,
     Washington,  D.C., 1973.

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

27.   Keighin,  D.  W. , "Resource Appraisal of Oil Shale in the Green River
     Formation, Piceance Creek Basin,  Colorado," Quart. Colorado School of
     Mines, ^0_ (3),  57-68 (1975).

28.   Thomson,  R.D. and York,  H.F., "The Reserve Base of U.S. Coals by Sulfur
     Content  (in Two Parts).   Part 1:  The Eastern States," U.S. Bureau of Mines
     Information Circular 8680, 1975.

29.   Hamilton, P.A., White,  D.H. and Matson, T.K. ,  "The Reserve Base of U.S.
     Coals by Sulfur Content (in Two Parts).  Part  2:  The Western States,"
     U.S.  Bureau of Mines Information Circular 8693, 1975.

30.   Fluor Utah, Inc., "Economic System Analyses of Coal Preconversion Technology,
     Vol.  2, Characterization of Coal Deposits for  Large Scale Surface Mining,"
     Report No. FE-1520-2, Energy Research and Develop. Admin., Washington,
     D.C., July 1975.

31.   National Academy of Science, Rehabilitation Potential of Western Coal Lands,
     Ballinger Publishing, Cambridge,  Mass., 1974.

32.   U.S.  Geological Survey,  "Stripping Coal Deposits of the Northern Great
     Plains, Montana, Wyoming, North Dakota and South Dakota," U.S.  G.S.  Map,  1974

33.   Gold, H.  et al,  "Water Requirements for Steam-Electric Power Generation and
     Synthetic Fuel Plants in the Western United States," EPA Report No.
     400/7-77-037, U.S. Environ. Prot.  Agency,  Washington, D.C., February 1977.

34.   Fieldner, A.C.  , Rice, W.E. and Moran, H.E., "Typical Analysis of Coals of
     the United States," U.S. Bureau of Mines Bulletin 446, 1942.

35.   Akhtar, S. , Mazzocco, N.J. and Yavorsky, P.M., "Aqueous Effluents from the
     Synthoil Process," presented at 175th ACS  National Meeting, Division of
     Fuel Chemistry, Paper No.  58, Anaheim, California, March, 1978.
                                        76

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                           4.  WATER SUPPLY AND DEMAND

4. 1  Introduction
     A general assessment of the water resources data in the major coal and
oil shale bearing regions of the United States is presented in this section.
Water resources data have been collected and used as a basis for determining
the availability of surface and groundwater resources at each specific conver-
sion plant site selected in Section 3 in terms of other competing users.  This
work was performed under subcontract by Resources Analysis, Inc.  The two
reports submitted as part of their study have been included in their entirety
as Appendix 13 Water Availability and Demand in Eastern and Central Regions
and Appendix 14 Water Availability and Demand in Western Region and summarized
in this section.
     Sufficient and reliable water supplies are essential to the siting and
operation of coal and oil shale conversion plants.  Significant quantities of
water are consumed as a raw material, particularly when a high degree of wet
cooling is used.  The supply of water must be available on a continuous 24-
hour basis.  The economics of shutdowns due to water supply shortages are such
that the reliability of water supplies are a major consideration in establishing
the overall feasibility of siting at a particular location, or the feasibility
of siting a large number of plants within a given region.
     Potential water supply sources for each site were evaluated on a site
specific basis in terms of total available water supply, required plant use,
needs and rights of other competing water users, and the quality of the
alternative water supplies,  Factors considered were the extent and vari-
ability of nearby stream flows or groundwater aquifiers, legal institutions
regulating the use of these waters and the implications of competing users for
limited supplies in certain areas.
                                       77

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     In assessing the water resources situations at each designated site, no
attempt has been made to generate new field data.  All data used in the
investigation was previously collected by various Federal and State govern-
mental agencies, local State water boards and universities and private
concerns.  This study serves primarily to compile the existing data into a
form most useful for establishing the water related aspects of synthetic fuel
plant siting and complements more extensive studies that have recently been
completed, for example, the DOE Alternative Fuels Demonstration Program
(formerly called ERDA Synthetic Fuels Commercialization Program) and the
National Academy of Science's CONAES report, referred to and partially
                                                                  3—8
summarized in Ref. 2, and some studies for particular river basins
     In most of the Appalachian and Illinois coal bearing regions the legal
doctrine governing the use of water is the Riparian Doctrine which defines
surface water rights as ownership of land next to or traversing the natural
stream.  The cost of transporting water in these regions is very low because
of the close proximity of the coal conversion plant to the water source.  In
the Western coal and oil shale bearing regions the Appropriation .Doctrine
usually applies.  The first appropriation of the water conveys priority
independently of the location of the land with respect to the water so that
the source water may not be in close proximity to the conversion plant.
Furthermore, chronic water shortages exist in many of the river basins. . Large
reservoirs may have to be built on the main stems of the principal rivers and
water transported over large distances to the water-short regions. The cost of
transporting water to a particular site is an important consideration in
determining the total water consumed at that site.
4.2  Eastern and Central'Regions
     The major coal regions in the Eastern and Central states are located in
the Appalachian arid the Illinois coal regions.  The Appalachian coal region
extends from eastern Pennsylvania through eastern Ohio, eastern Kentucky, West
Virginia and into northern Alabama.  The Illinois region includes the deposits
in Illinois,  southern Indiana and western Kentucky.  The Appalachian region
is characterized by highly variable terrain resulting from extensive geologic
folding and faulting, while the Illinois region  is underlain by a smoother,
                                       78

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much more consistent geologic  framework.
     The majority of the study sites shown  in Table  3-10  are  located within
the limits of the Ohio River Basin.  A  few  others are  located in  the Upper
Mississippi Basin in northern  central Illinois  and the Mobile River  Basin in
central Alabama.  Annual precipitation  and  runoff exceeds  the national  average
(30 in/yr) throughout the  region  and water  supplies  are generally plentiful.
Monthly and season variability in precipitation is greatest in the northwest
portion of the region and  least in  the  southern part.  The major  water  use is
municipal and industrial.
     The water supplies of the major rivers of  the Appalachian region,  shown
in Figure 3-4, are generally plentiful  with total average  stream  flow of more
than 150 billion gallons daily .  Surface water reservoirs within the region
can store about 25 percent of  the total average stream flow.   Groundwater is
generally abundant but its availability varies  throughout  the region.   These
water  supplies are supported by ample rainfall  and runoff.  In the northern
part of the basin, the precipitation averages about  35 in/yr  with more  precipi-
                                              9
tation occurring in the late spring and summer  .  The  southern region receives
an  average of 55 in/yr of  precipitation with most of the precipitation  during
winter and early spring.   Surface water runoff  averages 20 in/yr  throughout
the region with some areas in  the south averaging 30 to 40 in/yr.  The
evaporation from open water surface ranges  from 28 in/yr  in Pennsylvania to 42
                9
in/yr  in Alabama .
     The situation in the  Illinois  coal region  (Figure 3-4) is similar  to that
in  the Appalachian region  with respect  to water supply.  Both surface water
and groundwater are abundant and  are supported  by ample rainfall  and surface
       4
runoff -  The average precipitation ranges  from 35 to  40  in/yr in central
Illinois to about 48 in/yr in  western Kentucky.  In  the northern  part of the
region most of the precipitation  occurs in  the  spring, while  in the  southern
part the highest precipitation occurs in midwinter and early  spring.  The
average annual surface runoff  ranges from 8 in/yr in the northern region to 18
in/yr  in the southern region,  with  the  highest  runoff  occurring at the  same
time as the highest precipitation.  The annual  average evaporation from an
open water surface is 33 in/yr in Illinois  to 36 in/yr in western Kentucky.
                                        79

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     In the Eastern and Central regions the use of surface flows is usually
subject to the Riparian Doctrine, which defines surface water rights as
ownership of land next to or traversing the natural stream.  The owner of
riparian land has the right to make use of the surface water in connection
with the use of the riparian land as long as such use is reasonable with
respect to others having a similar right.  The Riparian Doctrine establishes
an order of preference among various categories of users for determining a
reasonable share; domestic users have the highest priority and industrial
users a relatively low ranking.
Surface Water Availability
     The adequacy of the water supply at each primary site having a river or
stream as its water source was assessed through a comparison of a typical
plant use with expected low-flows in the stream.  As we discussed previously,
the Riparian Doctrine governing water use in the Eastern and Central states
requires each use be reasonable in relation to other riparian uses.  For
preliminary screening purposes plant use at each site was compared to the
low-flow in the associated water source to establish whether the use would
probably be reasonable, possibly be reasonable, or probably be unreasonable.
The criteria used in judging the situation at each site were the following:
          Favorable;  Site use is less than 5 percent of the estimated
                      seven-day, twenty-year low-flow.
          Quesionable;  Site use is about 10 percent of the estimated
                      seven-day, twenty-year low-flow.
          Unreliable: Site use is more than 20 percent of the estimated
                      seven-day, twenty-year low-flow.
     The seven-day, twenty-year low-flow used in the comparison is defined
to be the minimum average flow over seven consecutive days that is expected
to occur with an average frequency of once in twenty years.  This is an
appropriate criteria for sites having a useful life of .about twenty years and
holding ponds with a reserve capacity of about a seven-day water supply.
Low-flow values were determined from stream-flow data reports for each state, from
various state or regional agencies, or were estimated from historical low-flow
at nearby gauging stations.  Low-flows from major streams where flow is
regulated  are very difficult to establish accurately.  In many of these
                                     80

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instances, however, flows are relatively high and a normal result of regu-
lation is to achieve higher low-flow.
     In Section 5 we summarize the net water consumed by region for the
standard size synthetic fuel plants shown in Table 3-3.  For the Central and
Eastern states the water consumed ranged from a low of 1.7 x 10  gpd to a high
of 6.8 x 10  gpd,  with the low value corresponding to a high degree of dry
cooling and the high value corresponding to a low degree of dry cooling (high
wet cooling).  We have assumed a typical plant use of 6.5 x 10  gpd (about 10
c.f.s. or 7000 acre-ft/yr) for the water availability analysis; it should be
remembered that this is a high water use.
     For the purpose of a detailed feasibility analysis of water availability,
the choice of a water source for each of the sites selected in Section 3 was
based upon the source being contiguous or in close proximity to the site.   The
list of coal conversion plant sites and the water sources chosen on that basis
are shown in Table 4-1.  A number of secondary sites shown in Table 4-2 were
also considered in order to provide a larger study area with respect to water
availability in the coal regions as a whole, but were not considered in the
detailed analysis of specific sites.  The water sources shown in Table 4-1
differ from those shown in Table 3-10 since they were chosen on a different
basis.  For each water source,  representative water quality data for that
source was required for determining the costs and energy of water treatment
within the coal conversion plant.  We were not able to find water quality data
for many of the sources listed in Table 4—1.  The water sources shown in Table
3-10 are those for which we were able to obtain water quality data (Appendix
11).    In this section we will be primarily concerned with the water sources
shown in Table 4-1.
     Table 4-3 lists the runoff characteristics of each primary supply source
and the results of the assessment based on local low-flows.  The analysis
shows that surface supplies are most favorable for those sites having the main
stream of a major regulated river near by.
     Surface water supplies are shown to be much less reliable for many of the
smaller streams away from the major rivers.  In many of these streams low-
flows may in fact be less than the typical coal conversion plant requirement.
In other cases a plant water requirement would represent a large portion of
the flow and such a use would probably interfere with other small existing
users.
     The analysis described above clearly suggests that there are sites having
                                      81

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     TABLE 4-1  LIST OF PRIMARY COAL CONVERSION PLANT SITES

                 FOR CENTRAL AND EASTERN STUDY
State
Alabama
Illinois
County

Jefferson
Marengo

Bureau
Shelby
St. Clair
White
Bureau
Fulton
St. Clair
Saline
Water Source

Coosa River
Tombigbee River or Groundwater

Groundwater
Kaskaskia River
Mississippi River
Wabash River
Illinois River
Groundwater
Mississippi River
Saline River
Indiana
Gibson
Vigo
Sullivan
Warrick
White River
Wabash River
Wabash River
Ohio River
Kentucky
Floyd
Harlan
Muhlenberg
Pike
Big Sandy River
Cumberland River
Green River
Levisa Fork
Ohio
Pennsylvania
West Virginia
Gallia
Jefferson
Tuscarawas
Tuscarawas

Armstrong
Somerset

Fayette
Kanawna
Mingo
Monongalia
Preston
Ohio River
Ohio River
Tuscarawas River
Groundwater

Allegheny River
Allegheny River

New River
Kanawha River
Big Sandy River
Monongahelia River
Cheat River
                             82

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TABLE 4-2   LIST OF SECONDARY COAL CONVERSION PLANT SITES
                        County                  Water Source

                        DeKalb                  Tennessee River
                        Fayette                 Warrior River
                        Jackson                 Tennessee River
                        Marion                  Tennessee River

    Illinois            Mercer                  Mississippi River
                        McLean                  Illinois River

    Kentucky            Henderson               Ohio River
                        Hopkins                 Green River
                        Lee                     Kentucky River
                        Lawrence                Big Sandy River
                        McCreary                Cumberland River

    Ohio                Morgan                  Muskingum River

    Pennsylvania        Venango                 Allegheny River
                        Clearfield              West Branch River
                        Cambria                 Conemaugh River

    West Virginia       Greenbrier              Greenbrier River
                        Marshall                Ohio River
                        Randolph                Tygart River
                               83

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                                TABLE  4-3   ASSESSMENT  OF POTENTIAL SURFACE WATER SOURCES
CD
State
Alabama

Illinois






Indiana


Kentucky




Ohio



Pennsylvania

West Virginia














Drainage USGS Mean Historical 7 day - 20 Yr.
County Source Area Gauge No. Flow Low-Flow Low-Flow Situation Possible Alternate Source
(SM) (CFS) (CFS) (CFS) (1)
Jefferson Coosa 8.390 4070 13,790 370
HQrengo Tomblgbee 5,900 4450 8,631 165
Bureau Groundwater — — — —
Bureau Illinois 12,040 — 12.500(E) 1.800(E)
Fulton Groundwater
St. Clalr M1ss1ss1pp1(R) 700,000 0100 177,000 18,000 10
Saline, Saline --- None --- 10(E)
Shelby Kaskaskla(R) 1,054 5920 788 0
White Wabash 28,635 3775 27,030 1,650
Gibson Wh1te(R) 11,125 3740 11,540 573
Sullivan Wabash(R) 13.161 3420 11,600 858
Vigo Wabash(R) 12,265 3415 10,660 701
HarHck Ohio(R) 107,000 3220 113,700 NA 2
(13
Floyd Levlsa Fork 1,701 2098 2,104 20
Harlan Cumberland(R) 374 4010 689 3
Henderson Oh1o(R) 107,000 3220 133,900 NA 15
Muhlenburg Green Pond(R) 6,182 3165 9,201 250
P1ke Levlsa Fork 1,237 2015 1,458 2
Galla Oh1o(R) --- --- 77,600 — 8
Jefferson Ohio(R) -— — - 40,900 --- 5
Tuscarawas Tuscarawas(R) 2,443 1290 2,453 170
Tuscarawas Groundwater — — — —
Armstrong Allegheny(R) 12,500 — 19,500(E) 900(E)
Somerset Casselman 382 0790 655 10
Fayette New(R) 9,000 1930 10,500 950(3) 1
Kanawha Kanawha(R) 10,419 1980 14,480 2,360 1
Marshall Oh1o(R) — — - 40.900 — 5
Mlngo Tug Ford(R) 850 2140 1,351 17(3)
Honongalia Honongahela(R) 4,407 0725 8,137 20
Preston Cheat 972 0700 2,239 10
(1) Situation assessment: F-Favorable, Q-Questionable, U'Unrellable
(2) Low-flow (1 day, 50 year) data from Illinois State Water Survey (1975)
(3) Estimated from nearby gauges
(4) Estimated using regression equations In Streamflow Data Program Reports
(5) Low flow (7 day, 10 year) from ORBC Table of Instream Flows
(6) Pennsylvania Department of Forests and Waters, Bulletin No. 1 (1966)
(7) Ohio Department of Natural Resources Bulletin 40 (1965)
(E) Estimated from best available information
(R) River substantially regulated at source location
	

	
800(2)
_--
.000
(NA)
(NA)
800(2)
610(4)
350(2)
300(2)
,000(2)
,000(5))
(NA)
(NA)
,400(5)
(NA)
(NA)
,600(5)
.600(5)
215(7)
...
(NA)
12(4)
.184
,750
,600(5)
30
248
95



(USGS.





F
F
See Table 4.1
F
See Table 4.1
F
U Ohio or Prop. Res.
U Lake Shelbyville
F
F
F
F
F
U Dewey Lake
U Surface Storage
F
Q Groundwater
U Flshtrap Lake or Groundwater
F
F
Q Groundwater
See Table 4.1
F
U Quemahonlng Res.
F
F
F
U Groundwater
Q Surface Storage
U Lake Lynn or Groundwater



1970)





                          (NA) Data not available at present, or nonapplIcable

-------
abundant supplies at hand where meeting the water requirements of one or more
conversion plants would be no problem.  There are others where supplies are
such that the designated supply source could not be relied on during very dry
periods and where alternative or supplemental sources should be developed.
The supplies available at several other sources are in between the extremes.
The adequacy of these sources depends in large part on the extent of other
competing uses or the likelihood that competing demands will develop the
future.
     As noted earlier, in addition to the primary specific sites, additional
sites in several other regions were  considered to complete the assessment of
overall water availability throughout the coal regions.  Using the same
analytical criteria as described earlier, these additional sites are listed in
Table 4-4 with their associated water source and a general assessment of the
water supply availability at each site.
     In summary, within the Appalachian Basin, where coal is available, there
are a number of large rivers contiguous or adjacent to many of the sites that
can provide a sufficient and reliable supply of water to support one or more
large mine-plant coal conversion complexes.  This applies to all plant sites
in the vicinity of the Ohio, Allegheny, Tennessee, Tombigbee and Kanawha-New
Rivers. In most of these instances present water use data and future demand
projections indicate a significant surplus streamflow beyond expected use,
even under low-flow conditions.  For the few cases where data on other demands
is not readily available, the coal conversion plant demand is generally in the
order of less than one percent of the seven-day- twenty-year low flow.  Uses
of this magnitude would appear to safely satisfy the common law requirement of
being reasonable relative to the users.  The surface water supplies are much
less reliable in the smaller streams, away from the major rivers.  Regions
generally found to have limited water supplies for energy development include
the upper reaches of the Cumberland  and Kentucky rivers in eastern Kentucky,
the eastern Kentucky and adjacent West Virginia coal regions in the Big Sandy
River Basin, and northern West Virginia and western Pennsylvania in the
Monongahela River Basin, except those areas that can be supplied from the
Allegheny, Ohio or Susquehanna Rivers.  In these areas extreme low flows are
practically zero, and a coal conversion complex could easily represent a
significant portion of the seasonal  low-flow in many of these areas.  In order
for a plant to be sited in these regions, an alternative or supplemental
supply to stream flows must be assured.

                                       85

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                              TABLE  4-4   ASSESSMENT OF ADDITIONAL SURFACE WATER  SOURCES
CD
State
Alabama

Illinois

Kentucky



Ohio
Pennsylvania


H. Virginia







Drainage USGS Mean Historical
County Source Area Gauge No. Flow Low Flow
(SH) (CFS) (CFS)
Fayette Warrlor(R) 4828 4650 7822 37
Marlon Tennessee(R) 30810 5895 51610 105
Jackson Tennessee(R) 25610 5755 43760 400
De Kalb Tennessee(R) 25610 5755 43760 400
Mercer Mlssisslppl(R) 119000 4745 62570 5000
McLean Illinols(R) 15819 5685 14529 1810
Hopkins Green(R) 7564 3200 10960 280
McCreary Cumberland 1977 4045 3199 4
Lee Kentucky 2657 2820 3638 4
Lawrence B1g Sandy(R) 2143 2150 2480 8.4
rtorgan Muskingum 7422 1500 7247 218
Venango Allegheny(R) 5982 02550 10330 334
Clearfleld West Branch 1462 5425 2467 100
Cambria Conemaugh 715 04150 1269 105
Randolph Tygart 408 0510 800 0.1
GreenbHer Greenbrler 1835 1835 1980 24
(1) Situation assessment: F*Favorable; q-questlonable; U=Unrel1able
(2) Low-Flow (1 day, 50 year) from Illinois State Water Survey Report No
(3) Estimated using regression equations In USGS Streamflow Data Program
(4) Pennsylvania Department of Forests and Waters Bulletin No. 1 (1966)
(5) Ohio Department of Natural Resources Bulletin 40 (1965)
(R) River substantially regulated from source location
7 day, 20 Yr.
Low Flow Situation
(CFS) (1)
N.A.
N.A.
N.A.
N.A.
6500(2)
N.A.
N.A.
12(3)
8.6(3)
74(3)
565(5)
N.A.
115(4)
155(4)
0.4(3)
43(3)

. 4 (1975)
Reports (1970)



Q
F
F
F
F
F
F
U
U
Q
F
F
Q
Q
u
q






Possible Alternate Source
Groundwater
—
...
...
—
Lake Cumberland
Unknown
Ohio River
...
...
Unknown
Unknown
Tygart Lake
Bluestone Res.






                      (NA) Data not available at present or non-appl1cable

-------
     Within the  Illinois  Basin,  the Ohio and Mississippi Rivers have sufficient
and reliable water  supplies  to support one or more large mine-plant coal
conversion complexes.   The  lower sections of the Kaskaskia,  Illinois and
Wabash Rivers, in Illinois;  the Wabash and White Rivers in Indiana;  and the
Green River in Kentucky also have reliable supplies.
Surface Water Doctrines
     The general aspects  of  water use regulations were reviewed primarily as
applicable to the surface water supply assessments described previously.   As
stated above, the reasonable use interpretation of the Riparian Doctrine is
now widely accepted.  Each owner of riparian land (i.e.  traversed by or
adjoining a natural stream)  has  the right to make any use of the water in
connection with the use of the riparian land as long  as  such use is reasonable
with respect to others' having a similar right.   This suggests  three important
considerations related  to the use of water for energy development.
     1)  Reasonable use.  This is a rather vague requirement primarily deter-
mined by the impact of  the use in question on other valid users.  This is a
relative matter and is  generally dependent more on the magnitude of the
proposed use than the nature of  it.   The basic requirement is that  some degree
of sharing of available supplies must take place among the various  demands.
     2)  Riparian land  use limitation.   This important aspect of the Doctrine
requires that water use be restricted to the riparian land upon  which the
right is derived.  The  basic requirement for land to  be  riparian is physical
contact with the water  source.   This can be a significant limitation on the
availability of an otherwise adequate water supply source when  coal reserves
are located some distance away from the  water.   Certain  state regulations
allow use on non-riparian land where supplies are sufficient, so that no
riparian user is injured by  such a  use.   Thus,  non-riparian  use  is  generally
dependent on the existence of  surplus water after all riparian use  has  been
satisfied—a very restrictive  condition.   Only  the major  rivers  of  the  region
such as the Kanawha, Allegheny,  Ohio and Mississippi  can  satisfy this  condition
reliably enough to justify the large capital  investments  involved in the
construction of coal conversion  plants.
     3)   Variability over time.  An  important limitation  in  the  Doctrine  to
significant users requiring  dependable,  long-term  availability such as  synthetic
fuel plants is  that a reasonable use  at  one point  in  time  may become unreason-
able at some unknown future  time.  Other  riparian  owners  do  not  lose their
                                       87

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right through disuse.  Also, riparian water rights generally are not  quantified
and recorded, but simply must remain reasonable with  respect to all other users.
     In addition to the above, the Riparian Doctrine  establishes an order of
preference among various categories of users for determining a reasonable
share with domestic users having the highest priority and  industrial  users a
relatively low ranking.  It is possible, however, that  should the  national
energy situation continue on its present course, energy development users in
the future may have a high social priority.
     Several Eastern states have recently adopted statutory modifications to
the Common Law Doctrine that allow some degree of water appropriation by
permit. These states are Kentucky, Indiana, Iowa and  North Carolina.   These
statutory modifications are generally aimed at allowing potential  users,
including in some instances non-riparian users, to obtain  the legal right to
use a specified quantity of water.  At the same time  they  attempt  to  insure
that no existing user would be harmed and all riparian  rights are  preserved.
The effect of such legislation would be to encourage  high  investment  type
industries requiring firm and reliable sources of water to locate  in  other
areas than they could presently.  Historically the vague requirements of the
Riparian Doctrine have forced signficiant water using industries to locate
primarily on the major rivers of the region that have surplus flows.
Competing Water Use
     In the previous section we have made an assessment of surface water
sources in terms of the relative amount of streamflow at low-flow  conditions
that would be required for a coal conversion plant.   This  approach provides a
good basis for identifying sites where the water requirements of a typical
coal conversion plant would be a reasonably small fraction of the  total
surface water flow under drought conditions and therefore  could be reliably
maintained.  It also clearly points out sites where the  plant requirements
probably or might not always be maintained since another provision of the law
is that users must also share in cutting back their use when supplies are
low.
     Although this approach gives a valid indication  of the relative  reason-
ableness of  a typical conversion plant use, another factor that might be
considered  in plant siting is the amount of competing use  in a particular
                                        88

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location from such other water demands  as municipal, industrial, power
production, etc.  The difference between the low-flow in a stream or river and
the total present or projected water use is the surplus flow available for
coal conversion,  or a deficit indicating that supplies are insufficient even
for other uses.  This information would be of particular importance where coal
resources are located 391116 distance away from a water source and a non-riparian
use of the water is being considered.   Such a use might be feasible if a
significant surplus supply exists at the source and therefore no other user
would be harmed by the withdrawal.
     Although data on other  competing uses is not available for all sites,
data compiled by the Ohio River Basin Commision   gives estimated consumptive
water use for 1975 and 2000  for the Ohio River main stem and its larger
tributaries.  This data was  used to compute surplus  (or deficit) water supplies
available under critical low-flow conditions for many of the specific sites
being studied.  Water use quantities for the tributary basins were given for
the entire basin.  For sites located some distance into these basins, water
use quantities were estimated as being  proportional to the ratio of drainage
areas.  The estimated present and future consumptive water use for other uses,
and the results of the supply surplus calculations for a number of sites are
presented in Table 4-5.
     It is apparent from these results  that significant water surpluses exist
even at low-flow conditions  all along the Ohio main stem both now (year 1975)
and in the future  (year 2000).  In fact at least some surplus under present
use conditions exists at all sites listed.  Under future (2000) conditions
deficit supplies are indicated for the  Monongahelia River at Monongalia
County, W. Virginia and the  Wabash River at White County, Illinois, and only a
relatively minor surplus will exist for the Tuscarawas River at Tuscarawas
County, Ohio.  Most of the other sites, too far removed from the Ohio main
stem for meaningful use estimates, would also be expected to show supply
deficits under these conditions.  However, the Wabash and White Basins, and
some others, have excellent  supplies of groundwater, as is described below.
     Thus far we have considered the availability of water for single mine-
plant complexes without considering the development of a large scale synthetic
fuel industry.  For example,  if a synthetic fuel industry is to produce 1x10
barrels/day of synthetic crude, or its  equivalent in other fuels of
                                      89

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              TABLE  4-5     ESTIMATED  CONSUMPTIVE  WATER  USE
AND  SURPLUS SUPPLIES IN  THE  OHIO RIVER  BASIN  FOR 1975  AND  2000
Location
Allegheny R.
(Allegheny Co. Pa. )
Honongahela R.
(Monongalla Co. W. Va.)
Ohio R.
(Jefferson Co. Ohio)
Ohio R.
(Marshall Co. W. Va.)
Musklngum (Tuscarawas)
R. (Tuscarawas Co. Ohio)
Kanawha R.
(Kanawha Co. W. Va.)
Ohio R.
(Gal Ha Co. Ohio)
Ohio R.
(WarMck Co. Ohio)
Green R.
(Muhlenburg Co. Ky. )
Ohio R.
(Henderson Co. Ky. )
Wabash R.
(White Co. 111.)
Mean
Annual (4)
Flow
(cfs)
19.500
8,137
40,900
40,900
2,453
14,480
77,600
113,700
9,201
133,900
11.540
Low Flow
7 Day, 20 Yr
Except as
Noted
(cfs)
1,000 (1)
248
5,600 (2)
5,600 (2)
215
1,750
8,600 (2)
13,000 (2)
500 (1)
15,400 (2)
610 (3)
Estimated
Present
1975
Use (5)
(cfs)
280
110
695
700
45
130
1 ,010
1,420
55
1,500
330
Available Quantity Estimated Available Quantity
With Present Future With Future
Use at Low 2000 Use At Low
Flow Conditions Use (5) Flow Conditions
(cfs) (cfs) (cfs)
720
138
4,905
4,900
170
1,620
7,590
11,580
445
13.900
280
350
310
1,129
1,306
85
240
1,980
3,220
60
3,310
1,120
650
-62
4,471
4,294
130
1,510
6,620
9,780
440
12,090
-510
      NOTES:    (1)  Estimated  from available Information
               (2)  Ohio River Basin Commission (1977) estimates
               (3)  Low-flow (1 day, 50 year) from Illinois State Water Survey Report No. 4 (1975)
               (4)  Mean flow  from U.S.G.S. Data
               (5)  Estimated  uses are accumulated consumptive use for the Ohio Main Stem, or on
                   Its tributaries, use at the named location determined from the  total tributary
                   basin use  from the ratio of drainage areas (ORBC 1977)
                                              90

-------
5.8x10   Btu/day in the Appalachian coal region and  an equal amount in the
Illinois coal region, then approximately 18 standard size clean  coal plants
each producing 10,000 tons/day of solvent refined coal to 24 standard size
coal gasification plants, each producing 250x10  scf/day of pipeline gas would
be required in each region.  The maximum quantity of water that would be
required in each region would be approximately 160x10  gpd (or about 240 cfs
or 170,000 acre-ft/yr).  Table 4-5 shows there should be sufficient water
available to support this level of synthetic fuel development in each of the
two basins all along the main rivers even at low flow conditions.
Groundwater Supply
     Groundwater was specified as a primary supply for certain sites located
in Illinois and Ohio.  In several other regions, conditions appear to be
favorable for the development of groundwater as an alternative source to
unreliable surface supplies or as a supplemental source.  Groundwater sources
may also have institutional advantages in some instances even though they
would generally be more expensive to develop than surface supplies.
     Groundwater in the East/Central coal region states is a large and
important water resource that may have a significant role in the development
of the coal resources.  In the Ohio River Basin, which encompasses much of the
study area, present groundwater development plans do not nearly utilize the
full potential of the resource.  It has been estimated   that the average
annual groundwater recharge of the region is about 35 billion gallons per day.
Annual groundwater use in 1960 by municipal and rural users was estimated to
be about one billion gallons per day or only about 3 percent of recharge.
Although not all of the groundwater is recoverable or located so as to be of
value in energy development, much of it is.
     Figure 4-1 shows the general locations of high-yield sources of ground-
water in the region.  Primary groundwater sources and all surface sources
classified as unreliable in the assessment of surface supplies were considered
in an initial review of groundwater availability.   A screening process similar
to that used for surface sources was utilized to establish whether or not it
would be feasible to develop groundwater as sources  of supply.   The following
criteria were used in assessing the situation at each site:
                                      91

-------
90'00'
                                  86'00'


35-1
00' 1
90*00'





t^fj
n
^j
TENNESSEE S 	
MISSISSIPPI \_
"/




V^. — NASHVILLE (
^S/
I TENNESSEE
ALABAMA | ~T Cl
86-00' \

0 50
1 1
1 	 1 1
0 50 100
^-f'1
•^
/^
(
JKORTIJ CAROUN.\-^ cl
EORCIA /&
&

100
1
1
^

s*oV^4M_ 35-00'
82' OO'

20O MILES
1

200 KILOMETERS
                                                 EXPLANATION




                                          Potential yields to individual wells





                                         Unconsolidated aquifers, greater than 500 gpm




                                         Unconsolidated aquifers, 100-500 gpm




                                         Consolidated aquifers, 100-500 gpm
                    Figure  4-1  High-yield sources of ground  water





                                                  92

-------
     Yield Characteristics
     A.  Favorable.     Well yields are expected to approach  500 gpm or more.
     B.  Possible.      Well yields are expected to exceed 100 gpm.
     C.  Unfavorable.   Well yields are generally less than 50 gpm.
     Accessibility
     A.  On-site
     B.  Near by
     C.  Distant
     Table 4-6 lists the primary sites considered in the groundwater analysis
and the results of the assessment.  Many of the sites show good potential for
groundwater development.
     The Wabash and White subbasins probably have the highest potential of
all Ohio River subbasins for additional groundwater development.  It is
estimated that about 30,000 billion gallons, or nearly 30 percent of the
total potable groundwater available from storage in the Ohio region, is
stored in these subbasins  .  Estimated average annual groundwater recharge
in these basins is 7.3 billion gallons per day while 1960 groundwater withdrawal
estimates are only about 0.22 billion gallons per day (about 3 percent of
recharge) which is only about 0.3 percent of potable groundwater storage.
Many very high yield aquifers offer excellent possibilities for use to supply
energy development programs.  A further discussion of the groundwater situation
at the sites having groundwater designated as a possible primary source is
found in Appendix 13.
     An assessment of the additional secondary sites is given in Table 4-7.
Of these, conditions appear to be most favorable for groundwater development
in Fayette County, Alabama.  With the exception of McCreary and Lee Counties,
where little potential appears to exist for large groundwater supplies,
development is a possibility at the other sites, depending on actual location.
     Unfortunately the groundwater situation is most favorable from alluvial
aquifers recharged by major streams in the valley bottoms where surface supplies
                                        93

-------
                         TABLE  4-6.   ASSESSMENT OF GROUNDWATER AVAILABILITY AT PRIMARY SITES

                                          WITH INSUFFICIENT SURFACE SUPPLIES
State
Alabama
Illinois
Kentucky
Ohio
Pennsylvania
West Virginia
County
Jefferson
Bureau
Fulton
Saline
Shelby
Floyd
Harlan
Muhlenberg
Pike
Tuscarawas
Somerset
Mingo
Monongalia
Preston
Presently
Designated
Source
Coosa
Groundwater
Groundwater
Saline
Kaskaskia
Levisa Fork
Cumberland
Green
Levisa Fork
Tuscarawas & GW
Casselman
Tug Fork
Monongahela
Cheat
Potential
Groundwater
Yield*
Favorable
Favorable
Favorable
Unfavorable
Possible
all okay
Unfavorable
Unfavorable
Possible
Favorable
Favorable
Favorable
Favorable
Unfavorable
Favorable
Groundwater
Accessibility
On-site
On-site
On-site
Near-by
Distant
Distant
Distant
Near-by
On-site
On-site
On-site
On-site
Distant
On-site
Groundwater
Feasibility
Yes
Yes
Yes
No
Possible
No
No
Possible
Yes
Yes
Yes
Yes
No
Yes
*Favorable = > 100 gpm and  likely  to  approach or exceed 500 gpm
 Possible  = generally > 100 gpm
 Unfavorable = < 50 gpm

-------
                           TABLE 4-7.  ASSESSMENT OF GROUNDWATER AVAILABILITY AT THE SECONDARY SITES
     State
     Alabama
     Kentucky
     Perin.
     West Va.
County
Present Source
Potential Ground-
  water Yield*
 Groundwater
Accessibility
Fayette
Marion
Jackson
DeKalb
McCreary
Lee
Clearfield
Cambria
Randolph
Greenbrier
Warrior
Tennessee
Tennessee
Tennessee
Cumberland
Kentucky
West Branch
Conemaugh
Typgart
Greenbrier
Favorable
Possible
Possible
Possible
Unfavorable
Unfavorable
Possible
Possible
Possible
Possible
On- site
On- site
On- site
On-site
Distant
Distant
On-site
On-site
On-site
On-site
     Preliminary
Groundwater Feasibility

        Yes
      Possible
      Possible
      Possible
        No
        No
      Possible
      Possible
      Possible
      Possible
Ln
     *Favorable  = > 100 gpm and likely to approach or exceed 500 gpm
      Possible   = generally > 100 gpm
      Unfavorable = < 50 gpm

-------
are best, and least favorable from less transmissive  consolidated  aquifers
higher in the watersheds where surface supplies tend  to  be poorest.   Since the
aquifer structure is highly fractured in many areas under study, expected well
yields can vary tremendously over a county-sized  area.
Groundwater Doctrines
     The principal groundwater doctrines affecting the use of groundwater
involve the concepts of absolute ownership and that of reasonable  use.  Absolute
 ownership recognizes a landowner as the owner of all groundwater  beneath his
land and allows him to use it or interfere with it in any way without being
accountable to other uses which may be affected.  Although this interpretation
is somewhat archaic, it still receives some continued acceptance.
     The concept of reasonable use of groundwater is most widely accepted and
involves a definition of reasonable use significantly different than that
under the Riparian Doctrine of surface supplies discussed previously.   As
applied to groundwater, any reasonable use in connection with the  land  from
which the groundwater is taken is allowed without regard to impacts the
withdrawal may have on other users.   Since the rights of property  owners  are
clearly more absolute with regard to groundwater use than in the case of
surface water, the development of reliable groundwater supplies for energy
production may be preferable in certain areas on the basis of institutional
feasibility.
Potential Environmental Impacts
     A number of potential hydrologic and environmental impacts are associated
with both the traditional coal mining operation and the process of converting
the coal produced to synthetic fuels.   The mining operation,  whether it be
underground or strip mining,  creates the potential for environmental problems
resulting from the earthmoving operation (erosion, sedimentation of stream
channels,  and scarring the land)  and the mine dewatering process (acid mine
                                      96

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drainage and depletion of groundwater  supplies).  Modern mining  techniques and
reclamation when properly employed can minimize or eliminate the problems
associated with earthmoving.   Impounding mine drainage  for  subsequent evapora-
tion or treatment and proper underground mining methods have been used  to
successfully handle the acid mine drainage problem.  The possibility that a
mining operation will lower nearby well yields or cause small  locally-used
shallow aquifers to be depleted is common to nearly  all coal bearing regions.
     Synthetic fuel plants may produce a number of waste residues that  could
be detrimental to water quality if discharged into surface  waters or if leached
into groundwaters after disposal.  Planning for the  safe disposal of all waste
residues is an important consideration of plant development and  design.  In
all of our plant designs, we have minimized the net  water consumed  and  the
water content of the wet-s-olid residuals generated,  thereby minimizing  the
potential for environmental degradation.
     The water quality of streams can  also be affected  by the  withdrawal of
significant amounts of water to supply the needs of  the conversion  process.
Such withdrawals from the smaller streams reduce the total  flow  available for
dilution of man-made pollutants.  The  potential impact  of this action can be
overcome by augmenting conversion plant supplies to  the fullest  extent possible
with lesser quality water from such sources as treated  municipal or industrial
wastewater effluents or brackish groundwater supplies.
     The major potential impact of the coal mining operation common to nearly
all coal bearing regions is that the mining will disturb existing aquifers and
result in the lowering of nearby well  yields or cause small locally used
aquifers to be depleted.  When a productive aquifer  is  cut by  the mining
operation, ,a large free-surface discharge into the mine may be created which
can significantly lower the hydraulic  gradient, or water table, of the aquifer
in the vicinity of the mine.   This problem is very localized and dependent on
                                        97

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the underlying aquifer structure.  This situation can only be  accurately
assessed on a site by site basis, on a scale much smaller than the present
site definitions allow.
     Another potential impact on groundwater systems is the effect of  large
withdrawal rates for conversion plant supplies.  If these withdrawals  exceed
aquifer recharge or transmissibility rates, they too can lower the local
groundwater table.  Therefore, the feasibility of using groundwater as  a water
supply source must be carefully evaluated based on the ability of the  local
aquifers to supply the required yields without widespread lowering of  the
water table or other impairments of existing users in the area.
     Based on the above considerations a brief qualitative evaluation  of
potential groundwater impacts was conducted for the primary groundwater
supply sites and several other sites where groundwater looks promising  as a
supplemental source.  These assessments are presented in Appendix 13.
Site Specific Summary
     This section presents a general summary of the water resources situation
at the proposed coal conversion plant sites in each state.   Table 4-8  lists
first by state the primary specific sites studied in detail and then the
additional secondary sites investigated in a general sense only.   The water
supply source designated for each site in the coal reserve-water supply matrix
is listed along with a qualitative (good, fair, or poor)  evaluation of the
adequacy of the source.  This assessment is based on a comparison of high
water plant usage with low streamflow conditions and other considerations as
described fully in the earlier text.   Figures 4-2 and 4-3 summarize Table 4-8
in a graphical manner for the Appalachian and Illinois coal regions.
     Alternative sources are suggested where designated sources are not rated
"good",  and the adequacy of these alternatives is rated based on a brief
review of the associated supply condition.   Since groundwater may be considered
as a supplemental or conjunctive supply in many instances,  groundwater avail-
ability  in the vicinity of each site  is rated based on the  general aquifer
                                        98

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TABLE 4-8   WATER AVAILABILITY SUMMARY
Location
Alabama
Primary Sites
Jefferson
Marengo
Secondary Sites
Fayette
Marion
Jackson
DeKalb
Illinois
Primary Sites
Bureau
Fulton
St. Clair
Saline
Shelby
White
Secondary Sites
McLean
Mercer
Designated Adequacy of
Source Source
Coosa R.
Tombigbee R.
Warrior R.
Tennessee R.
Tennessee R.
Tennessee R.
Illinois R.
Groundwater
Mississippi
Saline R.
Kaskaskia R.
Wabash R.
Illinois R.
Mississippi
Good
Fair
Fair
Good
Good
Good
Fair
Good
Very Good
Very Poor
Poor
Good
Fair
Very Good
Alternate Adequacy of Groundwater
Source Alternate Availability
Fair
Groundwater Fair Fair
Groundwater Fair Fair
Fair
Fair
Fair
Groundwater Very Good Very Good
Good
Groundwater Very Good Very Good
Ohio Good Very Poor
Lake Fair Fair
Shelbyville
Fair
Groundwater Fair Fair
Groundwater Very Good Very Good
Recommended
Supply
Coosa
Tombigbee & GW
Augment
Warrior & GW
Tennessee
Tennessee
Tennessee
Groundwater
Groundwater
Mississippi
Ohio R.
Kaskaskia S GW
Wabash
Illinois S GW
Mississippi
Environmental
Impact
Moderate
Significant
Moderate
Minimal
Minimal
Minimal
Moderate
Moderate
Minimal
Significant
Moderate
Moderate
Moderate
Minimal

-------
TABLE 4-8   (continued)
Location
Indiana
Primary Sites
Gibson
Sullivan
Vigo
Warrick
Kentucky
Primary Sites
Floyd
Harlan
Henderson
Muhlenburg
Pike
Secondary Sites
Hopkins
Lawrence
Lee
McCreary
Designated
Source
White R.
Wabash R.
Wabash R.
Ohio R.

Levisa Fork
Cumberland
Ohio R.
Green R.
Levisa Fork
Green R.
Big Sandy R.
Kentucky R.
Cumberland
Adequacy of
Source
Good
Good
Good
Very Good

Very Poor
Very Poor
Very Good
Fair
Very Poor
Fair
Fair
Poor
Poor
Alternate Adequacy of
Source Alternate
Groundwater Fair
Groundwater Good
Groundwater Good
Groundwater Very Good

Unknown -
Surface
-
Groundwater Fair
Unknown
Groundwater Fair
Groundwater
Unknown
L. Cumberland Good
Groundwater
Availability
Fair
Good
Good
Very Good

Very Poor
Very Poor
Good
Fair
Very Poor
Fair
Fair
Poor
Poor
Recommended
Supply
White & GW
Wabash R.
Wabash R.
Ohio R.

Unknown
Unknown
Ohio R.
Green & GW
Unknown
Green & GW
Big Sandy S GW
Unknown
Unknown
Environment a
Impact
Moderate
Moderate
Moderate
Minimal

Significant
Significant
Minimal
Moderate
Significant
_
Moderate
-
-

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TABLE  4-8  (continued)
Location
Ohio
Primary Sites
Galia
Jefferson
Tuscarawas
Secondary Sites
Morgan
Pennsylvania
Primary Sites
Allegheny
Luzerne
Schuylkill
Somerset
Secondary Sites
Venango
Clearf ield
Cambria
Designated
Source
Ohio R.
Ohio R.
Tuscarawas
Muskingum

Allegheny R
Susquehanna
Susquehanna
Casselman R
Allegheny R
West Branch
Conenaugh R
Adequacy of
Source
Very Good
Very Good
Fair
Good

Good
Good
Good
Poor
Good
Fair
Poor
Alternate Adequacy of Groundwater
Source Alternate Availability
Very Good
Very Good
Groundwater Very Good Very Good
Groundwater Very Good Very Good

Good
Good
Good
Quemahoning - Good
Res. (Highly Variable)
Unknown - Fair
Unknown - Fair
Unknown - Poor
Recommended Environmental
Supply Impact
Ohio R.
Ohio R.
Groundwater
Muskingum & GW

Allegheny
Susquehanna
Susquehanna
Casselman & GW
Allegheny
Unknown
Unknown
Minimal
Minimal
Moderate
Moderate

Moderate
Moderate
Moderate
Significant
Moderate
-
_

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                          TABLE 4-8  (continued)
Location
West Virginia
Primary Sites
Fayette
Kanawha
Marshall
Mingo
Monongalia
Designated
Source
New R.
Kanawha R.
Ohio R.
Tug Fork
Monongahela
Adequacy of
Source
Good
Good
Very Good
Poor
Fair
Alternate Adequacy of
Source Alternate

-
-
Groundwater Fair
Groundwater Fair-Good
Groundwater
Availability
Poor
Fair
Good
Fair
Fair-Good
Recommended :
Supply
New
Kanawha
Ohio
Tug & GW
Monongahela &
Environment a
Impact
Moderate
Moderate
Minimal
Moderate
Moderate
Preston

Secondary Sites
Randolph
Greenbrier
Cheat R.
              Poor
Tygart R.     Poor
Greenbrier  Fair-Poor
Groundwater


Unknown
Unknown
                                         Poor
                                                     Poor
Very Poor
Very Poor
                Groundwater
                Unknown
Unknown
Unknown
                   Significant

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                                          SITE LOCATIONS
                                          •  primary sites
                                          osecondary sites
                                     WATER AVAILABILITY
                                                marginal
                                                adequate
       APPALACHIAN COAL REGION
Figure 4-2  Water  availability in the Appalachian  coal  region
                      103

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                                       SITE LOCATIONS
                                           primary sites
                                          secondary sites
                                   WATER AVAILABILITY
                                          SSS^ inadequate
                                          ™ marginal
                                               adequate
                                   KENTUCKY    X

    ILLINOIS  COAL REGION
Figure 4-3.  Water availability in the Illinois coal region.
                   104

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structure in that area.  It must be recognized that actual well yields that
may be realized at a given location, particularly those from fractured
consolidated aquifers in the Appalachian region, are very site dependent.
     Based on the results of the overall investigations conducted, a water
supply source or combination of sources is suggested that would appear to best
meet the water supply needs at each site.  The originally designated sources
are used for this purpose to the fullest extent feasible.  This evaluation is
based on water supply considerations only accounting for the required reasonable
sharing of available supplies, but not considering the many other institutional
(such as the non-riparian use restriction), political or environmental consid-
erations that may enter into the final selection of the water supply makeup at
a particular location.  Some indication of the likelihood of environmental
impacts at a specific site is given in the last column.  This is a qualitative
assessment of potential environmental impacts based on the factors discussed
earlier and the general area of the site.  It must be emphasized that actual
environmental effects associated with coal mining and conversion are very
site and design/operation dependent, and cannot be reliably evaluated without
specific site and design data.
4.3  Western Region
     The water resources in the major coal and oil shale bearing regions of the
Western United States can be conveniently separated for consideration into two
major watershed regions, shown in Figure 3.5; the Upper Missouri River Basin
and the Upper Colorado River Basin,
     The vast Fort Union and Powder River coal formations cover large areas of
the states of Wyoming, Montana and North Dakota in the Upper Missouri River
Basin.  Other significant coal and oil shale deposits are situated in the Upper
Colorado River Basin in the states of Wyoming, Colorado, Utah and New Mexico,
Table 4-9 presents a list of 32 specific site locations that were selected for
study based on their proximity to readily developable energy reserves.  This
list covers more sites than the one given in Table 3-12 and provides a larger
study area with regards to water availability.  The locations of these sites
with respect to the major coal and oil shale reserves and the primary water resources
characteristics are shown in Figure 3.5.
                                         104a

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           TABLE  4-9 PLANT SITE LOCATIONS IN THE WESTERN STUDY REGION
State
               Mine
                     County
Upper Missouri River Basin
Wyoming
Montana
 North Dakota
Gillette            Campbell
Spotted Horse       Campbell
Belle Ayr           Campbell
Antelope Creek      Converse
Lake de Smet-Banner Johnson
Hannah Coal Field   Carbon
 Decker
 Otter Creek
 Pumpkin  Crrek
 Moorhead
 Foster Creek
 U.S. Steel-Chupp
 Coalridge
 Colstrip

 Slope
 Dickenson
 Bently
 Scranton
 Williston
 Knife River
 Underwood
 Center
  Deposit
Subbituminous
Subbi tuminous
Subbituminous
Subbituminous
Subbituminous
Subbituminous
       Hydrologic
       Sub-Region
Belle Fourche-Cheyenne
Powder
Belle Fourche-Cheyenne
Belle Fourche-Cheyenne
Powder
North Platte
 Upper Colorado River Basin
Wyoming
Colorado


Utah

New Mexico
Kemmerer
Jim Bridger
Rainbow #8
Tract W-a/W-b

Tract C-a/C-b
Colony Development

Tract U-a/U-b

El Paso
Wesco
Gallup
Big Horn
Powder River
Powder River
Powder River
Powder River
Daws on
Sheridan
Rosebud
Slope
Stark
Hettinger
Bowman
Williams
Mercer
McLean
Oliver
Lincoln
Sweetwater
Sweetwater
Sweetwater
Rio Blanco
Garfield
Unitah
San Juan
San Juan
McKinley
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Subbi tuminous
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Bituminous
Subbituminous
Bituminous
Oil Shale
Oil Shale
Oil Shale
Oil Shale
Subbituminous
Subbituminous
Subbituminous
Tongue-Rosebud
Tongue-Rosebud
Tongue-Rosebud
Powder
Tongue-Rosebud
Missouri Mainstem
Missour Mainstem
Tongue-Rosebud
Heart-Cannonball
Heart-Cannonball
Heart-Cannonball
Heart-Cannonball
Missouri Mainstem
Missouri Mainstem
Missouri Mainstem
Missouri Mainstem
Upper Green
Upper Green
Upper Green
Upper Green
Lower Green
Upper Colorado
Lower Green
San Juan
San Juan
San Juan
                                     104b

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     The Upper Missouri River Basin, on the eastern slopes of the Rocky Mountains,
has two major sub-regions with respect to climate.  The mountainous regions  of
western Montana and central Wyoming receive annual rainfalls of up to 40
inches and generate most of the runoff within the basin.  Much of the remainder
of the basin has the characteristic flat terrain of the northern Great Plains.
This area has a semi-arid climate and annual precipitation ranging from about
               9
12 to 24 inches .  Throughout the basin most of the precipitation occurs as
snowfall during the winter as a result of orographic cooling of the prevailing
westerly air flow.  The result is that most of the annual runoff occurs in
late spring as the mountain snowpack melts.  This serves to create short
periods of high streamflows and to recharge 'the alluvial groundwater system.
From late summer through winter there is very little natural surface runoff.
Annual open surface evaporation rates range from about 28 inches at the higher
                                           9
elevations to about 44 inches on the plains .
     The Upper Colorado River Basin covers a region on the western slope of
the Continental Divide that is located further to the south than the Missouri
Basin.  Although the Colorado River Basin has a somewhat more arid climate due
to its more southerly position and because much of the basin does not benefit
from the orographic precipitation caused by the Rockies, the seasonal distribu-
tion of overall precipitation is similar to that in the Upper Missouri Basin.
Throughout the basin annual precipitation varies from lows of about 8 inches
at numerous locations in the Basin to a maximum of about 40 inches at higher
                                           9
elevations in portions of northeastern Utah . Most of the annual surface
runoff results from melting mountain snowpacks in the spring with much lower
flows occurring over the remainder of the year,,  Annual evaporation rates over
most of the Basin are quite high, ranging from about 32 inches to about 54
inches .
     The geographic variability of the climate is an important aspect of the
assessment of potential water supplies for use in energy development.  As
indicated above, this variability indirectly affects the seasonal distribution
of water supplies throughout most of the study area.  Evaporation is also a
vital parameter to the water resources of the region since it affects two of
the most significant water uses - irrigation requirements and reservoir
evaporation losses.

                                      105

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     In the West the adequacy of a water supply is dependent on several
factors including the average quantity of water available at the  intended
source; the variability of the supply over time; the manner in which  the water
is used or committed to use through a prior appropriation; and the  environ-
mental and social implications involved in altering the hydrologic  region.
The Appropriate Doctrine is the code by which water is administered in the
Western states of concern.  In this system water rights are given priorities
dependent on the seniority of the right and independently  of  the  location of
the water use with respect to its source.  Generally the only requirement
regarding the use of water once a water right is confirmed is the need to put
the water to "beneficial use", the definition of which is  usually very loosely
held.  Water rights are considered to be property  and can  be  bought and sold
as such.  On a subregional basis total average annual water yields  generally
greatly exceed actual use.  In many cases, however, legally recognized rights
to use water exceed the available supplies during  low flow periods.  Supplying
water  for future energy use in many of these cases will require  implementation
of one or more of the following developments:
     1.  Additional storage facilities to more evenly distribute  the available
supplies over the year and from wet to dry years.
     2.  Importation of surplus supplies from regions with more  abundant water
yields.
     3.  Transfer of water use to the industrial sector by the purchase of
existing agricultural water rights and state approval of changes  in water use.
Surface Water Resources
     Upper Missouri River Basin
     The Upper Missouri River Basin may be divided into several  hydrologic
subbasins of interest with respect to water availability for  energy develop-
ment.  As shown on Figure 4-4, these study regions are:
     1.  Upper Missouri River Mainstern (Montana, North Dakota)
     2.  Yellowstone River Mainstem (Wyoming, Montana)
     3.  Powder River Basin (Wyoming,  Montana)
     4.  Tongue-Rosebud Basins (Wyoming,  Montana)
     5.  Heart-Cannonball Basins (North Dakota)
     6.  Bell Fourche-Cheyenne Basins  (Wyoming)
     7.  North Platte Basin (Wyoming)
                                      106

-------
            I          ft
                                /TONGUE-
                               /ROSEBUDl
               YELLOWSTONE  RIVER   feASINS
                              r    / i
           WYOMING
V-~,
L_.
                         .J-"     \._
                                        OCYE^NE BASMVS   SOUTH  DAKOTO
                            )
MCWTM PLATTt
   BASIK
Figure 4-4  Subbasin boundaries - Upper Missouri Basin

-------
     This section discusses these subregions  with respect to the total surface
water resources generated within the  regions  that is  available to all users.
     Most of the annual runoff produced  in  the  Upper  Missouri Basin originates
in  the mountainous headwaters of the  Yellowstone  and  Missouri subregions in
western Montana and Wyoming.  The Yellowstone River Basin is of special interest
in  this study because much of the most easily retrievable coal is located
within its  drainage divides, making it a likely source of supply for future
development.  The Yellowstone Basin covers  a  drainage area of about 70,000
square miles which is divided nearly  equally  between  Montana and Wyoming, and
joins  the Missouri River just east of the Montana-North Dakota border.  At
their  confluence the Yellowstone yields  an  annual flow of about 9.5 million
 acre-ft/yr  which is  22 percent more average flow than the Missouri, although
 it drains  14 percent  less  area.  The  Yellowstone  River receives more than one-
half of  its total yield from waters rising  in the mountain ranges upstream of
Billings, Montana.  The majority of the  remaining yield is from the Wind-
Bighorn  River Basin  in north-central  Wyoming.
      The hydrologic  characteristics vary within the Upper Missouri Basin,
primarily between the mountain and plains regions.  Water yield from the high
mountain region in the western basin  ranges to  over 20 inches per year, while
the semi-arid plains  covering much of the basin contribute less than one inch
of  runoff.  The total water yields on a  subregional basis are shown in Table
4-10.
        TABLE  4-10   AVERAGE ANNUAL WATER YIELD -  UPPER MISSOURI RIVER BASIN
          Subbasin
Tongue-Rosebud
Powder
Yellowstone Mainstem
Belle Fourche-Cheyenne
   (Wyoming only)
Heart-Cannonball
Upper Missouri Mainstem
   (At Oahe Dam)
North Platte
   (Colorado & Wyoming only)
Drainage
Area
(sq. mi. )
6,660
13,420
50,040
11,000
7,620
185,840
Average
Water Yield
in Sub-Region
(AF/year)
467,000
501,900
10,488,100
182,400
337,500
23,625,000
26,660
1,223,100
   Average
    Area
    Yield
(AF/year/sq.mi.)
      70
      37
     210

      17
      44
     127

      46
                                      108

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     Table 4-11 gives the recorded surface runoff characteristics of some
rivers in the Upper Missouri Basin (Figure 4.5) at selected points.  The
average discharge is the discharge averaged over the period of record while
the maximum arid minimum discharges are the instantaneous daily extremes.
Runoff is an indicator of a region's water resources, but it should not be
used alone as a measure of water sufficiency.  Taking a conservative (high)
estimate of average water use in a typical mine-plant complex to be 10 ft /sec
(6.5x10  gal/day) then Table 4-11 shows that the Missouri, Yellowstone and
Bighorn Rivers even at minimum discharge have sufficient capacity under present
conditions to support a number of standard size synthetic fuel plants.   As in
many parts of the West, some of the river flows of the smaller tributaries are
highly variable, even with regulation of some of the rivers.
  TABLE 4-11  RECORDED SURFACE RUNOFF CHARACTERISTICS IN CUBIC FEET PER SECOND
           OF RIVERS AT SELECTED POINTS IN THE UPPER MISSOURI BASIN
               River and Location
Missouri, near Culbertson, Montana
Yellowstone, near Sidney, Montana
Little Missouri, at Marmarth, North Dakota
Knife, near Hazen, North Dakota
Cannonball, near Breien, North Dakota
Yellowstone, at Miles City, Montana
Yellowstone, at Billings, Montana
Tongue, at Miles City, Montana
Bighorn, at Bighorn, Montana*
Powder, at Arvada, Wyoming
 Average    Maximum    Minimum
Discharge  Discharge  Discharge
10,330
13,030
343
183
247
11,330
6,858
423
3,851
272
78,200
159,000
45,000
35,300
94,800
96,300
66,100
13,300
26,200
100,000
575
470
0
0
0
966
430
0
275
0
*Regulated by storage facilities.

     The seasonal distribution of runoff also varies throughout the Basin with
most of the annual runoff occurring in the spring and early  summer due  to the
                                        109

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Figure 4-5   Major rivers in the Upper Missouri River Basin

-------
melting of the accumulated snowpack.  The largest variation in flow  is
evidenced in streams in the plains  regions where very high flows are  typically
experienced over a short spring melt season, but where flows often diminish  to
zero at times during the year because of depletions and  little rainfall.
Because of this seasonal variability numerous storage reservoirs have been
built over the years to retain the  spring runoff for use during the  remainder
of the year.  This has been particularly important to the development of the
region's agricultural base, since the controls make far more water available
for irrigation during the growing season than would be available under natural
flow conditions.
     Within the Yellowstone River portion of the Basin, the reservoirs are
located primarily on the tributaries in northern Wyoming and southeastern
Montana.  The mainstem of the Yellowstone is presently unregulated and is
valued as one of the few remaining  major free-flowing rivers in the West.  It
is doubtful if any future impoundments on the mainstem would be allowed.
     The Missouri River mainstem major coal reserve region is highly regulated
by a series of large, multi-purpose reservoirs built and operated by the
Bureau of Reclamation and the U.S.  Army Corps of Engineers.  These are as
follows:
          Reservoir           Location            Active Storage
          Fort Peck           Montana             10,900,000 AF
          Lake Sakakawea      North Dakota        13,400,000 AF
          Oahe                North and
                              South Dakota        13,700,000 AF
These reservoirs form the basis for a reliable and abundant water supply to
serve a variety of energy development activities in northeastern Montana and
along the mainstem in North Dakota.
     Upper Colorado River Basin
     The Upper Colorado River Basin may also be divided into several hydrologic
subbasins with respect to water availability.  As shown in Figure 4-6, these
study regions are:
                                      111

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        UJWER
        COLORADO
        MAINSTEM
       ARIZONA
Figure 4-6   Subbasin boundaries - Upper  Colorado River Basin
                           112

-------
     1.  Upper Green River (primarily Wyoming)
     2.  Lower Green River (Colorado and Utah)
     3.  Upper Colorado Mainstem (Colorado and Utah)
     4.  Lower Colorado Mainstem (primarily Utah)
     5,  San Juan River (Colorado, New Mexico, Utah and Arizona)
     Most of the annual runoff produced in the Upper Colorado River originates
in the western slope mountain headwaters of the Basin in Colorado.  The main-
stem of the Colorado River and two of its major tributaries, the Green River
and the San Juan River, drain portions of the.headwaters, but the Colorado
produces by far the most runoff.  Although the Green River Basin drains about
44,000 square miles or about 70 percent more area than the Colorado River
above their junction, the Colorado yields about 25 percent more water.  Much
of the remainder of the Basin at lower elevations has an arid to semi-arid
climate and produces very little additional yield.  Water yields range to over
20 inches in the high mountain regions, but less than 0.5 inches over most of
the Basin (Figure 4~7).  The total water yields on a subregional basis are
shown in Table 4-12.

       TABLE 4-12  AVERAGE ANNUAL WATER YIELD - UPPER COLORADO RIVER BASIN
                                                Average           Average
                                 Drainage     Water Yield          Area
                                   Area      in Sub-Region         Yield
          Subbasin               (sq. mi.)      (AF/year)        (AF/year/sq.mi.)
          Upper Green              14,300     1,926,000             135
          Lower Green              29,700     3,534,000             119
          Upper Mainstem           26,000     6,838,000             263
          Lower Mainstem           20,500       451,000              22
          San Juan                 23,000     2,387,000             104


     The principal rivers and tributaries in the Upper Colorado River Basin are
shown in Figure 4-7 with the recorded surface runoff characteristics of some
                                      113

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     UPPER GREEN
                                 1 1  TO 10 INCHES ANNUAL RUNOFF
                                 .j



                               11} OVER 10 INCHES ANNUAL RUNOFF
Figure 4-7  Major rivers and runoff producing areas


        in the Upper Colorado River Basin
                        114

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rivers at selected points in the region given in Table 4-13.  As mentioned
previously, the river flows are highly variable even with regulation  of  some
of the rivers.  The flow of the San Juan  River is  stabilized by the Navajo
Reservoir with a capacity of over  1.7x10   acre-ft  (0.55x10  gal).

  TABLE 4-13  RECORDED SURFACE RUNOFF CHARACTERISTICS IN CUBIC FEET PER  SECOND
         OF RIVERS AT SELECTED POINTS IN  THE UPPER COLORADO RIVER BASIN
                                                     Average   Maximum   Minimum
                 River and Location                 Discharge Discharge  Discharge
Colorado River, at Hot Sulphur Springs, Colorado         201     2,500        44
Colorado River, near Colorado-Utah State  Line           5,345    33,000     1,570
Gunnison River, near Grand Junction, Colorado           2,072    12,000      500
Green River, near Green River, Wyoming                  1,584    10,900      245
Green River, at Green River, Utah                       5,811    29,500     1,180
Yampa River, at Steamboat Springs, Colorado              421     4,080        45
White River, near Meeker, Colorado                      540     4,010        25
San Juan, at Farmington, New Mexico                     2,425    68,000        14
Animas, at Farmington, New Mexico                        922    25,000        1
San Juan, near Carracas, Colorado                        605     9,730        5

     The seasonal variability of runoff is also a  very  significant aspect  of
the overall water resources situation in the basin.  Most of the annual runoff
occurs during the late spring as a result of melting snow.  During the remainder
of the year most of the smaller tributary streams  receive little additional
rainfall input and flows frequently diminish to zero.   Because agriculture has
long been an important part of the region's economy, water resources develop-
ments have been developed over the years  to more evenly distribute the excess
spring runoff over the year, particularly during the growing season.  These
developments include storage reservoirs,  flow diversions and a variety of
irrigation works.  The result is that the Colorado River System has become
one of the most highly regulated river systems in  the country.
     The major storage reservoirs  in the  Upper Colorado Basin are the
following:
                                        115

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          Reservoir                Location             Active  Storage
         Fontenelle      Green River, Wyoming              190,000 AF
         Flaming Gorge   Green River, Wyoming-Utah       3,749,000 AF
         Blue Mesa       Gunnison River, Colorado          830,000 AF
         Navajo          San  Juan River, New Mexico      1,696,000 AF
         Lake Powell     Colorado River, Utah-Arizona   25,002,000 AF

 Although these  facilities  and a number of  significant  flow diversions  make
 more water  available  along the major  interstate  rivers than can presently be
 used, a specific  set  of legal considerations govern  how the water may  be used.
      Water  quality  is a more  significant issue in the  Upper Colorado River
 Basin than  in the Upper Missouri Basin.  Although the  water in the upper
 reaches of  the  major  streams  is of high quality, the quality deteriorates as
 the water moves downstream.  By far  the most significant water quality
 concern in  the  Basin  is salinity affecting agricultural usage.   Surface water
 quality in  the  Upper  Colorado Basin  will be an important consideration for
 future energy development  for two reasons.  The  presence of high concentrations
 of certain  salts  may  be a  factor affecting the feasibility of using various
 sources as  a water  supply  for energy  conversion, and therefore may be  a
 siting consideration.   At  the same time, the consumption of high quality
 supplies in the upper Basin region may reduce the dilution water available and
 therefore increase  salinity downstream.
 Groundwater Resources
      Groundwater is an  important but  often  overlooked  water supply source
 throughout  much of the  coal region of the  West.  It  is estimated that  there is
 approximately 120 million  acre-ft of  water  stored in natural underground
 reservoirs  at depths within only 200  feet  of the surface.   This volume is
 several  times the storage  capacity of all  of the surface reservoirs in the
 region,  yet present groundwater usage accounts  for  only a relatively  small
percentage  of total water  use.  The reasons for  this are varied,  but include:
the costs to locate and develop groundwater supplies,  poor groundwater quality
in some  areas, and the preference of  certain users to  utilize  surface  supplies.
However, groundwater supplies may have certain advantages  over surface supplies
                                        116

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in that it is often more widely distributed and more dependable throughout  the
year.  As competition for available surface supplies increases in the  future,
it is anticipated that groundwater will play a larger role in the overall
water supply picture in the West.
     Groundwater aquifers in the study area fall into two general categories.
Shallow aquifers consist of coalbeds, sandstones and the unconsolidated allu-
vium along major rivers and the principal tributaries in buried preglacial
valleys.  Deeper strata of limestone and associated carbonate rocks have also
shown promise as potential water supply sources, particularly in the northern
Great Plains region.  General areas underlain by aquifers capable of well
yields of 50 gpm or more are shown in Figure  4-8.
     Shallow aquifers are present throughout much of the Upper Missouri Basin
except in the Bighorn Mountains and Black Hills, where the older Madison
Limestone and associated carbonate rocks are exposed.  These aquifers  generally
vary in depth from the surface to a few thousand feet.  Most existing  wells
are less than about 300 feet deep although some alluvial wells less than 100
feet deep yield as much as 500 gpm.  Most present shallow aquifer wells yield
less than 50 gpm, but this appears to be a limitation related to typical water
requirements rather than the capacities of the aquifers.  Available data
indicates that the sandstone units and associated coal beds in the Fox Hills-
Hell Creek-Fort Union-Wasatch sequence may yield up to 500 gpm in appropriately
constructed individual wells.
     The Madison aquifer underlies most of the northern Great Plains coal
region except for the Bighorn, Pryor and Snowy mountains and the Black Hills
where it is exposed or absent.  Varying in depth from about 5000 feet  in the
coal region of Montana to about 10,000 feet in portions of the Powder  River
Basin in Wyoming, this aquifer has produced a few wells yielding up to several
thousand gallons per minute.  However, yields are highly variable and  since
the cost involved in tapping this source is so great, data on the potential of
the Madison is presently quite limited.
     The aquifers that underlie the Upper Colorado River region consist mostly
of consolidated and semi-consolidated sedimentary strata with unconsolidated
alluvial deposits along reaches of major stream valleys.  It has been  estimated
that the volume of recoverable groundwater within 200 feet of the surface is
about SS million acre-ft which is nearlv three times the active storaae in  all
                                      117

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                                                                       EXPLANATION
                                                               Ouontity generolly ovoiloble p.r
                                                                 well, in golloru per minutt
                                                                       SUBREGION

                                                                I. Upper Missouri River Iribuloriei

                                                                2. Yellowstone River

                                                                3.Western Dokoto Iributoriei

                                                                A.North Plotle-Niobroro Riverj

                                                                5.South Plolle - Arikoree Riverj
                                                                    so  100  150. 200  jso K
      I	
     WESTERN  MISSOURI  RIVER  BASIN
Figure 4-8   Groundwater  supply  availability  (from Ref.26)   (continued)
                                   118

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                                                 EXPLANATION

                                        Ouontity  generolly  ovoiloble per
                                          wall, in gollons p»r minute


                                                   Less  them 50


                                                   More  thon 50


                                         	•	Subregion boundory
         ronttriftle
          Reservoir
               Fleming Gorge
               Reservoir
                Wyoming^
                        "Colorodo
                      RIVER

                                   Ft
       River  <-^ Dinosour  Notionol
                Molnument
                     SUBREGIOfi—.
                               /     '
                               6°
                                        G le n wood
                          {£/^        Springs
                              UPPER
                                    Blue Mesa
                                    Reservoir
                               STEM

                            SUBREGION

                                r
 Uto n
Ariz ono
Colorado
New Mm
      SAN JUAN-: COLORADO    Nova,a
             SUBREGION
0
1
I 	
0
1
1
50
50
1 t
100
100 MILES
i
i
150 KILOMETRES
                                       UPPER COLOPADO RIVER  BASIN
  Figure 4-8  (concluded).
                      118a

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of the surface reservoirs in the Colorado River system and that the amount
stored in the deeper rocks is several times that within the initial 200  feet
zone.  It is also estimated that about 4 million acre-ft of groundwater
recharge occurs annually from rainfall, principally in the higher mountains
and plateaus where rainfall is the highest.
     Although the total volume of recoverable groundwater storage is great,
the water cannot always be obtained at the desired rates in all places.  About
85 percent of the stored groundwater occurs in sedimentary rocks which have
relatively low permeability and yield water slowly.  Wells yielding more than
50 gpm generally can be expected only in areas consisting of permeable
alluvium which accounts for only about 5 percent of the groundwater reserves.
     An area that has received specific attention with respect to the
availability and impacts of groundwater use for oil shale mining is the
Piceance Basin in Colorado.   Significant quantities of groundwater are believed
to be available in this Basin.   Estimates of the volume of water in storage in
the deep aquifers in the Piceance Creek Basin range from 2.5x10  to 25x10
acre-feet  '  .  Groundwater is also available from shallower alluvial aquifers
that are much smaller in areal extent than the deep aquifers.  Recharge to the
aquifers occurs mainly as a result of snow melt along the margins of the
basin.  Groundwater flows from the margins of the basin to the central part of
the basin  .  The surface water and ground water systems are hydraulically
connected so that if a large quantity of groundwater is withdrawn from an
aquifer, flow in the neighboring streams could be decreased or possibly
reduced to zero.
Water Use Doctrines
     In most of the Western states the Appropriation Doctrine governs the use
of water.  It is based on the principle that a senior right has diversion
priority over a junior right, i.e.  in times of limited water availability, the
senior diversion right can be completely satisfied before any diversion for
the junior right is permitted.   This doctrine encourages the beneficial use of
water often at the expense of satisfactory streamflow conditions and was
                                     119

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 established to assure the  senior  appropriator that he has a reliable supply of
 water  insofar as no other  water user  is permitted to take any action which
 could  in any way injure  the  senior  appropriator.   Thus, water is often
 regarded as a property right in and of itself.   Junior water rights are, in
 most cases, also protected against  injury  from any manipulation or change in
 use of senior water rights,  as they are generally entitled to the maintenance
 of stream conditions  as  they existed  when  the junior appropriation was granted.
      Typically, each  state has a  water administration system with character-
 istics distinct from  those in the other western states.  A characteristic
 common to all of the  systems of the states under consideration include some
 degree of appropriation  doctrine, a system designed primarily to encourage the
 efficient beneficial  use of  water,  in an economic sense, while at the same
 time minimizing conflicts  with other  water users.   This system permits and in
 many cases requires,  the diversion  of water from a stream bed or watercourse
 to establish a water  right.   Recently, though,  the administrative procedures
 have been changed  in  several of the states regarding instream appropriations
 of water; these have  been  instituted  primarily  for the purpose of minimizing
 environmental degradation, e.g.,  maintaining a  minimum stream-flow for fish
 life and recreational purposes.
     The procedures by which water  rights  can be  transferred in title, manner
 of use,  and place  of  use vary widely  from  state to state.  In some states,
 irrigation water is tied to  the land  upon  which it is used and can be trans-
 ferred only with somewhat  greater effort than in  those systems in which it is
 recognized that the water  is  indeed separable from the land.   In all cases,
 however,  the prevention  of adverse  effects  of the  transfer of other water
 uses,  junior and senior,  is  of paramount importance.   In fact in most cases
 this is the only restriction  on transfer of  water  on an individual basis.  It
 is typically the case, however,  that  the burden of proof lies upon those
wishing to effect  the transfer,  whether the  change must be adjudicated or
approved by an  administrator.
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     Development of storage rights is generally encouraged  in the  area  of
interest by water administration systems.  Again, they are  permitted only when
other water users are not materially injured, or when they  can be  induced to
withdraw objection to the project.  In general, temporal  aspects  (e.g.,  time
of year in which water is used) play a large role in the  value of  the right.
Consequently, water storage plays a correspondingly large role in  the transfer
of water rights.  For instance, when an irrigation right  which is  used,  in the
period May-October each year is transferred to an industrial use which  requires
a year-round water supply, some storage must be used, even  when the total
annual volume of the industrial use is equal to or less than that  of the
irrigation use.  This is done primarily to ensure that the  hydrologic regime
of the river does not change as a result of the change in use and  harm  a
junior appropriator by causing water which was formerly available  to him to
become unavailable.
     Trans-basin diversions can be handled in many ways as  simply  as a
conventional change in use and location.  However, the consequences of  trans-
basin diversions tend to have somewhat greater impact on  the hydrologic
regimes of rivers; hence,  the political  and  environmental aspects  of  trans-
basin diversion are much more complicated.    This is largely a result  of the
interstate compacts which exist on most of the major interstate rivers.  These
compacts are discussed individually in Appendix 14.  Generally, the interstate
compacts tend to come about only after conflicts between  the states arise
concerning the flows.  Since they are a result of tensions  between the  states,
the states watch closely to ensure that they do not get shortchanged by  other
states.  Consequently, interstate compacts affecting trans-basin diversions
must satisfy very stringent conditions.  For example, one potential problem
lies in the lack of any compact or agreement between the  states of Colorado
and Utah concerning the use of water of the White River.  Commonly regarded  as
one of the most likely sources of water for oil shale development, the  absence
of any agreement on the disposition of White River water  almost guarantees an
                                       121

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eventual clash between the states of Colorado and Utah when an attempt  is  made
in either state to put a large amount of water to use.  Currently  the river
remains largely undeveloped.
     Groundwater is another resource subject to a variety of differing
administrative policies in different states and regions.  In most  states
permits from the statewide administrative agency are required.  Typically, one
of the main requirements has been that of not adversely affecting  the
groundwater situation of adjoining landowners.  In most cases the  deep, non-
alluvial aquifers with limited recharge capabilities may only be "mined" at a
rate usually set by the state administrator responsible for such matters.
     Frequently the administration and regulation of groundwater activities is
handled by the same state agencies which administer the surface waters.
Although the history of groundwater management is relatively short,  signifi-
cant changes have been made in several states in the recent past.  They have
moved primarily in the direction of recognizing the hydraulic connections
between surface water and tributary groundwater sources.  Thus, increasing
interaction is taking place between the surface water management systems and
the groundwater management systems.
     An important factor in the consideration of the water supply  possibilities
in the area lies in the claims of the Federal Government for its reservations
of different types.  As discussed below the Reserved Rights Doctrine allows
the federal government to reserve sufficient water for whatever use  is  made of
federally reserved lands, which include Indian Reservations and Bureau  of  Land
Management land among other types.   Consequently, there has been considerable
litigation to force the Federal Government to quantify these claims  and
file for them through the State Water Administrations.
     Federal Reserved Rights are based upon the notion that sufficient  water
from adjoining watercourses was reserved for whatever use the Federal lands
should be put to when the land was claimed by the Federal Government.   Since
many of these lands were put aside before private water development  took
                                       122

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place, the priority of the Federally reserved water  is better  than  the  other
water rights on the river.  Generally, this concept  has been tested in  the
courts and firmly upheld.  The problem associated with the Federally reserved
water rights is that they have not been quantified or even identified,
resulting in uncertainty in the past by other water  users.  Because the Indian
Reservations fall into this category, and because they are the Federally
reserved lands most likely to be developed, much of  the concern has focused
upon them - hence the proliferation of court cases concerning  them.   There has
been no resolution of this problem and the uncertainty may well drag on for
several years.
     Another consideration of Federal water policy is the development of the
Wild and Scenic Rivers in the region of concern.  When a river is designated
as wild or scenic, development along the river is severely restricted in order
to maintain the desirable condition of the river.  Among the rivers being
considered for designation are parts of the Yellowstone, Missouri,  Green,
Yampa and Colorado in the study area.
Competing Water Uses
     An important consideration in assessing water availability is  how  other
alternative uses will compete for the available water of any particular supply
source.  In this section we will consider the present use of water  in each of
the various regions of interest, discuss the factors that may  lead  to changes
in the demand structure and then consider a number of potential future  demand
scenarios.
     An important aspect of any discussion of present or future water use  in
the arid western regions considered here is that the limited geographical  and
seasonal distribution of water supplies has greatly  affected the develop-
ment of these regions and how water is used.  Most of the water supply
generated in the region as a whole occurs as winter  snowfall at higher  eleva-
tions in the upper watersheds.  Melting of the extensive mountain snowpeaks
                                      123

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results in high rates of spring  stream runoff and groundwater recharge, but
throughout much of the  summer  and  fall seasons,  very little additional runoff
is produced.  This leaves  large  portions of the  region with very little water
throughout much of the  year  except along the major streams.  Since most poten-
tial  water users require a steady  and reliable supply, most of the region's
development  has occurred where natural supplies  are most reliable or where
man-made  control projects  have improved the seasonable variability of supplies
to  an acceptable level.
      Historically the primary  use  of water throughout the region has been for
a variety of agricultural  uses.  Since the growing season extends over much
of  the dry  summer period,  continuing water resources developments have been
 directed  at storage  impoundments which more evenly distribute the spring runoff
 throughout  the year.  Even though  the reservoir  evaporation losses associated
 with this may represent a  substantial depletion, the total value of the annual
 runoff is increased  since  more summer water is available at a substantially
 higher value per unit than spring  water.  Many reservoirs have been built and
 are operating throughout the West  for this purpose.  As water from these
 sources has become available in  any given area,  the demand for the relatively
 inexpensive water generally  increases.  This is  an indication of the fact that
 the level of various alternative water uses is highly dependent on the
reliability of the supply  as well  as its economic cost.
      The  use of water for  agricultural purposes  which consists primarily of
the irrigation of cropland or  pasture is by far  the largest water use in the
West, accounting for an average  of 70-80 percent of total present depletions.
This  depletion in most  cases represents only a portion of the water actually
withdrawn from a source and  applied to the cropland.   The net depletion of
irrigation water comes about from  evaporation or transpiration losses, seepage
into  the deep groundwater  system and water incorporated into growing plants.
Multiple reuse of irrigation water has resulted  in adverse water quality
impacts through the accumulation of dissolved salts that are particularly
severe in the Southwestern states.
      An extensive system of  reservoir storage has been developed through-
out the West to more uniformly distribute the spring runoff
over the year and  particularly through the  growing season.   These reservoirs
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often serve multipurpose functions including irrigation,  flood control, power
generation, municipal and industrial supplies and recreation.  Although these
developments make far more water available for use when the water is most
valuable, on an annual basis the large water surface areas associated with the
reservoirs result in substantial water depletions through evaporation.
     It has been increasingly recognized during recent years that maintaining
streamflows above certain minimum levels that vary according to season is
necessary to preserve the habitat for fish and stream-related wildlife.
Free-flowing streams also create opportunities for recreation and increase
environmental quality in several ways.
     For the most part, however, the appropriate water laws in effect in the
Western states are weak or lacking in provisions that would insure minimum
sustained streamflows.  Under present laws streamflows can be and in many
cases are appropriated to a level that exceeds the available water supply.
A result of this is that theoretically streams can be completely depleted
and have no remaining flow during dry months or years.  This obviously has
serious impacts on local fish and wildlife populations.
     Several states presently recognize minimum flows for maintaining fish and
wildlife as a beneficial use and, therefore, a use that can be specifically
reserved in its own right.  Other states are contemplating similar legislation,
Studies to more adequately establish the minimum flow regime needed to sustain
given stream ecosystem without  appreciable degradation will be required as a
part of the development and perfection of future instream flow appropriations.
In many cases the result may be instream flow requirements that are a major
portion of existing low flows.
     The sparse population throughout most of the study region results in
municipal and industrial water  demand sectors being very  low by comparison
with the agricultural sector.   Domestic and industrial users supplied by
municipal systems are frequently considered together under the category of
Municipal and Industrial  (M&I).   On the whole, M&I use presently accounts
for less than 5% of overall water use and an even smaller fraction of total
depletions.
     Self supplied industrial users are generally considered separately.
The major industrial uses in this category are the mining and minerals
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 industry which uses water primarily in the cleaning  and processing of ores
 and  the power industry which uses water in thermal steam-electric power
 plants for cooling.  These major industries as well  as  many other less
 significant water users generally fully deplete their water withdrawals because
 any  wastewater produced would be detrimental to the  environment if returned to
 the  streams.
      Upper Missouri River Basin
      Water use in the Upper Missouri Basin is committed largely to agricultural
 purposes.  It has been estimated that fully 80 percent  of present use goes
 towards  crop or  range irrigation and related uses.   Development of the region
 in fact  has depended on reliable water supplies and  as  such has occurred mostly
 along the  interstate rivers and their major tributaries.   Good water avail-
 ability  in western Montana and the  Upper  Yellowstone Basin in north central
 Wyoming  and  south  central Montana has led to the  development of numerous
 irrigation projects and associated  water  control  facilities such as reservoirs,
 irrigation channels and distribution systems.  Most  of  the population centers,
 power generation facilities, and other industrial development are also located
 in these regions.  Much more limited water supplies  are available for develop-
 ment in  the plains regions of eastern Montana and Wyoming and western North
 Dakota,  and as a result, these regions have been  developed to a far lesser
 extent.
      The way water is presently being used in this region is largely determined
 by legal considerations as to the right to use the water.   This is particularly
 true in  the portions of the Yellowstone River Basin  and the Belle Fourche-
 Cheyenne Basins  where some of the most easily retrievable coal reserves are
 located, but where water  at  times  is  already  in very short supply.  Within each of the
 major tributaries, various interstate compacts define how much of the available
 supplies may be  used within each state, allowing  for reservations recognized
 prior to the compact dates.   Each state's share then is allocated according to
 existing appropriative rights.
     The way in which water is presently being used in the  Upper Missouri coal
 regions is shown in Table 4-14.   The water use values given here are for total
 depletions of the water supplies.   Irrigation and municipal use generally
would involve  larger  actual withdrawals with return  flows  to  the waterways,  and
hence reuse.   Industrial  and reservoir evaporation involve  full depletion of

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              TABLE 4-14  WATER USE - UPPER MISSOURI RIVER BASIN

Subbasin
Present Use
Tongue-Rosebud
Powder
Yellowstone Mainstem
Belle Fourche-Cheyenne
(Wyoming only)
Heart-Cannonball
Upper Missouri Mainstem
(To Oahe Dam)
North Platte
(Wyoming only)
Projected Future Use (Year 2000)
Tongue- Rosebud
Powder
Yellowstone Mainstem
Belle Fourche-Cheyenne
(Wyoming only)
Heart-Cannonball

Irrigation
187,200
181,600
1,561,200
6,000
24,300
1,335,300

574,000
238,000
285,000
1,785,000
7,000
61,000
MSI and
Rural
Domestic
5,000
4,400
79,400
2,000
6,500
159,600

7,000
11,000
10,000
128,000
5,000
8,000

Industrial
1,600
1,600
24,600
3,000
2,400
(including all
industrial)

9,000
124,000
62,000
25,000
45,000
3,000

Reservoir
Evaporation
8,000
29,000
331,900
31,000
8,000
1,445,000

177,000
9,000
29,000
332,000
31,000
17,000

Total
'201,800
216,700
1,997,100
41,000
41,200
2,939,900

766,000
382,000
386,000
2,270,000
88,000
89,000
Upper Missouri Mainstem
  (To Oahe Dam)

North Platte
(Wyoming only)
918,000
Note (1)


36,000
47,000
180,000
1,181,000
(1)  Major water demands in this region will be supplied out of the Mainstem
     reservoirs which have a supply that greatly exceeds any projected uses.

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the water utilized in these sectors.
     Estimates of water use in the year 2000 in the Upper  Missouri  River
Basin portion of the study area are also given in Table  4-14.   Projections
for portions of the subregions in the state of Wyoming are taken from the
Wyoming Framework Plan 14 which projects moderate increases in irrigation
depletions for food and fiber production, but relatively larger increases in
industrial use.  Projected Montana water use is from  the Montana Department of
Natural Resources and Conservation15.  Figures for the Yellowstone  Mainstem
and  the Heart-Cannonball subregions were disaggregated from estimates for the
total Yellowstone Basin16 and the western Dakota tributaries of the Upper
Missouri Basin.  No use projections were made for the Upper Missouri Mainstem
subregion because it is anticipated that the abundant water supplied available
in the Fort  Peck reservoir and Lakes Sakakawea and Oahe  will be more than
adequate to  meet the energy and all other water needs of that area  well into
the  future.
     In Table  4-14 the figures given for industrial usage include self-supplied
industrial uses  (municipally-supplied industrial water is included  under
M&I/Domestic)  which are primarily for the mining/minerals industry  and thermal
power generation.  Projections for  synthetic fuel production are not included
in this  category.  Data on future reservoir evaporation  losses is not available
so it has been assumed that these depletions will be  the same in the future as
at present.  The largest increases  are for irrigation and industrial uses; the
latter increase is primarily for increased water consumption in cooling towers
for  steam-electric power generation.
     Upper Colorado River Basin
     Agriculture is also an important part of the economy of the Upper Colorado
River Basin.   Because much of the Basin has a semi-arid  climate and little
precipitation  over most of the year, most of the region's growth has occurred
along the Colorado River and its major tributaries.   Since even these major
rivers naturally would have large seasonal fluctuations  in flow, numerous
storage reservoirs have been built  throughout the Colorado Basin to more
evenly distribute the water supply.  Today the Colorado  River is one of the
most regulated rivers in the country and a uniform, reliable flow can be
produced over the entire year.
     This has  led to the development of many irrigation  projects at locations
throughout the Basin.   Presently water use for irrigation  accounts  for by far
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the largest depletions of the available supply.  The reservoirs that make  this
water available for use, however, also cause significant depletions through
evaporation.  A summary of present water use within each of the study  subregions
according to the various demand sectors is given in Table  4-15.
     Upper Colorado River Basin water use estimates for the year  2000  are  also  given
in Table  4-15.  Projections of irrigation depletions are based on OBERS  (Office
of Business Economics, U.S. Department of Commerce and the Economic Research
Service, U.S. Department of Agriculture)   projections of  agricultural data as
                                                           18
disaggregated from figures given for the individual states  .  M&I and self-
supplied industrial (exclusive of synthetic fuel production) projections were
derived from figures given in Ref. 5.  By the year 2000 it was assumed that each
state will be utilizing their allowable share of the mainstem reservoir evapora-
tion which is apportioned to the states based on the Upper Colorado Compact
share allotments.  Data for future levels of "other" uses  is not  available, so
it was assumed there would be a 50 percent increase in this category over
present depletions, primarily for fish, wildlife and other recreational devel-
opments.  The largest increases are for irrigation and industrial
 (steam-electric power generation) uses.
Demand Variability and Demand Changes
     The utility of water for certain uses varies considerably from season to
season throughout the year.  This is particularly true of  agricultural uses
which account for a very large portion of total water use  in the  western study
region and which occur primarily during the summer and fall growing seasons.
The average duration of the growing season extends from about mid-May  through
September in the Upper Missouri Basin and from about May through  mid-September
in the Upper Colorado Basin.  Demands for irrigation water, therefore, begin
in April, gradually increase to peak requirements in July, and then taper
off until about October.  The winter months of November through March  have no
                              19
irrigation water requirements
     The amount of irrigation water required from year to  year also varies,
depending on a number of factors among which is the amount of natural  rainfall.
During dry periods or drought years when the available water supplies  are  at
their lowest levels, irrigation demands tend to be highest.  During these
periods many of the junior water rights in certain areas cannot be met.
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                                  TABLE 4-15.   WATER USE - UPPER COLORADO  RIVER BASIN
                                              (DEPLETIONS - ACRE-FEET/YEAR)
                                                 MSI and
               Sub basin            Irrigation
         Present
         Upper Green                 242,000
         Lower Green                 550^000
         Upper Mainstem              775,000
         Lower Mainstem               33,000
         San  Juan                    286,000
o        Projected Future (Year 2000)
         Upper Green                 407,000
         Lower Green                 655,000
         Upper Mainstem            1,166,000
         Lower Mainstem               58,000
         San  Juan                    696,000
         1  Other  losses  are  consumptive conveyance losses and evaporation
           attributed  to recreation,  wildlife and wetlands.
Rural
Domestic
12,000
6,000
15,000
1,500
11,500
6,000
15,000
20,000
2,000
27,000

Industrial
16,000
28,000
13,000
1,500
31,500
104,000
146,000
108,000
23,000
188,000
Reservoir
Evaporation
26,000
31,000
79,000
2,000
95,000
73,000
144,000
168,000
18,000
117,000
1
Other

154,000
194,000
-
48,000
24,000
231,000
291,000
-
72,000

Total
296,000
796,000
1,096,000
38,000
472,000
618,000
1,191,000
1,753,000
101,000
1,100,000

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     Reservoirs built to carry spring runoff over to the peak  agricultural
need during the growing season and to some extent from wet years  to  dry  years
also account for a water depletion that varies seasonally.  Although storage
impoundments help to even out the seasonal fluctuation in runoff,  signi-
ficant evaporation water losses result in net decreases in the water available
to downstream areas.  The variation of reservoir evaporation losses  closely
resembles that for irrigation demands with evaporation being highest during
July/August and diminishing to zero during the winter months when  the reservoirs
are frozen.
     Municipal and particularly industrial demands tend to be  much more  constant
over time.  These demands, however, are generally much more dependent on
reliable supplies and therefore required priority rights during low  flow
periods.
     Any discussion of potential demand changes must recognize that  the  limited
water supply and associated high economic cost of water in the West  have directly
influenced growth and development in many areas and has kept use at  relatively
low levels.  Since water demand is a sensitive function of cost for  many
uses, the overall demand structure in any locale at one unit cost  (i.e., supply
level) may be very different than the structure at a higher unit  cost.   This is
an important consideration in assessing any potential demand changes affecting
the future supply/demand picture, particularly in the primary  energy regions
of the West, since the value of water for energy production is likely to be
higher than the value for agricultural uses.  This could result in a signifi-
cant shift in water use as a result of industrial users acquiring  agricultural
rights to use water.
     As energy and other industrial developments occur in the  future, institu-
tional constraints may play a key role in the way water may be distributed  or
used.  Constraints on inter-basin transfers, particularly in the  Yellowstone
River Basin, presently make development of some prime coal deposits  just
outside the basin boundary difficult.  Also present priority schedules in
some states give a low preference to industrial uses of water.
     The primary demand sectors which are expected to have an  impact tending
to increase water use in the future are increased irrigation use  for food and
fiber production and an increased role of the region in providing  for the
nation's energy needs.

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     With regard to the future course of agricultural  development,  there is
considerable disagreement as to whether there will be  a  net  increase or
decrease in irrigated agriculture in the study  area, and the magnitude of any
such change.  The relative portion of agriculture in the future competition
for water between energy and agriculture depends to a  great  degree  on the
national policies and market conditions, which  will affect the degree of
Federal financing of irrigation developments such as Bureau  of Reclamation
storage projects.
     The nature of future energy development and the water required to support
it also depends in large part on national policy and international  developments.
Depending on the extent to which the nation decides to develop a self-sufficient
energy policy and the extent to which nuclear energy is  utilized in the
program will greatly affect the level of coal and oil  shale  development occurrin
in the study area in the near to intermediate future.  The mix between coal-
fired thermal electric power generation and synthetic  fuel production will
also affect the overall water requirements.
     As the competition for the increasing scarce water  supplies becomes more
intense, a number of developments could tend to change the nature of use in
several demand sectors.  These generally involve the conservation and reuse of
water through better management practices.  Significant  saving in industrial
water use could be realized if dry cooling systems are installed more frequently
in the future.  The use of poorer quality supplies or  reuse  of wastewater
supplies rather than high quality surface supplies represents another avenue
that could affect the future industrial demand  situation.
Water Supply Availability
     In this section estimates are made of the  total future  unallocated surface
water supplies in each of the hydrologic subregions by combining the total
annual water supply data with water use projections for  uses other  than
synthetic fuel production.
     A summary of projected regional water availability  for  coal and oil shale
conversion in the year 2000 is given in Table 4-16 for both  the Upper
 Missouri River for the Upper Colorado River Basins.   Projected increases for
steam-electric power generation have been included in  the  projected depletions
                                       132

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                         TABLE 4-16.  PROJECTED FUTURE  WATER AVAILABILITY (YEAR 2000) IN 1000 AF/YR
                            Annual Water Supply
Water Use and Commitments
LO
U)
Natural Depleted
Subbasin Yield Inflow
Upper Missouri River
Tongue- Rosebud
Powder
Yellowstone
Mainstem 10,
Belle Fourche
Cheyenne
Heart-Cannonball
North Platte 1,
Upper Colorado River
Upper Green 1,
Lower Green 3,
Upper Mainstem 6,
Lower Mainstem
San Juan 2,
Basin
467
502

488

182
338
223
Basin
926
534
838
451
387
0
0

0

0
0
520
0
1,300
0
9,298
0
Total
Imports Supply
0
0

0

0
0
10
0
0
0
0
130
467
502

10,488

182
338
1,753
1,926
4,834
6,838
9,749
2,517
Projected
Depletions
382
386

2,270

88
89
1,181
618
1,191
1,753
101
1,100
Total
Instream Flows Exports Use
148
162

4,070

75
138
501
960
2,400
3,400
4,900
1,260
0
0

0

0
0
0
10
112
620
0
113
530
548

6,340

163
227
1,682
1,588
3,703
5,773
5,001
2,473
Net Water
Availability
(63)
(46)

4,148

19
111
71
338
1,129
1,065
4,748
44

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in each Basin.
     These summaries consist of three parts for each region:  the  overall
water supply, water use and commitments, and the net remaining water  supply.
The overall water supply in a subregion consists of the natural water yield
within the subregion (as previously given in Tables 4-10 and  4-12) , the
depleted stream inflows from other subregions, and any water  imports  from
other subregions.  Data on possible future intra-basin transfers  (imports/
exports) are not specific enough to allow reliable projections of  these
quantities, so present water transfers have been used in these tables.   Water
use and commitments are made up of projected future depletions  (as previously
given in Tables  4-14 and 4-15 , instream flow requirements, and any water
exports from out of the subregion.  It has been assumed that  present  unused
water commitments will be utilized by the year 2000 and that  future use
projections include these present commitments.  The difference between the
total available  water supply and the total water use and commitments  is  the
net water  supply available for future depletion.
     A  number of prior studies have considered and described  various  energy
development scenarios that may occur depending on several underlying  factors
such as the availability and cost of nuclear energy, foreign  oil or other
               1, 14, 16, 20-25              ,                     .
forms of energy                .  A summary of expected water requirements in
each of the drainage sub-areas for some of these scenarios are presented in
Section 6  of Appendix 14.  Since these projections are highly variable,  we
have examined two cases of water demand.  For low water demand,we  have assumed
that one or two  standard size coal or oil shale conversion plants  are located
in each one of the seven drainage basins in the Upper Missouri River  Basin and
in each one of four drainage basins in the Upper Colorado River Basin; the
total number of plants range from 12 to 24.
     For high water demand, we will consider a synthetic fuels industry
producing  1x10  barrels/day of synthetic crude, or its equivalent  in  other
fuels of 5.8x10   Btu/day, in each of the three principal coal bearing regions
in the West:  Ft. Union, Powder River and Four Corners,- and in the principal
oil shale region: Green River Formation.  The total production in  the Western
region is 4x10  barrels/day.   As a relative measure, in 1977,  crude oil was
imported at about the rate of 6xlQ6 barrels/day and distilled products at
about 2x10  barrels/day.   Table 4-17 lists the number of standard  size plants
                          12
required to produce 5.8x10   Btu/day for the conversion technology and product
output indicated.  The range is from 18 coal refining plants  producing 10,000
tons/day of solvent refined coal to 24 coal gasification plants producing

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       TABLE  4-17   NUMBER OF STANDARD SIZE PLANTS REQUIRED TO PRODUCE
            1  x  10   BARRELS/DAY OF SYNTHETIC CRUDE OR ITS EQUIVALENT
                             OF 5.8 x 1012 BTU/DAY
    Conversion                                              Number of
    Technology             Product         Unit Output   Standard Size Plants
Coal gasification        Pipeline gas    250 x 10  scf/day       24
Coal liquefaction          Fuel oil      50,000 barrels/day      19
Coal refining        Solvent refined coal 10,000 tons/day         18
Oil shale               Synthetic crude  50,000 barrels/day      20

250x10  scf/day  of  pipeline gas.   In summary, low water demand represents
production of  about 0.5 to 1.0x10  barrels/day of synthetic crude, or its equivalent,
while high water demand represents production of 4x10  barrels/day.
     The sub-areas  used to report energy development and water requirements
are generally  different than the drainage sub-areas.  In order to arrive at
some consistency between the two, we have assigned drainage sub-areas to each
of the coal and  oil shale bearing regions in the West.  This is shown in Table
4-18.  In the  Powder River and Ft. Union coal regions there may be some overlap
of the drainage  sub-areas.  Low water demand requirements were determined by
assuming that  two standard size gasification plants were located in each of
the drainage sub-areas of the coal bearing regions and two standard size oil
shale conversion plants were located in three of the drainage sub-areas of the
Upper Colorado River Basin  The Lower Colorado River Mainstem was not considered.
As will be shown in Section 5, gasification plants have the largest water
consumption The  water requirements for each region were calculated based on
the data shown in Table 5-6 for a high degree of wet cooling.  For high water
demand, we have  assumed that the water requirements for each of the drainage
sub-areas within a coal or oil shale region are equal.  The water requirements
for low water  demand and high water demand are given in Table 4-18 for each of
the hydrologic sub-regions.  We should point out these estimates are conservative
because a high degree of wet cooling was assumed.  In fact, as will be shown
later, intermediate or minimum practical wet cooling should be primarily used
in the West, reducing the water requirements given in Table 4-18 by about one-third.
     Comparison  of the consumptive water requirements in Table 4-18 with the
water availability results in Table 4-16 gives an indication of the relative
                                       135

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   TABLE  4-18    SUMMARY  OF WATER REQUIREMENTS FOR COAL AND OIL  SHALE CONVERSION
            IN  EACH OF THE DRAINAGE SUB-AREAS (10  GPD OR 1000  AF/YR*)
 Powder River Coal Region
      Powder (UMRB)
      Yellowstone  Mainstem (UMRB)
      Bell Fourche-Cheyenne (UMRB)
      North Platte (UMRB)
 Ft.  Union Coal Region
      Heart-Cannonball (UMRB)
      Upper Missouri  Mainstem (UMRB)
      Tongue-Rosebud  (UMRB)
 Four Corners Coal Region
      San Juan (UCRB)
 Green River Oil Shale Formation
      Upper Green  (UCRB)
      Lower Green  (UCRB)
      Upper Colorado  Mainstem (UCRB)
Low Water
Demand
4
4
4
4
4
4
4
High Water
Demand
40
40
40
40
50
50
50
14

 6
 6
 6
180

 60
 60
 60
 *Based on a load factor  of  90%.

 adequacy of water supplies  for  coal  and oil shale production in the drainage
 subbasins.   Except for the  Tongue-Rosebud and Powder River drainage areas, the
 water  required for the low  water  demand can be accommodated by the available
 supplies  in most  of the  subbasins.    However, in the Belle Fourche-Cheyenne
 and  San Juan basins the  water demands for synthetic fuel production are
 greater than about twenty percent of the total water availability; this may
 be considered excessive.  For high water demand, the projected loads cannot be
 accommodated by the available supplies  in most subbasins.   In the Upper
 Green, Heart-cannonball  and North Platte subbasins,  the water demands are
 greater than twenty percent of the total water availability.   Only in the
 Yellowstone, Upper Missouri, Lower Green and Upper Colorado mainstem subbasins
 does it appear that sufficient supplies  are available for the expected loads
 of energy production.   However, it should be pointed out that water availability
within the Upper Colorado River Basin may be limited because  all of the water
                                       136

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rights to most of the free flowing water in the Basins  are  already  allocated.
These rights would have to be transferred to support additional  energy  develop-
ments.  Lack of sufficient water could be a limiting factor in the  other
regions unless additional supplies can be made available through surface
and/or ground-water development or through the acquisition  of existing  rights.
Alternative Water Supply Sources
     Some of the possibilities for water supply for energy  conversion have
been evaluated.  All possibilities have not been fully  evaluated, or even
identified, and since the study has been performed at long  distance, there may
be some inaccuracies in the broad-level analysis.  The  evaluation of water
rights is difficult without extensive field work, and for this reason,  the
purchase of water rights is acknowledged in many of the water supply alter-
natives, although no estimates are made of the prices or the different  manipu-
lations of water rights which would be necessary in any such program.
     In general, there are several sources of water for large demands including
groundwater, purchase of water used for irrigation, construction of storage
facilities, purchase of water from existing storage facilities,  and inter-
basin transfers of water.  Each of the alternatives given is comprised  of one
or more of these water sources.
     The alternatives presented are compatible with those for the other river
basins, even when inter-basin water transfers are involved.  Thus it is possible
to combine any alternative from one river basin with any project from another
river basin.  In several cases, projects for more than  one  river basin  could
be combined and cost efficiency increased.
     A summary of the water supply alternatives for the subbasins in the Upper
Missouri River and Upper Colorado River Basins is presented in Table 4-19.
Comments on each subregion are given below.
Tongue-Rosebud River Basins
     The Tongue River and Rosebud Creek drainage basins, adjacent to the
Powder River Basin, have a high demand for the scant available water in the
drainage basin.  Because these rivers are both tributaries  of the Yellowstone
River, importations to the Tongue and Rosebud Basins from other parts of the
Yellowstone Basin are permitted by the Yellowstone River Compact.  There are
several sites in the Basin for which reservoirs have been proposed, and these
are included as possible alternatives for water supply.
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               TABLE 4-19  SUMMARY OF WATER SUPPLY ALTERNATIVES
          Subbasin

Upper Missouri River Basin

Tongue-Rosebud



Powder
                                   Low Water
                                    Demand
                              High  Water
                                Demand
Yellowstone Mainstem



Belle Fourche-Cheyenne



Heart-Cannonball


Upper Missouri Mainstem


North Platte



Upper Colorado River Basin

Upper Green


Lower Green


Upper Mainstem



Lower Mainstem



San Juan
Additional storage alone,  Additional storage or
or with water rights       aqueduct from Bighorn
acquisition                or  Yellowstone
Acquisition of water
rights, or construct
Moorhead or Lower Clear
Creek Reservoir

Mainstem diversion
Ultimate Powder River
development, or aqueduct
from Bighorn or Yellowstone
Mainstem diversion to
     offline storage, or
     Ft. Peck Reservoir
Reservoir development,  or   Reservoir  and groundwater
groundwater development    development or aqueduct
                                 from  Bighorn or Yellowstone
Reservoir development
Mainstem diversion
Acquisition of water
rights and/or ground-
water development
Additional local storage
facilities

Reservoir development on
the White River

Diversion from the main
stem to utilize existing
storage
Aqueduct from Sakakawea
     or Oahe Reservoirs

Aqueduct from Ft. Peck,
Sakakawea or Oahe Reservoirs

Same Low Demand, or import-
tation from Green Basin
Aqueducts from Fontenelle
and/or Flaming Gorge

White River storage plus
diversion from Green River

Same as Low Demand
Although no significant energy development  has  been
projected from the Lower Mainstem  hydrologic  subregion
large supplies are available  from  Lake  Powell.
                              Groundwater development
                              and/or diversion using
                              Navajo Reservoir storage
                           Diversion  using  all  available
                           Navajo  Reservoir storage  and
                           extensive  groundwater
                           development
                                        138

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Powder River Basin
     In general the Yellowstone and Bighorn have  sufficient water supplies
for all anticipated in-basin requirements, whereas  the  Tongue  and Powder
drainage basins, with the largest supplies of  coal,  have  a more limited
supply of water relative to the total demand.
     Large amounts of coal lie very near  the indistinct drainage divide
between the Powder River and the Belle Fourche River, in  the Belle Fourche
River drainage basin.  The water supply of the Belle Fourche is very limited,
thus forcing investigation of trans-basin imports of water.  However,  the
nearest sources of water are tributaries  of the Yellowstone, subject to con-
straints imposed by the Yellowstone River Compact upon  the export of water
from the Yellowstone River.
Yellowstone and Missouri River Basins
     The Yellowstone and Missouri Rivers  have  ample  water supplies for any of
the projected water demand scenarios for  their entire length.   Although the
Yellowstone River is free-flowing for its entire  length,  there are two very
large reservoirs on the Missouri in the area of interest,  Ft.  Peck Reservoir
and Lake Sakakawea.  Additionally, there  are two  reservoirs on the Bighorn
River, a major tributary to the Yellowstone River,  which  can provide storage
for water along the stretch of concern of the  Yellowstone River.
     Because it is still free-flowing, the Yellowstone  River is presently
being studied for inclusion in the Wild and Scenic  Rivers Section.  If it is
so designated, severe restrictions will be placed on the  construction  of
storage and water use facilities of the mainstem  river.
Heart and Cannonball River Basins
     The Heart and Cannonball Rivers both lie  completely  within North  Dakota
and are tributary to the Missouri River.  Due  to  their  relatively small
watershed area, they both have limited streamflow.   Since the  drainages are
adjacent and parallel to each other, with a low drainage  divide between them,
it is assumed the transfer of water between the basins  is possible without
major problems.  There are no compacts concerning either  of these rivers
which would hinder their development from institutional considerations.
Platte River Basin
     While there is a large amount of water in the  Platte River Basin, it is
present being used for a variety of uses, with agriculture being the largest
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user.   In this situation there are two directions in which  one  can proceed
to obtain the water necessary for new purposes:  (1) develop new sources of water,
and (2)  purchase and transfer of water presently being used for other purposes.
The possibility of groundwater development remains, but  will not be further
discussed here.
     Importation of water from the Green River Basin is  one of  the most likely
possibilities for the development of new water in the Platte Basin.  There
exists a large amount of storage in the North Platte Drainage Basin,  but it
is all currently used, primarily for agricultural purposes.
     Developments in the water use of Platte River water will be closely
monitored by Nebraska and significant increases in consumptive  use will
probably be protested.
Upper Green River Basin
     The Green River in Wyoming is that state's major contributor to  the
Colorado River drainage.  There is currently very little development  in the
region, and most of the water allotted to Wyoming under  the terms of  the
Upper Colorado River Basin Compact flows unused out of the  state.  This means
that large amounts of water in the Green River are available for development
and beneficial use.
     There are two reservoirs on the Green River in Wyoming, Fontenelle and
Flaming Gorge, both of which are part of the Upper Colorado River Basin
Storage Project.  With the storage capacity of these reservoirs, adequate
water supplies are available for the energy demands presently envisioned for
the Green River Basin in Wyoming.
     For these reasons, the anticipated source for all of the scenarios would
be the Green River, with its storage capabilities in the Fontenelle and
Flaming Gorge Reservoirs.
Lower Green River Basin
     For each of the demand scenarios, the same sources  of  water exist.
These are the Green River, the White River, the Colorado River  and possibly the
Strawberry-Duchesne Rivers.   In general the Green River  is  seen as a  probable
source of water for the Utah energy requirment, with excellent  storage
capacity in Fontenelle and Flaming Gorge Reservoirs.
     The White River is also a very good potential source of water.for the
Utah demand.   However,  the lack of a White River compact between Utah and

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Colorado combined with the potential utilization  of White River water in
Colorado make it risky to depend on. this  source without assurance of
continued supply in Utah.
     The Colorado is seen as an unlikely  source of  water because of its
distance from the proposed sites.   The proposed Starvation Reservoir on the
Strawberry River could supply a portion  (about 30,000  AF)  of  the required
amount.  This would be carried by the Duchesne River,  whence  an aqueduct
would carry to the point of use.
Upper Colorado Mainstem
     There are two major surface water sources which are being  considered
seriously.  They are the White River and  the Colorado  River.  Either one has
sufficient average annual flow to supply  the major  portion of the requirement.
It is anticipated, however,that both rivers will  be used,  as  the sites  vary in
their' proximity to each river.  There exists currently a large  amount of
storage capacity in the Colorado River, but very  little in the  White River.
There have been, several dam sites identified, but none of  them  are expected
to be built by Federal agencies.  Instead, they may be developed by private
groups, such as a consortium of energy companies.
San Juan River Basin
     There exist two major sources of water in the  San Juan River Basin  in
New Mexico which could supply the amounts of water  required by  coal conversion
plants.  These are the San Juan River and groundwater.   It must be realized,
however, that there will be strong competition for  the water  from a variety
of sources,  among whom a very important one is the  rapidly developing uranium
mining and processing industry.   New Mexico is one  of  the  centers of the
uranium mining and milling industry.- and this industry's development will
closely follow the general development of nuclear power activities in the
United States and the world.
     One of the most important effects of both uranium and coal  mining
will be the  consequences of dewatering on the surrounding  areas,  and on  the
water supply picture in general.   Mine dewatering will  produce  a  large amount
of water of  varying qualities available for immediate  consumption.   However,
this has the effect of mining the aquifer of its water,  and could  potentially
have very serious and far-reaching long-term consequences.  For  this  reason
the mine dewatering will necessarily be closely monitored  by  the  New Mexico

                                      141

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Department of Environmental Improvement, which is concerned mainly with  the
pollutional aspects.   Until now, no policy has been established  in New Mexico
with respect to this problem.  It is possible that this will  change  in the
near future.
     The San Juan River is the other major possibility for a  large supply of
water.  A tributary of the Colorado River, it is the only major  river flowing
through the northwest quadrant of New Mexico.  The only significant  reservoir
on the San Juan River is the Navajo Reservoir which has approximately 100,000
AF/year allotted for industrial purposes, most or all of which will  be energy-
related.  This river is subject to the Colorado River Compact and the Upper
Colorado River Basin Compact.  Because the San Juan River is  essentially the
entire Colorado River drainage of New Mexico,  New Mexico receives its allotment
of Colorado River water from the San Juan River.
      The water required for  low water demand, of about 14,000 AT/year, would
probably come from the Navajo Reservoir on the San Juan River, with  ground-
water sources as a supplement.  For high water demand of 180,000 AF/year,
water could also be supplied primarily from the Navajo Reservoir.  However, it
would require an arrangement with local Indian tribes in which part  of their
water allocations would be used for industrial purposes.  There  would be
severe complications in supplying the high demand scenario, due  to institu-
tional problems of water transfer.  It is not known at this time to  what
extent groundwater can serve as a source for the water demand.   An extensive
study examining this problem is currently underway by the U.S. Geological
Survey.
Conclusions on Water Supply Availability
     Based on the data presented earlier in this section, several conclusions
can be drawn concerning the role of water availability in future energy
developments in the West.   It is apparent from future use projections that in
most regions, actual water use other than for energy will be  considerably less
than the total available surface water supply.  of the remaining water,
however,  significant quantities may already be legally committed to  other
uses, or may be required for instream flow uses.  In many cases, therefore,
water to meet energy requirements will have to be acquired through the purchase
of existing rights,  diverted from major interstate rivers and piped  to the
point of intended use,  or a combination of these.
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     The results of this investigation indicate that synthetic  fuel plant
water requirements will most easily be accomplished for  those plant sites
located along the main stems of the major rivers and in  areas where the  level
of competing use is projected to be small relative to overall water availability.
Subbasins in this category include the following:
          1.  Yellowstone River Mainstern
          2.  Missouri River Mainstern
          3.  North Platte River
          4.  Upper Green River
          5.  Upper Colorado Mainstern
Although overall water availability is generally favorable within  these
regions, individual plant sites may be located considerable  distances  away
from the water sources and require major water delivery  developments to  transport
the water to the required places.
     On the other hand, in several areas the expected level  of  future  water
needs for energy development will be very difficult to meet  from the available
sources within the region without major disruptions to the present water use
structure.  Some of the most readily developable coal reserves  in  the  Powder
River and Fort Union coal formations of northeast Wyoming and North Dakota are
located in basins with these characteristics.  These subbasins  include the
following:
          1.  Tongue-Rosebud
          2.  Powder River
          3.  Belle Fourche-Cheyenne
          4.  Heart-Cannonball
In these regions the energy water requirements probably  can  best be met  by
trans-basin diversions from more adequate supplies outside the  regions.
4-4  Water Supply to Chosen Sites
     The water to meet energy requirements will probably have to be transported
to the point of use from major interstate rivers and riverways.  In this
section we estimate the cost of building and operating a pipeline  for  a  number
of different water supply options.  Details of the calculations are found in
Appendix 15.
     Figure 4-9 shows the total annual cost  (expressed in terms of $/1000 gal)
of building and operating a pipeline as a function of pipe diameter for  a
                                      143

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typical set of conditions.  For a particular pipeline diameter  and pipeline
flow velocity, the total annual cost has a minimum.  The total  annual  cost
increases more rapidly for diameters smaller than the minimum cost diameter
than for diameters larger than the minimum cost diameter.  The  friction
pumping costs dominate the total costs for the former, while the pipeline
construction costs dominate for the latter.
     Figure 4-10 shows the minimum cost of transporting water.  The  capital
and friction pumping costs do not include the cost of pumping against  a  static
head.  The static head pumping costs are given in the lower part of  the  figure
and should be added to the capital and pumping costs to arrive  at a  total
annual cost.  At a flow rate of about 6x10  gpd, corresponding  to the  high end
of the water requirements for a standard size coal gasification plant, the
unit cost of water supply is about 2.5C/1000 gals-mile, while for a  flow rate
of 60x10  gpd the unit cost of water supply is 0.25^/1000 gals-mile.   This
illustrates the capital intensive nature of pipeline construction and  operat-
ing costs and indicates that if at all possible, pipelines should be built to
supply the needs of a particular region rather than a specific  plant.
     We have considered the case of a single pipeline supplying water  to a
single coal conversion plant in the Upper Missouri Basin and the Four  Corners
Region.  We have assumed that the water supply comes from the nearest  reliable
water source of sufficient size.  Trans-basin diversions are presumed  possible.
Table 4-20 lists the total cost of water conveyance for all of  the plant-site
combinations.  The minimum distance for transporting water was  1 mile  (Decker
to North State Line Reservoir) and the maximum distance was 96  miles (Gallup,
N.M. to San Juan River).  The cost varied from $0.023/1000 gals to $3.45/1000
gals.  It should be pointed out that this is the minimum cost of transporting
water and does not include the purchase of water rights or the  cost  of the
water itself.
     As will be shown in Section 5, the cost of water determines the degree to
which wet cooling should be used.  At a site where water is plentiful  and
inexpensive to transport, high wet cooling would be used.  In regions  where
water is marginally available or moderately expensive to transport,  intermediate
cooling would be used, and where water is expensive to transport or  scarce,
minimum practical wet cooling would be used. High wet cooling does not mean
                                        144

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   10
     -1
01

i
1/5
C
o
(Q
CD

O
O
O
                                           PUMPING STATION -

                                           PUMPING (FRICTION) COSTS
              = $25,000/inch  (diam.) mile

                   = 0.10
-  P
f

E

k

N  =

Q  =

H  =

   =

Vu =
 M

DM =
- "M
 3x10
     -3
       0.1
                                                           PIPELINE
                                                         CONSTRUCTION
                                                             COSTS
                                                          PUMPING (ELEVATION)
                                                          COSTS
                                                    1.0
                                         D/D
                                            M
                 Figure  4-9   Total annual costs  for transporting water

                             as a  function of pipe diameter.
                                         145

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     10
       -1
 0)
 E
 I
 to
 c
 o
 113
 CD
O
O
O
o
o
10
  -2
                   1	1	1—|—TT
                   CAPITAL AND PUMPING (FRICTION)
                               COSTS
                                H/L = 0
                         100
                          50
1—I  I  I  I
 N = 0.91
 f = 0.016
 E = 0.80
 k  = $0.02/Kwhr
                                                       k  = $25,000/in (diam.)
                                                                       - mile
                                               D=24"
                    H/L =  25  Ft/mile  PUMPING (ELEVATION) COSTS
     10
       -3
                                        10
                                         Q,  FLOW RATE (mgd)
                                                                100
                            Figure 4-10  Unit cost of water supply

-------
TABLE  4-20.  LOCAL SUPPLY TO  INDIVIDUAL PLANTS
Location
Beulah
Will is ton
Center
Underwood
U.S. Steel
Coalridge
Gillette
Antelope
Creek
Lake-de-Smet
Spotted
Horse
E.Moorhead
Decker Cr.
Otter Cr.
Foster Cr.
Pumpkin Cr.
Colstrip
Belle Ayr
Slope
Dickinson
Bentley
Scranton
Hanna
Distance
Water Source (miles)
Lake Sakakawea
Lake Sakakawea
Missouri River
Lake Sakakawea
Yellowstone River
Medicine Lake
Crazy Woman Creek
Beaver Creek
Reservoir
Lake-de-Smet
Clear Creek
Reservoir
Moorhead Reservoir
North State Line
Reservoir
Moorhead Reservoir
Tongue River
Tongue River
Yellowstone River
Crazy Woman Reservoir
Mott Reservoir
Mott Reservoir
Mott Reservoir
Thunderhawk Reservoir
Seminoe Reservoir
16
8
16
8
10
16
45
72
5
16
22
1
20
16
24
28
54
44
50
10
42
20
Static
Head
(feet)
50
250
300
150
600
400
940
1000
200
400
700
50
200
350
600
700
850
350
100
150
550
100
Total Cost
$/1000 gals
0.43
0.16
0.37
0.13
0.26
0.40
1.20
1.26
1.90
2.08
2.03
0.12
0.47
0.61
0.03
0.02
0.48
0.43
0.60
0.74
0.66
0.67
1.37
1.32
1.29
0.26
0.91
0.43
Total Cost
$/acre-ft
140
53
120
43
83
130
390
411
620
678
- 661
39
154
198
8
7
156
139
197
241
216
220
446
431
420
86
295
140
                                                      Continued
                       147

-------
TABLE 4-20.  (concluded)
Location
Kemmerer
Jim Bridger
Rainbow #8
Gallup
Static
Distance Head
Water Source (miles) (feet)
Fontanelle 70 900
Reservoir
Flaming Gorge 18 400
Reservoir
Flaming Gorge Res. 18 500
San Juan River 96 1800
Total Cost
$/1000 gals
1.53
2.13
0.50
0.44
0.37
2.52
2.54
2.25
Total Cost
$/acre-ft
505
695
164
144
121
823
827
732
We sco
El Paso
San Juan River
San Juan River
30
50
400
800
0.66
1.23
1.10
213
401
358
                                      148

-------
that all of the unrecovered heat is dissipated by wet  cooling,  since  an
appreciable fraction will be lost directly to the atmosphere.   Minimum
practical wet cooling does not mean that none  of the  unrecovered heat is
dissipated by dry cooling, since this is not economical.  The largest
difference in total net water consumed occurs between  high wet  cooling and
intermediate cooling; there is very little difference  in water  consumption
between intermediate wet cooling and minimum practical wet cooling. If water
costs more than $1.50/1000 gals, minimum practical cooling would be used.
Intermediate wet cooling would be used if the water cost is between $0.25/1000
gals to $1.50/1000 gals, while high wet cooling would  be used if water costs
less than $0.25/1000 gals.
     On Figure 4-10 we have shown those sites where the cost of transporting
water to the site for a standard size plant is less than $0.25/1000 gals and
greater than $1.50/1000 gals.  It is clear that except for plants located near
the main stem of the major rivers, intermediate cooling would be desirable for
a large majority of the sites in the Upper Missouri Basin and the Four Corners
Region.  In general we could extend this result to the Upper Colorado River
Basin, as a whole.
     If a large scale synthetic fuel industry is to be developed in the West,
large quantities of water will be required.  It is clear that it is more
economical to have a large single pipeline built to transport water to a large
number of plants than to have a large number of individual pipelines supplying
individual plants.  Table 4-21 shows the total cost of transporting water for
a number of mine groupings for 50, 100, 150 and 300x10  gpd; the cost does not
exceed $1.63/1000 gals for all the cases that we have  considered.
     In the previous section we showed that the water  requirements for
high water demand for each of the drainage sub-areas is about SOxlO6 gpd,
except in the Four Corners Region where the demand would be about 180x10  gpd.
Figure 4~12 shows the cost of transporting these quantities of water to some
of the major coal producing regions.  Here again, except for large scale
development near the main stems of the major rivers, intermediate cooling
would be desirable for most of the study sites.
                                     149

-------
     MONTANA
                                           NORTH DAKOT
                                      UPPER

                                      MISSOURI

                                      RIVER BASIN
        V\vV\\v—""">
        \^m
                        WYOMING
                                       Cost Of Wbter
                                       ($/ioco  GALS)
                                            <0-25
UPPER  COLORADO
  RIVER  BASIN
                                        9TE LOCATIONS
                                        m primary sites

                                        • secondary sites
Figure 4-11 Cost of transporting water to specific site locations.
                  150

-------
TABLE  4-21.  LARGE SCALE  WATER CONVEYANCE COSTS


I location
; Midpoint
between Wesco
; and El Paso

Highlight
1


Rock Springs


1

Gillette












Stan ton





Group of Mines
Wesco, El Paso



Gillette, Belle
Ayr, Antelope
Creek

Jim Bridger,
Rainbow #8



Foster, Pumpkin,
Moorhead,
Spotted Horse,
Gillette,
Belle Ayr,
Antelope Creek







Center ,
Underwood,
Knife River



Water Source
Navajo Reservoir
via San Juan
River

Boysen Reservoir



Green River




Boysen Reservoir




Yellowstone at
Miles City


Bighorn River at
Hardin


Lake Sakakawea



Static
Distance Head
(miles) (feet)
38 500



150 0



14 400




180 -253




165 2300



180 1840



14 100




Flow
(mgd)
50
100
150
300
50
100
150
300
50
100
150

300
50
100
150
300

50
100
150
300
50
100
150
300
50
100
150
300

Total Cost Total Cost
$/1000 gals $/acre-ft
0.35 115
0.26 86
0.22 73
0.17 56
1.22 398
0.86 281
0.71 230
0.50 163
0.15 49
0.12 38
0.10 33

0.08 27
1.47 478
1.04 338
0.85 276
0.60 195

1,55 505
1.16 376
0.98 319
0.75 246
1.63 531
1.20 391
1.01 329
0.76 249
0.12 40
0.09 29
0.07 24
0.06 18

-------
TABLE 4-21.   (concluded)
Location
Stanton
DeSart
Loesch
Quietus
Group of Mines
Center,
Underwood,
Knife River
Slope ,
Scran ton,
Bentley ,
Dickinson
Foster Creek,
Pumpkin Creek
Decker, Otter
Creek, Moorhead,
Spotted Horse
Water Source
Missouri River
Lake Sakakawea
Lake Oahe
Yellowstone River
at Glendive
Yellowstone River
at Miles City
Yellowstone River
at Miles City
Bighorn River at
Hardin
Static
Distance Head
(miles) (feet)
1 0
86 900
120 1100
122 700
60 850
108 1900
102 1400
Flow
(mgd)
50
100
150
300
50
100
150
300
50
100
150
300
50
100
150
300
50
100
150
300
50
100
150
300
50
100
150
300
Total Cost Total Cost
$/1000 gals $/acre-ft
0.008 3
0.006 2
0.005 2
0.003 1
0.78 254
0.58 188
0.48 158
0.37 119
1.08 351
0.79 257
0.66 216
0.50 162
1.06 344
0.77 326
0.64 207
0.47 152
0.56 184
0.42 137
0.36 117
0.28 90
1.05 342
0.79 258
0.68 221
0.53 172
0.96 311
0.71 232
0.60 197
0.46 151

-------
                                                      4---1
                                                      NORTH DAKOTA
                                                  UPPER
                                                  MISSOURI
                                                  RIVER BASIN
                                \  WYOMING
UPPER  COLORADO
  RIVER  BASIN
                                                   Cost Of Water
                                                   (S/IOCO GALS)
                                                       <0-25
                                                  y////.~o -25- '-so
                                                  "     > I - 50
SITE LOCATIONS
  primary sites
  secondary sits
  pipeline
         Figure 4-12  Cost of transporting water to coal regions.
                              153

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References - Section 4

  1.   Energy Research and  Development  Administration,  "Alternative Fuels
      Demonstration Program.  Final Environmental Impact Statement", ERDA-1547,
      Washington,  D.C.,  September  1977.

  2.   Harte, J.  and El-Gasseir, M., "Energy  and Water",  Science,  199,
      February  10,  1978.

  3.   Brill, E.D., Jr.  et  al, "Issues  Related  to Water Allocation in the Lower
      Ohio River Basin," Vol  III-G, Ohio  River Basin Energy Study, U.S.
      Environmental Protection  Agency, Washington,  D.C., May, 1977.
  4.   Smith, W.H.  and Stall,  J.B., "Coal  and Water Resources for Coal Conversion
      in Illinois," Cooperative Resources Report No.  4,  Illinois State Water
      Survey  and Illinois  State Geological Survey,  Urbana,  Illinois, 1975.
  5.   U.S. Department of the  Interior, "Report on Water for Energy in the
      Upper Colorado River Basin," U.S. Gov't.  Printing Office, Washington,
      D.C., 1974.
  6.   U.S. Department of the  Interior, "Report on Water for Energy in the
      Northern  Great Plains Area with  Emphasis on the  Yellowstone River Basin,"
      U.S. Gov't.  Printing Office, Washington, D.C.,  1975.

  7.   Northern  Great Plains Resources  Program, "Report of the Work Group on
      Water,"  Denver, Colorado, Dec. 1974.

  8.   U.S. Department of the  Interior, "Westwide Study Report on Critical Water
      Problems  Facing the  Eleven Western  States," U.S. Gov't. Printing Office,
      Washington,  D.C.,  1975.

  9.   Geraghty,  J.J., Miller, D.W., Leeden,  P.,  Von Der and Troise,  F.L. ,
      Water Atlas  of the United States.   Water Information  Center, Port
      Washington,  New York, 1973.

 10.   Ohio River Basin  Commission, "The Ohio Mainsteam-Water and Related Land
      Resources  Study Report  and Draft Environmental  Impact Statement," Cincinnati
      Ohio, January 1978.

11.   Bloyd, R.M. , Jr.,  "Summary Appraisal of  the Nation's  Groundwater Resources-
      Ohio River,"  U.S.G.S. Professional Paper  813-A, 1974.

12.   Week, J.B., Leavesley, G.H., Welder, F.A.  and Saulnier, G.J.,  Jr.,
      "Simulated Effects of Oil-Shale Development on the Hydrology of the
      Piceance Basin,  Colorado,"  Geological Survey Professional  Paper 908,
      U.S. Gov't. Printing Office, Washington, D. C. 1974.

13.  Price, D.  and Arnow, T.,  "Summary Appraisals  of  the Nation's Groundwater
     Resources-Upper Colorado Region,"  Geological Survey  Professional Paper
     813-C, U.S. Gov't. Printing Office, Washington,  D.  C.,  1974.

14.   "Wyoming Framework Water Plan,"  Wyoming  State Engineer's  Office,  1973.
                                      154

-------
15. "Water Use in Montana'1, Montana Department of Natural  Resources  and
     Conservation, Inventory Report No. 13, Helena, Montana, April 1975.

16.  "Analysis of Energy Projections and Implications for  Resource Requirements,"
     Harza Engineering Company, 1976.

17.  Office of Business Economics, U.S. Department of Commerce; and  Economic
     Research Service, U.S. Department of Agriculture field data.

18.  "Upper Colorado Region Comprehensive Framework Study, Appendix  X,
     Irrigation and Drainage",  Upper Colorado Region State-Federal Inter-
     agency Group, 1971.

19.  Climatic Atlas of the United States, U.S. Department  of Commerce, National
     Oceanic and Atmospheric Administration, 1974.

20.  "Energy from the West:  A Progress Report of a Technology Assessment of
     Western Energy Resource Development," Science and Public Policy Program,
     Univ. of Oklahoma, EPA-600/7-77-072, July, 1977.

21.  National Petroleum Council, Committee on U.S. Energy  Outlook, "Coal
     Availability," 1973.

22.  National Petroleum Council, Committee on U.S. Energy  Outlook, "Oil
     Shale Availability,"  1973.

23.  Federal Energy Administration, Interagency Task Force on Synthetic
     Fuels from Coal, "Project Independence Blueprint-Synthetic Fuels from
     Coal," U.S.  Gov't. Printing Office, Stock No. 4118-00010, Washington,
     D.C., November,  1974.

24.  Federal Energy Administration, "Project Independence  Report," U.S.
     Gov't. Printing Office, Stock No.  4118-00029, Washington, D.C.,
     November,  1974.

25.  Commerce Technical Advisory Board, "CTAB Recommendations for a National
     Energy Program," U.S.  Department of Commerce, U.S.  Gov't. Printing
     Office,  Washington, D.C.,  1975.

26.  West,S.W.,  "The  Role  of Groundwater in Resource Planning in the  Western
     United States,"  U.S.  Geological  Survey, Western U.S. Water Plan,Working
     Document,  Open File Report 74-125, Denver,  Colorado, March 1975.
                                      155

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                5.  WATER REQUIREMENTS AND  RESIDUALS

 5.1  Total Water  Consumed  and Residuals  Generated
      In this  section  the total water consumed and wet solid residuals
 generated in  standard size mine-plant complexes located in the principal coal
 and oil shale bearing regions of the United States are summarized.  The totals
 are summarized by conversion technology  for the United States as a whole with
 no distinction made between coal rank;  and then for each coal and oil shale
 region.  In the four sections following  this one the totals are broken down
 into a number of  water use categories and each category is summarized by
 conversion technology and  region.   The  details of the various analyses and
 calculations  that we have  performed in  arriving at the summary tables and
 graphs have been  omitted in this section. They can be found in the Appendix
 volume of this report.
      Water consumption is  based on net water consumption.  All effluent
 streams are assumed to be  recycled or reused within the mine or plant after
 any necessary treatment.   These streams  include the organically contaminated
 process condensate waters  and the  highly saline water blown down from the
 cooling system.   Water is  released to evaporation ponds as a method of salt
 disposal.   However, we  have generally assumed that the highly saline waters
 can be disposed of with the coal ash.  We have not considered the recovery of
 water from the drying of high moisture content coal such as lignite, because
 the costs  are high, in  the  range of $1.30 to $1.50 per 1000 gallons2.  However,
 recovery  is a serious possibility  when water is particularly scarce, especially
 in  the  West.    The rest of the water leaves the plant as vapor, as hydrogen
 in  the  hydrocarbon products,  or as occluded water in the solid residues.
Dirty water is cleaned  but  only for reuse and not for returning it to a
receiving water.  No waters  are returned to the receiving waters.   The totals
for wet-solid  residuals include the solid residue as well as the occluded
water in the  solid residue.
                                       156

-------
     In selecting the various process-site  combinations  for  study (Section 3),
we considered the following process criteria:  (a)  low  temperature gasifiers
and (b) high temperature gasifiers for converting  coal to pipeline gas,  (c)
coal refining to produce a de-ashed low sulfur solvent refined  coal and
liquefaction to convert coal to low sulfur  fuel oil  and  (d)  direct and indirect
surface retorting for converting oil shale  to synthetic  crude.   The results
are summarized by conversion technology, as shown  in Table 3-3,  as well  as by
the processes chosen to illustrate them.  In addition, the results are
presented by coal and oil shale region and  by coal rank  within  each region in
contrast to a breakdown by state, as was done in Section 3.   Table 5-1  shows
the sites comprising each major coal and oil shale bearing region.
Mining Rates
     The daily coal and oil shale mining rates for a standard size synthetic
plant are summarized in Table 5-2 for each  rank of coal  and  for high grade
shale with no distinction made between sites.  The coal  mining  rates vary  from
approximately 13,000 to 45,000 tons per day, reflecting  the  variation in the
heating value of the different rank coals, while from  73,000 to 105,000  tons
per day of oil shale are mined.  The daily mining  rates  are  also given per
unit of heating value in the product fuel enabling the results  to be scaled to
plant sizes different than the standard size plants.
     In Tables 5-3 and 5-4 the daily coal and oil  shale  mining  rates are given
by coal and oil shale region (Table 5-1). For a limited  number  of process-
region-coal rank combinations not covered in this  study, we  have used the
results given in Ref. 1.
Total Net Water Consumed
     Table 5-5 summarizes the total net water consumed for three different
cooling options for all of the conversion technologies and processes studied.
The range in the total water consumed reflects the variation with site.  The
three cooling options represent different levels of  wet  evaporative  cooling
which are used based on the availability and cost  of water.  Below we will
define more quantitatively the levels of cooling  (also see Appendix  7).  For
oil shale only intermediate cooling was considered.
                                       157

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     TABLE 5-1  STUDY SITES COMPRISING COAL AND OIL SHALE BEARING  REGIONS
    Coal Region

East and Central States

Appalachian
 Illinois
 Western States

 Four  Corners

 Powder River and Fort
  Union
   Coal Conversion

 Coal Rank


 Lignite
 Bituminous
 Bituminous
Subbituminous

Lignite
                              Subbituminous-
                               Bituminous
                                                             Site
Marengo,  Alabama
Jefferson,  Alabama
Floyd, Kentucky
Harlan, Kentucky
Pike, Kentucky
Ohio  (all sites)
Pennsylvania  (all  sites)
West Virginia  (all sites)

Illinois  (all sites)
Indiana  (all sites)
Mulhlenberg, Kentucky
New Mexico  (all  sites)
U.S. Steel  Chupp Mine, Montana
Coalridge,  Montana
East Moorhead, Montana
Otter Creek, Montana
Pumpkin Creek, Montana
North Dakota (all sites)
Colstrip, Montana
Decker, Montana
Foster Creek, Montana
Wyoming (all sites)
 Oil Shale  Region

Western States

Green River Formation
Oil Shale Conversion

    Shale


  High Grade
          Site
                                                  Parachute Creek, Colorado
                                 158

-------
                   TABLE 5-2  COAL AND OIL SHALE MINING RATES  FOR STANDARD SIZE SYNTHETIC FUEL PLANTS
                                              1000 tons/day
100 lb/10  Btu
Conversion Technology
Coal Gasification
Lurgi
Synthane
1
! Hygas
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC

Oil Shale
Paraho Direct
Paraho Indirect
TOSCO II
Lignite Subbituminous Bituminous

29.7-43.3 19.4-26.0 16.7-19.4
22.1-23.7 16.1-18.6

24.5-29.2 14.6-21.4 13.6-16.8
26.3-32.1 - 13.1-16.6

18.9-25.7 14.9-18.4

28.2-44.8 25.3-28.9 18.9-21.9
High Grade Shale

92
105
73
Lignite Subbituminous

2.5-3.6 1.6-2.2
1.8-2.0

2.0-2.4 1.2-1.8
2.2-2.7

1.2-1.7

1.8-2.8 1.6-1.8
Bituminous

1.4-1.6
1.3-1.6

1.1-1.4
1.1-1.4

1.0-1.2

1.2-1.4
High Grade Shale

6.3
7.2
5.0




•Jl
'•O

-------
                              TABLE 5-3  REGIONAL SUMMARY  OF COAL AND OIL SHALE MINING RATES



                              IN 1000 TONS PER DAY FOR STANDARD SIZE SYNTHETIC FUEL PLANTS

Coal Gasification
Lurgi
Syn thane
Hygas
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC
Oil Shale
Paraho Direct
Paraho Ind .
TOSCO II
Appalachian Region
Bituminous Lignite

16.2* 43.3
16.1-18.6
13.6-16.8 29.2
-

14.9-16.7

18.3* 44.8

-
-
-
Illinois Region
Bituminous

17.4-19.4
17.5-17.8
16.0-16.8
15.1-16.6

17.5-18.4

18.9-21.9

-
-
-
Powder R/Ft. Union Region
Subbituminous
-Bituminous Lignite

16.7-26.2 29.7-35.1
22.1-23.7 30.5*
15.4-21.4 24.5
13.1 26.3-32.1

24.7-25.7 31-6*

19.9-28.9 28.2-42.8

-
-
-
Four Corners
Subbituminous

19.4-26.0
25.9*
14.6-19.3
-

18.9

28.3*

-
-
-
Green River
Formation
Oil Shale

-
-
-
-

-

-

92
105
73
O
       *From  data in Ref. 1

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                            TABLE  5-4  REGIONAL SUMMARY OF COAL AND OIL SHALE MINING RATES



                  NORMALIZED WITH  RESPECT TO THE HEATING VALUE IN THE  PRODUCT FUEL IN  100 LBS/10  BTU

Coal Gasification
Lurgi
Syn thane
Hygas
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC
Oil Shale
Paraho Direct
Paraho Ind.
TOSCO II
Appalachian Region
Bituminous Lignite

1.4* 3.6
1.3-1.6
1.1-1.4 2.4
-

1.0-1.1

1.1* 2.8

-
-
-
Illinois Reqion
Bituminous

1.5-1.6
1.5
1. 3-1.4
1.3-1.4

1.1-1.2

1.2-1.4

-
-
-
Powder R/Ft. Union Region
Subbituminous
-Bituminous Lignite

1.4-2.2 2.5-2.9
1.8-2.0 2.5*
1.3-1.8 2.0
1.1 2.2-2.7

1.6-1.7 2.0*

1.2-1.8 1.8-2.7

-
-
-
Four Corners
Subbituminous

1.6-2.2
2.2*
1.2-1.6
-

1.2

1.8*

-
-
-
Green River
Formation
Oil Shale

-
-
-
-

-

-

6.3
7.2
5.0
o>
       *From data  in Ref. 1

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TABLE  5-5  SUMMARY  OF  NET WATER CONSUMED FOR STANDARD SIZE SYNTHETIC FUEL PLANTS

Coal Gasification
Lurgi
Syn thane
Hygas
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC
Oil Shale
Paraho Direct
Paraho Indirect
TOSCO II
Total Water Consumed (1Q6 gpd)
High Wet Intermediate Minimum
Cooling Cooling Practical Cooling
4-7 2-5 2-5
5-6 4 4
5-6 4-5 4-5
6 4 3_4
5-6 3-5 3-4
4-7 3-4 2-4
5
8
8
Total Water Consumed
High Wet Intermediate
Cooling Cooling
18-30 9-22
22-27 16-19
21-26 16-19
25-27 16-18
17-21 11-14
13-21 8-13
(gal/106 Btu)
Minimum
Practical Cooling
7-21
15-17
15-19
14-17
10-14
7-11
18
28
29

-------
     The  water requirements for standard size plants range from 4 to 7 x 10
                                                                6
gpd for coal gasification and coal refining and from 3 to 6 x  10  gpd for  coal
liquefaction;  the  range of net water consumed for oil shale conversion is
5 to 8 x  10   gpd.
     In order to explain the similarities and differences in net water consumed
between the  conversion technologies it is necessary to examine the totals  on a
regional  basis (Tables 5-6 and 5-7)-   As we have done previously, data from
Ref. 1 has been added for a limited number of cases.  We should note that  a
larger percentage  of the unrecovered heat in the Lurgi process is dissipated
by wet cooling in  Ref. 1 as compared to the present study, while for the SRC
process the  overall conversion efficiency is lower in the present study than
that assumed in Ref.  1, resulting in larger wet cooling loads.  However, the
data of Ref.  1 presents a useful data base for the present study.  Figures 5-1,
5-2 and 5-3  show a breakdown of the average net water consumption by region
and by process and for the three cooling options.   Four water use categories
are presented for  each coal conversion process in each region:  net process
water based  on reuse of all condensate; cooling water, flue gas desulfurization
water, if necessary;  and water for mining, dust control, solids disposal,
water treatment, revegetation and other uses.   For oil shale it is most
convenient to break down the water use categories in a slightly different way
to reflect the large quantities of water required for spent shale disposal:
net process  water  for retorting and upgrading; cooling water;  water for spent
shale disposal and revegetation; and water for dust control, mining and other
uses. For the cases where the net process water is negative (i.e., net water
is produced  in the process), the cooling water requirements can be obtained
from Figures 5-1,-2,-3 by adding the absolute value of the process water to
the cooling  water  component.
     Except  for the Hygas process, the net water consumed for the Four Corners
region is higher than for the other regions because of the larger amount of
water needed for dust control and the handling of ash for the high ash Navajo,
New Mexico coal. Water is required for revegetation in New Mexico because the
rainfall  is  less than 10 inches per year,- but is not required at any other
location.  For the Hygas process there are many competing demands which make
the above generalization invalid.
                                      163

-------
             TABLE  5  6     REGIONAL  SUMMARY  OF NET  WATER CONSUMED IN  1C)6  GPD  FOR STANDARD SIZE SYNTHETIC FUEL  PLANTS



Coal Gasification
Lurgi
Synth ane
Hyga«
Bigaa
Coal Liquefaction
Synthoil

Coa 1 re fining

Oil Shala
Paraho Direct
Paraho Indirect
TOSCO II
Appalachian
Bituminous
123
6.4' 5.7* 4.3*
5.2-5. 7 3.8-4.2 3.6-3. 9
5.6-6. 1 4.3-4.6 4.2-4. 5
5 5-6.4 3.9-4 7 3.6-4 4




Region
Lignite
123
4.3 2.1 1-7
5.0 3.7 3.5





Illinois Region
Bituminous
123
6.2-6.8 4.5-5.0 4.1-4.7
5.3-5.5 3.9-4.1 3.6-4.1
5.9-5.9 4.5-4.6 4.3-4.5
6.0-6.4 3.9-4.2 3.5-3.9
5 7-5 8 4 0-4 1 3 7-3 8




Powder River/Ft. Union
Subbit ominous -Bituminous
123
5.6-6.9 3.7-5.1 3.3-4.8
6.0-6.4 4.1-4.4 3.7-4.1
4.9-5.4 3.7-4.2 3.5-4.0
5.9 3.7 3.4
5 2-5 3 3 3—3 4 3031




Regions
Lignite
1 2 3
5.3-5.7 3.3-3.6 2.9-3.2
5.7* 3.5- 3.1*
5.0 3. a 3.6
6.3-6.5 4.2-4.3 3.9-4.0


4.9-6.5 2.9-3.7 2.5-3.1


Four Comers
Subbituminous
1 2 3
7.0-7.2 5.1-5.3 4.7-4.9
6.5* 4.1* 3.8'
5.4-5.5 4.2-4.3 4.0-4.1
6 0-6.7" 4.3-5.1* 4.0-4.8*

46* 34* 3.3*


Green Rivar
Formation
Oil Shale
2
-




5.1
8.2
8.3
1 • High Wet Cooling,  2 - Intermediate Wet  Cooling,  3 - Minimum Practical Met Cooling
•Data froo Ref. lj only applies  to particular numt>er and not range.

-------
                            TABLE 5-7  REGIONAL SUMMARY  OF NET WATER  CONSUMED  NORMALIZED



                        WITH RESPECT TO  THE HEATING VALUE IN THE PRODUCT  FUEL IN GAL/106 BTU

Coal Gasification
Lurgi
Syn thane
Hygas
Bigas
Coal Liquefaction
Syn thoil
Coal Refining
SRC
Oil Shale
Paraho Direct
Paraho Indirect
TOSCO 11
Appalachian Region
Bituminous
123
27* 24- IB'
22-24 16-17 15-16
23-26 18-19 17-19
18-21 13-15 12-14
11- 7* 6*

Lignite
123
18 9 7
21 16 15
-
21 12 11

Illinois Region
Bituminous
123
25-28 19-21 17-19
22-23 16-17 15-16
24-25 19-20 18-19
25-27 16-18 15-16
19 13 12
15-17 10-13 9-12

Powder River/Ft, union Regions
Subbituminous-Bituminous
1 2 3 .
23-29 15-21 14-20
25-27 17-19 16-17
21-23 16-18 15-17
24 16 14
17 11 10
13-15 8-9 7-8

Lignite
123
22-24 14-15 12-13
24* 15' 13*
21 16 15
26-27 18 16-17
19- 14- 13*
15-21 6-9 7-8

Four Corners
Subbi turn i nous
123
29-30 21-22 20-21
28' 18« 16*
23 18 17
20-22- 14-16' 13-16*
15* 11* 10*

Green River
Formation
Oil Shale
2
—
-
-
IB
28
29
1 = High Wet Cooling,  2 = Intermediate Wet Cooling, 3 = Minimum Practical Wet Cooling



• Data from Raf.  1; only applies to particular number and not range.

-------
   20
                                   ILLINOIS REGION
                                                                             APPALACHIAN REGION
                                                                             BITUMINOUS COALS
                                             APPALACHIAN REGION
                                               LIGNITE COALS
                                                                                                                     i
  -10
 2000 _
I
 1000 _
                                                  13 UUST CONTROL AND OTHER
                                                  E3 FLUE GAS DtSULFURIZATION
                                                  a COOLING
                                                  E3 NET PROCESS
1  - HIGH WET COOLING
I  - INTERMEDIATE WET COOLING
3  - MINIMUM PRACTICAL COOLING
                                                                    Vt'//
                                                                      2
                                                                                                                         i-3
-1000
                                                                                                                                                     -3
         LURGI
                    5YNTHANE
                                 HYGAS
                                            BIGAS      SYHTHOIL
                                                                    SRC
                                                                               SYNTHANE
                                                                                             HYGAS     SYNTHOIL
                                                                                                                     LURGI
                                                                                                                                 HYGAS
               Figure 5-1    Summary of average  net water  consumed  for  standard  size  coal  conversion  plants
                                              located  in  the Central  and  Eastern states
                                                                                                                                              SRC

-------
            1
                         POWDER RIVER AND FORT UII10N REGIONS
                               SUBBITUMJHOUS COALS
                                   POWDER RIVER AIID FORT UNION REGIONS
                                           LIGNITE COALS
                                                                                                  P3
                                                                                                  £
                                                                                                                                          V V"

                                                                                                                                          I
                                                                                                                                                  FOUR CORNERS
(T.
-J
     2000
             I
22 DUST CONTROL AND OTHER
E2J FLUE GAS DESULFURIZATION
D COOLING
Q NET PROCESS
1  - HIGH WET COOLING
2  - INTERMEDIATE WET COOLING
3  - MINIMUM PRACTICAL WET COOLING

                          1
              LURGI
                         SYNTHANE      HYGAS
                                                  BIGAS      SYHTHOIL
                                                                          SRC
                                                                                       LURGI
                                                                                                  HYGAS
                                                                                                               BIGAS
                                                                                                                           SRC
                                                                                                                                        LURGI
                                                                                                                                                     HYGAS      SYNTHOIL
                                      Figure  5-2    Summary  of  average net  water  consumed  for coal  conversion  plants
                                                                located in the Western states

-------
        3000 I—
        2000
GREEN RIVER FORMATION
OIL SHALE
1 - HIGH WET COOLING
2 - IIITERIEDIATE WET COOLING
_ 3 - MINIMUM PRACTICAL UET COOLING



-

\
&£

^
^
//
^

-1




^
//
//
46

!
-
-
-
-

        IOOOL  ^
             PARAHO   PARAHO   TOSCO
             DIRECT   INDIRECT   II
                                       Hs 5
                                                        20
                                                                 GREEN RIVER FORMATION
                                                                     OIL SHALE
                                                             E3 DUST CONTROL AND OTHER

                                                             £3 SPENT SHALE DISPOSAL

                                                             CD COOLING

                                                             E3 RETORTING AIID UPGRADING

                                                 PARAHO   PARAHO   TOSCO
                                                 DIRECT  INDIRECT    II
Figure  5-
3   Summary  of net water consumed for oil  shale conversion plants

              located  in  the Western  states

-------
     In the Illinois coal region, the average water  requirements  for  coal
gasification are relatively insensitive to the particular  conversion  process,
with the variation being no more than 15 percent  for the high  and intermediate
wet cooling options and no more than 25 percent for  the minimum practical  wet
cooling option.  The water required for coal gasification  is larger than that
for coal liquefaction which, in turn, is larger than that  for  coal refining.
The water requirements range from a low of 9 gal/10   Btu to a  high of 28
gal/10 Btu, greater by more than a factor of three.   In the Appalachian coal
region the water requirements  (normalized with respect to  the  heating value of
the product fuel) for coal gasification are higher than those  for coal liquefaction
for plants utilizing bituminous coal; for plants  utilizing lignite coal, the
water requirements for coal gasification are slightly lower than  those for
coal refining.  In the latter  case this can be attributed  to the  high moisture
content of the lignite coals and the very large quantities of  process water
produced in the Lurgi process.  The Lurgi process accepts  wet  coal and the
large quantities of dirty condensate produced are treated  for  reuse  (at a
cost) and are subtracted from  the process requirement.  We should also point
out that the net water consumed in the Synthane,  Hygas and Synthoil processes
is virtually identical in both the Illinois and Appalachian coal  regions for
bituminous coals.  However, the net water consumed in the  SRC  process is
higher for lignite coals than  for bituminous coals because of  the lower
conversion efficiency attributed to the larger quantity of energy required for
drying the higher moisture lignite coals prior to dissolution.  The slight
difference in the results for  the Hygas process is due to  the  different
process water requirements for lignite and bituminous coals.
     For each of the three basin-coal combinations in the  West, the net water
requirements are largest for coal gasification, followed in turn  by coal
liquefaction and coal refining (see Figure 5-2).  The larger requirement for
the Four Corners reqion is attributed to the high ash Navajo,  New Mexico coal.
In the Powder River and Ft. Union coal regions the average wet water  requirements
for the Lurgi, Hygas and Bigas processes are virtually identical  for  lignite
and subbituminous coals.  The  differences in the  SRC water requirements between
the lignite and subbituminous  coals are attributed to the  large difference
                                         169

-------
between the moisture content of the two coals.
     The net water requirements for the Synthoil and oil shale plants  can  be
compared since the products are roughly the same.  The water consumed  in the
Synthoil and Paraho Direct processes is about equal.  However, the water
consumed in the two indirect heated oil shale processes is 60 percent  higher
due mainly to the larger requirements for spent shale disposal and revegetation
     Differences in water consumption between the Illinois coal region and the
Powder River and Fort Union regions for subbituminous coals for a given coal
conversion process are relatively small, being no more than 15 percent with
the absolute difference being no more than 2.5 gal/10  Btu.  However,  for
lignite coals, differences between the Appalachian coal region and the Powder
River and Ft. Union regions are much larger,  the maximum being about 6 gal/10
Btu for the Lurgi process and 4 gal/10  for the SRC process, with the  Lurgi
water requirements being smaller in the Appalachian region and the SRC require-
ments being smaller in the Powder River and Ft. Union regions.
     In a particular coal bearing region, differences in the water requirements
for the four coal gasification processes that we have considered are due
principally to the differences in the process water requirement and the
differences in the estimated overall efficiency resulting in different cooling
water requirements.
Total Wet Solid Residuals Generated
     Solid residuals generated in coal and oil shale conversion plants  are
generally disposed of wet with occluded water.  Table 5-8 summarizes the total
wet solid residuals generated in the standard size plants with no distinction
made between sites, but with overall ranges given.   Also shown are the
residuals normalized with respect to the heating value in the product  fuel.
The principal residuals in coal conversion plants are coal ash, and where  flue
gas scrubbing is used,  the flue gas desulfurization sludge.  In the oil shale
plants the principal residual is the spent shale.  Sludges from water  treat-
ment plants have also been considered.   Between 3 to 15 x 103 tons/day  of wet
solids are disposed of  for coal gasification  plants, 1 to 4 x 1Q3 tons/day  for
coal liquefaction plants,  and from 2 to 6 x 1Q3 tons/day for coal refining
plants.   Outstripping all of the coal conversion residuals by an order  of
                                   170

-------
            TABLE -5-8  SUMMARY OF WET SOLIDS  RESIDUALS GENERATED FOR
                      STANDARD SIZE SYNTHETIC FUEL PLANTS

                                     Total Wet Solids
                              103 tons/day       Ib/lQ6 Btu
Coal Gasification
     Lurgi                       7-15           59 - 126
     Synthane                    5-7            40-56
     Hygas                       4-8            32-64
     Bigas                       3-7            27-61

Coal Liquefaction
     Synthoil                    1-4             7-28

Coal Refining
     SRC                         2-6            12-40

Oil Shale
     Paraho Direct                 76               520
     Paraho Indirect              104               630
     TOSCO II                      68               470
                                       171

-------
magnitude are those from oil shale processing where the primary  residual is
spent shale.
     The quantity of the residuals depends on: the ash content of  coal,  the
salt content of the source water, and the sulfur content of  coal when flue gas
desulfurization is used on coal-burning plant boilers.  The  maximum residuals
produced by each process depends on the site.  The largest quantities of
residuals for the Lurgi, Hygas and Synthoil processes occur  in those areas
having the highest ash coals, i.e., Jefferson, Alabama  (16.9% ash)  and El Paso
 (19.2% ash) and Wesco  (25.6% ash). New Mexico.  For the Synthane and SRC
processes the largest residuals are generated at those sites utilizing groundwater.
For the Bigas process the quantities of both ash and flue gas desulfurization
sludge determine the sites with the largest residuals.
     Tables 5-9 and 5-10 show the range of wet solid residual totals on a
regional basis, while Figures 5-4, 5-5 and 5-6 show a breakdown  of  the average
wet solid residuals by region and by process.  Three categories  are presented
for each coal conversion process:  ash sludge, flue gas desulfurization sludge,
if required, and water treatment sludge.  Only the category  of wet  spent shale
is shown for oil shale conversion.  Flue gas scrubbing is not required for the
Synthoil and SRC processes.
     In the Synthane process most of the ash produced is fly ash which is
handled dry, i.e. water is added to wet the ash equal to ten percent of  the
ash weight.  Except for the Synthane process, most of the ash that  is produced
is bottom ash which is sluiced with recycled sluice water.   The  thickened ash
slurry removed is 35 percent water.
     In the Illinois coal region for coal gasification, except for  the Lurgi
process, the wet solids generated are relatively insensitive to  process.   The
difference between the wet solids generated for the Lurgi process  and the
other three gasification processes is due to the large quantity  of  boiler feed
treatment wastewater required for the Lurgi process.  This will  be  explained
in the next section.   The total wet residuals normalized with respect to the
heating value of the product are comparable for the Synthoil  and  SRC processes,
with the SRC process having a slightly larger value.  The larger quantities of
wet residuals for coal gasification are attributed to the flue gas  desulfuriza-
tion sludge, which is not required for the liquefaction and  coal refining
processes.  The  only differences between the wet solids generated in the
                                    172

-------
                               TABLE 5-9  REGIONAL  SUMMARY OF TOTAL WET RESIDUALS  GENERATED


                                  IN 10  TONS/DAY FOR STANDARD SIZE SYNTHETIC' FUEL PLANTS

Coal Gasification
Lurgi
Syn thane
Hygas
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC
Oil Shale
Paraho Direct
Paraho Ind .
TOSCO II
___ 	 , —
Appalachian Region
Bituminous Lignite

3.5* 11.5
5.5-6.4
3.5-6.6 3.9
-

1.1-4.3

4.0* 3.7




Illinois Region
Bituminous

7.8-11.3
4.8-5.6
4.8-5.5
3.3-6.8

1.9-2.5

2.7-6.3




Powder R/Ft. Union Region
Subbituminous
-Bituminous Lignite

7.6-8.5 7.3-10.0
5.5-6.7 3.9*
3.8-5.5 4.2
3.6 4.1-8.3

3.3-4.0 5.3*

2.0-3.8 3.2-4.7




Four Corners
Subbituminous

7.1-15.1
7.0*
4.7-7.7
-

3.2-11.2*

13.7*




Green River
Formation
Oil Shale

-
-
-
-

—

-

76
104
68
-J
U)
       *Data from  Ref.  1; only applies  to  particular numbers and not  range.

-------
                       TABLE 5-10  REGIONAL SUMMARY OF TOTAL WET  RESIDUALS GENERATED



               NORMALIZED WITH RESPECT TO THE HEATING VALUE IN  THE  PRODUCT FUEL IN LBS/10  BTU

Coal Gasification
Lurgi
Syn thane
Hygas
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC
Oil Shale
Paraho Direct
Paraho Ind .
TOSCO II
Appalachian Region
Bituminous Lignite

29* 96
40-54
29-55 32
-

7-28

25* 23




Illinois Region
Bituminous

65-95
44-47
40-46
27-56

12-16

17-40




Powder R/Ft. Union Region
Subbituminous
-Bituminous Lignite

61-68 61-83
46-56 33*
32-46 35
30 34-69

21-26 34*

12-24 20-34




Four Corners
Subbituminous

59-126
59*
39-64
-

28-72*

19-86*




Green River
Formation
Oil Shale

-
-
-
-

-

—

520
630
470
*Data from Ref.  1 ;  only applies to particular number and not range.

-------
tn
         80
          60
          40
        1000
         600-
         SOD
         400
         200
               LURGI
                                 ILLINOIS REGIOIS
[1   FLUE GAS OESULFURIZATIOH SLUDGE

      ASH SLUUGE


      TREATMENT SLUDGE
                                                                              APPALACHIAN REGION
                                                                              BITUMINOUS COALS
                                                                         m
                                                                                   APPALACHIAN REGION
                                                                                     LIGNITE COALS
                       SYNTHANE
                                  HYGAS
                                            BIGA5
                                                   SYilTHOIL
                                                              SRC
                                                                        SYHTHAIIE
                                                                                  HYGAS
                                                                                          SYilTHOIL
                                                                                                       LURG1
                                                                                                                HYGAS
                         Figure 5-4    Summary  of  average wet-solid residuals  generated from

                   standard  size  coal conversion plants located  in Central and Eastern states

                                                                                                                        SRC
                                                                                                                                 12
                                                                                                                                 10
                                                                                                                                    o

                                                                                                                                 6   o

-------
100
 80
 60
 40
 20
                     POWDER RIVER AND FORT UNION REGIONS
                            SUBBITUHINOUS COALS
                                                              POWDER RIVER AND FORT UNION REGIONS
                                                                       LIGNITE COALS
                                                                                                                                FOUR  CORNERS
800
600
400
200
I    I   FLUE  GAS DESULFURIZATION SLUDGE

       ASH SLUDGE

       TREATItHT SLUDGE
                                                                                                                                                         10


                                                                                                                                                         8   3
       LURGI     SYNTHANE     HYGAS
                                        BIGAS      SYNTHOIL     SRC
                                                                            LURGI
                                                                                       HYGAS
                                                                                                  BIGAS
                                                                                                             SRC
                                                                                                                          LURGI
                                                                                                                                     HYGAS     SYNTHOIL
                           Figure  5-5    Summary  of  average  wet-solid residuals generated from

-------
                                      GREEN RIVER FORMATION
   8000
   6000
-  4000
   2000
             SPENT OIL SHALE
          PARAHO
          DIRECT
 PARAHO
INDERECT
                                    100
                                    80
                                    GO
                                    40
                                    20
TOSCO
  II
                                                     800
                               1  600
                                                     400
                                                     200
                                          1
                                                            1
PARAHO
DIRECT
 PARAHO
INDIRECT
TOSCO
  II
        Figure  5-6   Summary of  average wet  solid residuals generated from

         standard size oil  shale plants located  in the Western  states.

-------
Illinois coal region and those generated in the Appalachian coal region  can be
attributed to differences in the sulfur and ash content of the coals.
     In the Four Corners and the Powder River and Ft. Union regions,  coal
gasification generates the largest quantity of wet residuals with respect to
the heating value of the product fuel, followed in turn by coal liquefaction
and coal refining.   For the same processes there are no significant variations
with coal rank in the Powder River and Ft. Union coal regions except  for the
Bigas process; for Bigas the variation is due to the higher ash coals.   As
mentioned previously, the large quantities of wet solids generated in the Four
Corners region is due to the high ash content of the Navajo coal.
     A comparison of the total wet residuals generated in the Illinois coal
region and the Powder River and Ft. Union regions (subbituminous coals)  show
that they are comparable, as are the results for the Appalachian region  and
the Powder River and Ft. Union coal regions for lignite coals.  However,  there
are some differences between the three categories of sludges.  In general
water treatment sludges in the Western states are larger than those for  the
Eastern and Central states, while the reverse is true for flue gas desulfuriza-
tion sludges.
5.2  Process Water Requirements
     Figures 5-7 and 5-8 show the quantity of steam and boiler feed water
required for the conversion process, the amount of dirty and intermediate
quality condensate coming out of the process, and the net process water  consumed.
The raw water source must be treated to produce the high quality steam and
boiler feed water required for the process, while the dirty and intermediate
quality condensate must be treated for reuse since disposal is not practical,
requiring cleaning before disposal to meet environmental regulations.
Methanation water for the process is reused without any treatment.  This
process water is not shown on the figures.  Neither are quench water  for the
Synthoil process and dirty water input for Bigas, which do not require treatment.
     Large quantities of steam and boiler feed water and dirty condensate must
be treated in the Lurgi process, although net process water may be produced in
the process.   The Lurgi process accepts wet coal, resulting in large  quantities
of dirty condensate.   In general the low temperature coal gasification processes
require more costly treatment than either the coal liquefaction and coal
refining processes.   High temperature gasification processes do not require
extensive water treatment because the process condensate is of relatively
                                        178

-------
      2500
      2000 _
      1500 -
      looo
       500 -
      -500 .


-


-
—


p
^

E3 STEAM AND BOILER FEED WATER REQUIRED
_.



I
52
&
1
B
sX
$
-
E3 DIRTY AND INTERMEDIATE QUALITY CONDENSATE
H3 NET PROCESS WATER CONSUMED



$

I
i



„

._,„ HIGHEST



1
1
FLOW
LOWEST
FLOW
li \
pi
8
1
X
—
_ p
;!;;: ^^s; ^§:::? ^» N
I li
in
                                                                                            -  7
                                                                                            _  6
                                                                                            _  3
                                                                                            -  2
                                                                                            _  1
              LURGI
                        SYNTHANE
                                    HYGAS
                                               BIGAS
                                                        SYNTHOIL
                                                                    SRC
PARAHO  PARAHO  TOSCO
DIRECT INDIRECT  II
Figure  5-7  Range  of process  water flows for standard  size  synthetic  fuel  plants

-------
30


20



t—
cn
I 	 i <^j
CD °
i ,0
0
-10


-




-






Z
/,
'/
y.

//
I
0







-i;



STEAM AND BOILER
FEED WATER REQUIRED _
El DIRTY AND INTERMEDIATE QUALITY CONDENSATE
m


NET PROCESS WATER CONSUMED










^_>_HIGHEST

'y

\




^



~


LURGI SYNTHANE









i
VALUE


:



LOl
VA



JEST
LUE


HYGAS





\
~~



j
1


-

} pmiL

B "

BIGAS SYNTHOIL SRC PARAHO PARAHO TOSCO
DIRECT INDIRECT H
Figure 5-8  Range of process water flows in gal/10  Btu

-------
good quality.  Process requirements for the Synthane plants  are  less  than
those  for Hygas plants because the Synthane process makes char  and passes
more coal through the gasifier. This makes more hydrogen  available from  coal.
     The summary of process water flows are shown for each coal  region in
Figures 5-9 and 5-10.  The net water consumed for the Hygas, Bigas and Synthane
processes are relatively independent of site.  Figure 5-11 shows that the net
process water consumed in the Lurgi process is a function of the moisture
content of the coal.  For the Synthoil and SRC processes, the net process
water consumed is a function of both the moisture and oxygen contents of the
coal (Figures 5-12, 5-13 and 5-14).  The highest process water requirement  is
in the Appalachian region which has the lowest oxygen content coals and  the
lowest requirement is in the Powder River and Fort Union  regions.  In the SRC
process when hydrogen is produced from very moist coals, principally  lignite,
without predrying the coal, the net process water will be less than that
indicated by the oxygen content (Figure 5-13).  The process water consumption
or production in the oil shale plants relate directly to  the amount of water
produced in the retort itself.
5.3  Cooling Water Requirements
     The cooling water consumed in coal conversion processes comprises the
largest percentage of the total water requirements.  Three cooling options
were considered representing different kinds of wet evaporative cooling for
turbine condensers and gas-compressor interstage coolers.
     At a site where water is plentiful and inexpensive to transport, high wet
cooling should be used.   The cooling loads on both the turbine condensers and
interstage coolers are taken to be all wet cooled.  For the Lurgi process a
detailed thermal balance is not available: wet cooling is assumed to  be used
to dispose of 33 percent of the total unrecovered heat.  The same value was
one estimated for the Synthane process to facilitate comparison.  This value
falls within the range of Lurgi design data.  The El Paso  design indicates
that 36 percent of the unrecovered heat is dissipated by evaporative  cooling
                      4
while the Wesco design  indicates 26 percent.  In regions where water is
marginally available or moderately expensive to transport, intermediate
cooling should be used.   Intermediate cooling assumes that wet cooling handles
10 percent of the cooling load on the turbine condensers and all of the  load
of the interstage coolers (Appendix 7).   For the Lurgi process 18 percent
                                       181

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  2500
  2000
  1500
2 ,000
   soo
ILLINOIS REGION



—


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_ Rl DIRTY AND INTERMEDIATE QUALITY
• •*x
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E3 NET PROCESS WATER CONSUMED


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COALS







APPALACHIAN REGION ~
LIGNITE COALS






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         LURGI
                   SYNTHANE
                               DIGAS
                                         HYGAS
                                                  SYNTHOIL
                                                             SRC
                                                                        SYNTHANE
                                                                                   HYGAS
                                                                                             SYNTHOIL
                                                                                                         LURGI
                                                                                                                    HYGAS
                                                                                                                               SRC
                               Figure 5-9   Summary of  average  process  water  flows  for standard  size
                                       fuel plants  located in the Central and Eastern states.

-------
  2000
o 1000
  500
  -500  -
FOUR CORNERS






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^
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LIGNITE COALS






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POWDER RIVER-FORT UNION REGIONS
SUBBITUHINOUS COALS
E2 STEAM AND BOILER FEED WATER REQUIRED
El DIRTY AND INTERMEDIATE QUALITY COMPENSATE _
E3 NET PROCESS WATER CONSUMED



\
\


1
1
—
I ®
L J I

                                                                                                                                                 _ 8
          LURGI
                     HYGAS
                              SYNTHOIL
                                          LURGI
                                                     BIGAS
                                                               HYGAS
                                                                         SRC
                                                                                     LURGI
                                                                                               SYHTHANE     BIGAS
                                                                                                                    HYGAS
                                                                                                                             SYIITHOIL
                                                                                                                                        SRC
                                Figure 5-10   Summary of average process water flows for standard size
                                                synthetic fuel plants located in  the Western states.

-------
      400
      200 L
 CO
ro
 o
 I/O
 LiJ
 O
 O
 01
 CL.
-200 L
 P   -400
      -600
     -800
    -1000
                      10
                            20           30

                      MOISTURE CONTENT  (PERCENT)
40
          Figure 5-H  Net process water consumed in  Lurgi  process.

           (from calculations of Appendix 6 for specific  coals).
                                       184

-------
                                                     OXYGEN CONTENT
                                                           8
10
12
                  400
                  300
              CQ
             ro
              O
              UJ
              O
              O
              Q:
              Q-

              o
                  200
CO
Ln
                  100
                                                           T
                                                                        _L
                                               10          15          20

                                               MOISTURE CONTENT  (PERCENT)
            25
14
                                                                                                       o
                                                                                                       Q.
                                                                                                      VO
                                                                                                       O
                          0.5
             30
                               Figure 5-12  Net process water consumed in Synthoil process

                                 (from calculations of Appendix 2 for specific coals).

-------
CD
CTl
               CO
              ro
               O
GO
UJ
<_)
O
C£
o.

o
I—

I—
UJ
                     200
                     100
-100
                   -200
                   -300
          MOISTURE CONTENT

              o   <  30 %


              •   >  30 %
                                                 6            8          10

                                                  OXYGEN CONTENT (PERCENT)
                                                                 12
                                                                                                   0.5
                                                                                                         ID
                                                                                                          O
                                                                                                   -0.5
                                                                                                   -1.0
                                                                                                   -1.5
                                                                                  14
                           Figure 5-13  Net process water  consumed  in SRC  process - variation  with

                             oxygen content  (from  calculations  of Appendix 1 for specific coals).

-------
CD
                         200
                         100  U
                     a:
                     zc

                     CO
                    CO
                     o
                     LTl
                     oo
                     _
                     O
                     a:
-100
                         -200
                         -300
     hOXYGEN CONTENT

         o   <  9 %


         •   ^  9 %
                                         10
                             20           30           40

                                MOISTURE  CONTENT (PERCENT)
50
                                                                                                       1.0
                                                                                                       0.5
                                                                                     a.
                                                                                     o

                                                                                    ID
                                                                                     o
                                                                               -0.5
                                                                                                       -1.0
                                                                                                       -1.5
60
                                   Figure  5-14  Net  process  water  consumed  in  SRC process - variation

                              with moisture content (from calculations of Appendix 1 for specific coals).

-------
of the unrecovered heat is dissipated by wet cooling.  Again,  this  is  based on
Synthane process estimates.  The oil shale processes are assumed  to use an
intermediate degree of wet cooling. For the Paraho Direct process,  28  percent
of the unrecovered heat is dissipated by wet cooling.  For the Paraho  Indirect
and TOSCO II processes 18-19 percent is dissipated.
     In regions where water is expensive to transport or scarce,  minimum
practical cooling should be used.  Minimum practical wet cooling  assumes that
wet cooling dissipates 10 percent of the cooling load on the turbine condensers
and 50 percent of the load in the interstage coolers  (Appendix 7).   For this
case the Lurgi process is assumed to dissipate about 15 percent of  the unrecovered
heat by wet cooling.  Again it is based on the estimates for the  Synthane
process.
     The degree to which wet cooling should be used is determined by the cost
of water.  If water costs more than about $1.50 per 1000 gallons  minimum
practical cooling should be used.  Intermediate cooling should be used if the
water cost is between $0.25 per 1000 gallons and $1.50 per 1000 gallons,  while
high wet cooling should be used if water costs less than $0.25 per  1000
gallons  (Appendix  7).
     For a given size coal conversion plant the quantity of water consumed by
cooling mainly depends on the overall conversion efficiency and the  percent of
unrecovered heat dissipated by wet cooling.  All of the unrecovered  heat not
dissipated by wet cooling is lost directly to the atmosphere while the rest of
the heat is transferred to the atmosphere by direct cooling.   As  discussed
above, the choice depends on the availability and cost of water.  Table 5-11
lists the range of conversion efficiency for each conversion process as well
as the percent of unrecovered heat dissipated by wet cooling.  For the  SRC
process the low conversion efficiency corresponds to plants sited at Marengo,
Alabama and Coalridge, Montana where the feed coals are lignites  having high
moisture contents.   The low conversion efficiency is the result of  large
quantities of energy required for coal drying.   The conversion efficiencies
for all of the coal gasification processes are comparable, while  those for
coal liquefaction and coal refining are also comparable, but slightly  higher
                                       188

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                   TABLE 5 -11   OVERALL CONVERSION EFFICIENCY AND
               PERCENT UNRECOVERED HEAT DISSIPATED BY WET COOLING
 Coal Gasification
     Lurgi
     Synthane
     Hygas
     Bigas
                             Overall
                            Conversion
                            Efficiency *
                             (Percent)
65-67
65-73
65-74
66-70
                   Percent Unrecovered Heat
                   Dissipated by Wet Cooling
                                         Minimum
                High Wet  Intermediate  Practical
                Cooling     Cooling      Cooling
  33
30-33
23-35
40-46
  18
15-18
13-20
20-21
  15
12-16
11-17
16-17
 Coal Liquefaction
     Synthoil
72-79
44-54
25-36
22-33
 Coal Refining
      SRC
59-82
34-51
18-33
15-30
 Oil Shale
     Paraho Direct
     Paraho Indirect
     TOSCO II
 71
 57
 68
              28
              19
              18
*(Heat content of product  fuel plus  combustible  byproducts)/(Heat  content  of
  coal or oil shale)
                                        109

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    80
    70
S   HIGH WET COOLING

E3   INTERMEDIATE WET COOLING

O   MINIMUM WET COOLING
    60
    50
£   40
    30
    20
    10
                                                             HIGHEST
                                                        —,— VALUE
                                                            .LOWEST
                                                             VALUE
/
          LURGI
                     SYNTHANE
                                  HYGAS
                                             BIGAS
                                                        SYNTHOIL
                                                                      SRC
                                                                PARAHO
                                                                DIRECT
 PARAHO   TOSCO
INDIRECT    IF
         Figure 5-15   Percent  of  unrecovered heat  removed by wet cooling.

-------
than  those  for coal gasification.  We should note that the  conversion  effici-
encies  for  coal liquefaction may be a little high because not  all  of the
energy  loads  were considered in the SRC designs of Appendix 2.   The conversion
efficiency  for the Paraho Direct process is comparable to that for coal
gasification.  The percent of unrecovered heat dissipated by wet cooling for
coal  liquefaction and coal refining are also comparable and, in general,
higher  than that for coal gasification (Figure 5-15).  The  fraction of heat
used  to evaporate water in the indirect oil shale processes is somewhat lower
than  the direct process.   This may be explained by the fact that in the
indirect heated retorting process part of the unrecovered heat is  lost up  a
furnace stack,which is not lost that way in the direct processes.
     Figure 5-16 shows the range of water consumed by cooling  for  standard
size  synthetic fuel plants;  the same data is shown normalized  with respect to
the heating value in the  product in Figure 5-17.   The maximum  difference in
water consumption between high wet cooling and minimum practical cooling for
the processes taken as a  whole is about 10 gal/10  Btu.  The SRC process shows
the largest difference between the highest and lowest value of  cooling water
consumed for  a given cooling option.
     Figures  5-18 and 5-19 show the average water consumed  by  cooling in each
of the  regions considered.   For each process, the average water  consumed is
relatively  insensitive to the coal bearing region and variations for a given
cooling option from site  to site within the region are expected  to be small
for all of  the processes  except for possibly the SRC process,  as discussed
above.   However, within a given region there might be large variations in
water availability and water costs,- and different cooling options at different
sites will  produce large  differences in the cooling water consumed and the
plant water requirements.
5.4  Other  Water Requirements
     In this  category we  include the water requirements for  flue gas scrubbing,
ash or  spent  shale disposal, dust control, water treatment  wastewaters and
other needs.   The methods for estimating these quantities are  given in
Appendices  8,  9, 11 and 12.
     The largest single factor in the water requirement for  flue gas scrubbing
is the  moisture content of the coal or char fed to the boilers.  For this
reason  the  flue gas requirement is greatest for the coals from  the  Appalachian
                                     191

-------
3000
           ED
HIGH WET COOLING

INTERMEDIATE WET COOLING

MINIMUM WET COOLING
2000
1000
             GHEST VALUE
        LURGI
                   SYNTHANE
                              HYGAS
                                         BIGAS
                                                    SYNTHOIL
                                                                SRC
                                                                         PARAHO   PARAHO
                                                                         DIRECT  INDIRECT
                                                                       TOSCO
                                                                        II
                Figure  5-16   Cooling water consumed by evaporation

                      for standard size synthetic  fuel plants.

-------
30
20
^o
tVJ   HIGH WET COOLING

E3   INTERMEDIATE WET COOLING

[3   MINIMUM WET COOLING
/
                                                                   — HIGHEST
                                                                     VALUE
                                                                   .LOWEST
                                                                   VALUE
                                                                 I?
        LURGI
                  SYNTHANE
                               HYGAS
                                           BIGAS
                                                     SYNTHOIL
                                                                  SRC
                                                                 PARAHO  PARAHO   TOSCO
                                                                 DIRECT INDIRECT    II
  Figure  5-17  Cooling  water consumed by  evaporation  in  gals/10  Btu.

-------
  2000
   1500
° 1000
   500
                           ILLINOIS AND APPALACHIAN REGIONS
               [2   HIGH WET COOLING
               &   INTERMEDIATE HET COOLING
               E3   MINIMUM WET COOLING
     LURGI
Figure  5-
Illinois
   GREEN RIVER
    FORMATION
                                                                                                    85
                                                                                                   i£>
                                                                                                 3  2
                    SYNTHANE
                               HYGAS
                                         BIGAS
                                                    SYIITHOIL
                                                                SRC
PARAHO   PARAHO   TOSCO
DIRECT  INDIRECT    11
                18   Average cooling water consumed for  coal  conversion in  the
                and Appalachian coal regions  and  consumed for oil shale conversion
                              in the Green River Formation.

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                     2000
                      1500
<£>
                  «   1000
                       500
                        0
                                                  POWDER RIVER-FORT UNION REGIONS
                                   E2  HIGH WET COOLING




                                   E)  INTERMEDIATE WET COOLING




                                   O  MINIMUM WET COOLING
                              LURGI       SY1ITHANE      HYGAS       BIGAS       SYHTHOIL





                         Figure  5-19  Average  cooling  water  consumed for
                                                                                                               FOUR CORNERS
  SRC             LURGI       HYGAS       SYHTHOIL





coal conversion in the Western  states.

-------
and Four Corners regions which are relatively low in moisture.   In all
Synthane plants dry char is fed to the boiler making the scrubbing water
requirements high.  Coal is not fed to the boilers in the Solvent  Refined Coal
and Synthoil designs considered.
     The water required for ash disposal, dust control and other needs cannot
be readily generalized because of the many competing factors.   However,  the
water requirements for the Four Corners region are higher than  for the other
four regions because of the high ash coal and the revegetation  requirement.
The water requirements for the disposal of spent shale and subsequent  revege-
tation differs considerably between processes, depending on  the operator's
assumption about the amount of water necessary to properly dispose of  the
spent shale.  In the proposed TOSCO II design it is assumed  that the addition
of water to the spent shale leads to cementation of the shale after compaction
while in the proposed Paraho designs the spent shale is simply  compacted dry.
The water consumption for the Paraho design is mainly for revegetation whereas
in the TOSCO II design it is in large part for compaction.
     The largest quantity of water treatment wastewaters are consumed  in the
Lurgi process because of the large steam and boiler feed water  requirements.
Generally the wastewaters for all of the other conversion processes do not
exceed one percent of the total water consumed except where  the feed water is
a hard well or brackish groundwater where the wastewaters may exceed about
five percent.
5.5  Residuals
     In coal conversion plants the residuals include coal ash,  flue gas,
desulfurization sludges where flue gas scrubbing is used, and water treatment
sludges.  In the oil shale plants the principal residual is  the spent  shale.
The methods for estimating these quantities are given in Appendices 8, 9,  11
and 12.
     In the four coal gasification processes, coal or char is burnt to raise
steam in a boiler.  The furnaces are assumed to be a dry bottomed  pulverized
coal type with 80 percent of the ash as fly ash and 20 percent  as  bottom ash.
As occurs in some 65 percent of the power generating stations today, fly ash
is assumed to be handled dry;  that is, water is added to wet the ash equal to
ten percent of the ash weight.   Furnace bottom ash is assumed sluiced  (as it
usually must be)  with recycled sluice water.   The thickened  ash slurry removed
is 35 percent water.   All ash from all coal conversion reactors is assumed
handled with the bottom ash.   The water evaporated to quench gasifier  ash is
included in the wet cooling load of the various processes.   In  the Synthane
                                         196

-------
process all of the ash from the gasifier enters the boiler where it is fired

with 80 percent of the ash leaving as fly ash and 20 percent as bottom ash.

This ash is handled as discussed above.

     Flue gas desulfurization sludge is not generated for the coal liquefac-

tion and coal refining processes.  For the four coal gasification processes

the flue gas desulfurization sludge is related directly to the sulfur content

of the coal, being highest in the Eastern and Central states and lowest in the
Western states.


References - Section 5

1.   Probstein,  R.F.  and Gold, H.,  Water in Synthetic Fuel Production -
     The Technology and Alternatives, MIT Press, Cambridge, Mass. 1978.

2.   Goldstein,  D.J.  and Yung, D.,  "Water Conservation and Pollution Control
     in Coal Conversion Processes," Report No. EPA-600/7-77, Environmental
     Protection Agency, Research Triangle Park, N.C., June 1977.

3.   Gibson, C.R., Hammons,  G.A. and Cameron, D.S., "Experimental Aspects of
     El Paso's Burnham I Coal Gasification Complex," in Proceedings, Environ-
     mental Aspects of Fuel Conversion Technology (May 1974, St. Louis, Missouri)
     pp. 91-100,  Report No.  EPA-650/2-74-118  (NTIS PB 238304), Environmental
     Protection Agency, Research Triangle Park, N. C., October 1974.

4.   Berty, T.E.  and Moe, J.M., "Environmental Aspects of the Wesco Coal
     Gasification Plant," in Proceedings, Environmental Aspects of Fuel
     Conversion Technology (May 1974, St. Louis, Missouri), pp. 101-106,
    / Report No.  EPA-650/2-74-118 (NTIS PB 238304, Environmental Protection
     Agency, Research Triangle Park, N.C., October 1974.
                                        197

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                             6.   CONTROL TECHNOLOGY
6.1  Water Treatments
     In the preceding section we have summarized the quantities of net water
consumed and wet solid residuals generated by conversion technology and by
coal and oil shale region.   In making these estimates we have assumed that no
water streams leave the mine-plant boundaries and that all effluent streams
are recycled or reused within the mine or plant after any necessary treatment.
These streams include the organically contaminated waters generated in the
conversion process, which are unfit for disposal without treatment, and the
highly saline water blown down from evaporative cooling systems.  Water is
only released to evaporative ponds as a method of salt disposal when the usual
inorganic concentration of released wastes is about two percent (for example,
ion exchange regeneration wastes and cooling tower blowdown when more than 10
cycles of concentration are used and less than 10 percent of the intake water
is released).  We have generally assumed that these wastes are disposed of
with the coal ash.  The rest of the water consumed leaves the plant as vapor,
as bonded hydrogen (after hydrogenation) in the hydrocarbon product and as
occluded water in the solid residues.  The water treatment plants are not
designed to return flow to receiving waters.  Returning water to a source is
not economic when the water must be cleaned to a quality equal to or better
than the source water to meet environmental constraints.  All wet solid
residuals must be disposed of in an environmentally acceptable manner.  Toxic
and soluble organic materials must be destroyed and toxic heavy metal salts
must be converted to insoluble forms.  Soluble inorganic sludges and toxic
residuals from the coal ash or spent shale must be contained in disposal sites
to prevent leaching into drinking water sources.
     In this section we will summarize the individual water treatment blocks
and water flow diagrams, each applicable to one or more processes at many
                                        198

-------
sites.   The estimated costs and energy requirements of  the water  treatment
section of each process-site combination will also be summarized.   Detailed
calculations for each plant-site combination are found  in Appendix  11, while
the background information on the water treatments used is found  in Refs.  1
and 2.   We have not selected the means of disposal of the wet  solid residuals
nor have we estimated their costs.   This was beyond the  scope  of  the  study. We
have also not considered the costs  of water treatment for shale oil conversion.
     The cost and energy estimates  for water treatment  are much less  well
defined than the water quantities.   Although the water  treatment  technologies
considered are achievable,  the experimental evidence for coal  conversion
process waters is not available to  fully assess them.  For this reason designs
and costs must be regarded with a greater degree of uncertainty than  the estimates
of water quantity requirements.   Furthermore, because of the large  number of
plant-site combinations,  we could not, within the limitations  of  the  study,
look at all of the various  water treatment options for each plant-site
combination.    Instead we have used one or two water flow diagrams, each
applicable to one or more processes at many sites.   The  water  treatment plants
are designed to prevent water streams from leaving the mine-plant boundaries
and to  recycle and reuse  all effluent streams within the mine  or  the plant.
The costs and energy requirements for disposal are not  included in  this study.
For example,  the costs of evaporation ponds used to hold highly saline blowdown
waters  have not been estimated.
     In any synthetic fuel plant high quality water is  required for the process,
intermediate quality is required for cooling, and low quality for disposal and
mine uses.   Figure 6-1 is a simplified water reuse scheme which assumes that
the effluent from the process is of low quality and insufficient to meet all
of the  plant's cooling needs.   The  process condensate for the  liquefaction
and coal refining processes and for the low temperature  coal gasifiers is
quite dirty.   The process condensate for the Hyga;; high  temperature gasifier
is of intermediate quality; clean condensates are produced from the Dygas
process.   The scheme further assumes that the raw water  supplied to the plant
is from a fresh water source and of medium quality.   If  the source of supply
were of poor quality and  expensive, as from a brackish groundwater aquifier,
                                       199

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                            FROM
                                             TO
O
o
                       FRESH WATER
                           SOURCE
 MED.
QUALITY
                          PROCESS
  LOW
QUALITY
             TREATMENT
              TREATMENT
 HIGH
QUALITY
                                                                       I T TV   ^^
  MED
DUALITY
                PROCESS
                COOLING
                          COOLING
                                                         LOW
                                                       QUALITY
                                          DISPOSAL
                                           & MINE
                            Figure  6-1  Simplified water use diagram  (Reprinted from

                            Ref.  2  with the permission of The MIT Press. Copyright

                              1978 by  the  Massachusetts Institute of Technology).

-------
it might be economical to take the medium quality water  resulting from treating
the dirty process stream and feed it back for treatment  to  high  quality boiler
feed water.
     Figure 6-2 is an amplification of Figure 6-1 and represents a general
water treatment scheme for a coal conversion plant generating  dirty process
water.   The scheme is not unique, but does contain the main components of any
water treatment plant:  boiler feed water preparation, process water or
condensate cleanup,and cooling water treatment.  The three  main  streams are shown with
heavy lines.   Figure 6-3 shows the water treatment block diagrams used for all
of the processes.   Details are given in Appendix 11.
     Boiler feed water preparation includes occasional lime soda softening,
electrodialysis on all plants when the raw intake water  is  brackish,  and ion
exchange.  Three different ion exchange schemes have been chosen based on the
quality of the intake water.   The cost of ion exchange depends on the  quantity
and quality of the intake water, which are usually site  dependent,  and on the
pressure of the steam raised in the boiler.  All of the plants use  a lot of
high pressure steam for driving machinery, but this condensate is returned
with less than 2 percent loss.   The largest requirement  for boiler water
makeup is for steam which enters into the conversion reactions.   The Lurgi,
SRC and Synthoil plants require low pressure steam, while the  Hygas, Bigas  and
Synthane require higher pressure steam.  The Lurgi process  requires  the  most
steam,  followed by the Hygas and Synthane processes which require  comparable
amounts, and then by the Bigas process which requires the least  boiler  feed
water for coal gasification (Figures 5-7 and 5-8).   The SRC and  Synthoil
processes require little steam.  In some cases reverse osmosis is used  to
return  treatment condensate to the boiler in those Lurgi plants  where  all of
the condensate is not required in the cooling tower.  This  is  followed  by
activated carbon adsorption.   It may be necessary for the carbon bed to precede
reverse osmosis so as to prevent membrane fouling,  but the  arrangement  shown in
Figure  6-3B is preferable because it reduces the load on the carbon.
     Foul condensate treatment includes phenol extraction,  ammonia separation
and biotreatment.   Phenol extraction, involving solvent extraction of phenolic
compounds in which phenol is recovered and sold to help defray the costs.
                                      201

-------
                                 RAW WATER

r
i
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C RESERVOIR ^V*-EVAPORATION

•^
r
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•>
r
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POTABLE
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TREATMENT ^ 	 J
r
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^ ' ^^ -^
(SERVICE AND A
SANITARY I
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r
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ER J

r 1 ~1
	 v T t
1 FVAPORATiriN i ( i ( DUST A ' FLUE GAS ^
I L Vrtrutvi 1 1 urt 1 1 ni^POSAI / 1 rmnTnrti ] t
Figure 6-2  Water treatment flow diagram for coal conversion plant
 generating dirty process water (dashed boxes indicated  the require-
  ments are not necessary for every plant).  (Reprinted from Ref.  3
    with the permission of The MIT Press.  Copyright  1978 by the
               Massachusetts Institute of Technology).
                            202

-------
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Ul


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26
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TnnnTTn-Jl'^' 39 31 > SdFTFNFR 1
'ORATION)"' -15 ' Nn , |
C ASH ^ V
^ DISPOSAL J SLUDGE
                                                                        Streams are numbered for identification
                                                                                                                            RAW WATER
                                                                                                                                          EVAPORATION
                                                                                                                 WASTE
                                                                                                  (REVEGETATION)
                                                                                                   /"SERVICE s ~\
                                                                                                   ^ANITARY USE  J
                                                                                                     ^EVAPORATION
                                    H&ter treatment plant block diagram for all Synthane,

                                          some Lurgi and all Hygas.
                                                                                                                     B.  Water  treatment plant

                                                                                                                     Block diagram for some  Lurgi.
                                                                                                                                             (continued)
                                                            Figure 6-3   Water  treatment block  diagrams.

-------
                                          Streams are  numbered for identification
                                                                                            RAW WATER



C RESERVOIR y23-* EVAPORATION
21
24
as
1
POTABLE WATER
TREATMENT
"


3

[SOFTENING NO.I (i^SLUDGE
L
n
4
5
~~ BOILER FEED
TREATMENT :±> HA<
FIG. 11-2
M Is
34 CONDE
POL1S
NSATE
HING
I7

PROC
ESS j
C SERVICE 1 ) |«
SANITARY USE J \ 	 «u>.m.i» 	 1

PACKAGE
SEWAGE PLANT

JO
35

(EVAPORATION/
TE
SEPAWmON h^^ONIA

39 ,

10
11
15
14
32 /" roniiNG >
V TOWER V
J/.
/
39
^ 	 r 3»

13
C" ASH "^
^DISPOSAL J
37
TB 17
2jS SLUDGE
	 it

)
30

— J— — -. (EVAPORATION
NO. 3 ~*^



y*
BOILER FEED
TREATMENT -Jls
FIG. 11-2 ~^
.

CONDENSATE
POLISHING

7
> HASTE
*f PROCESS 1
PHENOL
£ XJRACT ' nN
"
.'
AMMONIA _<
SEPARATION
.

? * BIOTRE
19 r

10
ATMENT -


| FILTER |
35


31
14
ING A
ER J
39
»• PHENOL
* AWONIA
> SLUDGE
,.
/" DUST "
yCONTROL^
f ASH A
^ DISPOSAL J




C. Water treatiaent plant bloclc diagram
            for Bigas process.
D.  Hater treatment block diagram for Synthoil process.

                            (continued)
                             Figure  6-3  (continued)

-------
                            Streams are numbered for identification

                            Flow rates ore given in Appendix 11
RAW WATER
                                                                                              EVAPORATION
KJ
O
Ln
                                                                                                               SLUDGE
                                                                       £.   Hater treatment blocX diagram
                                                                        for SRC process.
                                                                       Figure  6-3  (concluded)

-------
is used only when the foul condensate is highly concentrated.   The  process was
not used for Lurgi or Synthane plants fed by bituminous  coal,  nor was it used
for Hygas and Bigas.   Ammonia separation, used for all process-site combinations
is a distillative, extractive process, where the ammonia is  assumed recovered
as a 30 wt % solution and sold to help defray costs. Because of the lack  of
information on how much organic contamination is acceptable  in cooling  water,
biotreatment is used, when extraction is not used, on dirty  condensate  from
all plants except Bigas.
     Cooling water treatment involves lime soda softening of the raw water for
cooling tower makeup, filtration of the effluent water from  biotreatment,  acid
treatment of all high alkalinity cooling water makeup streams,  the  addition of
biocide anticorrosion chemicals and suspending agents, and lime soda softening
of the cooling tower blowdown.  Potable water treatment  is just chlorination;
the quantity is low and the cost is treated as zero.
     We have also made some assumptions in considering specific conversion
processes. Since so much of the ash is removed from Synthane plants as  dry fly
ash, not enough cooling tower blowdown can be disposed of with the  ash  to
control the tower.  To maintain the concentration in the  circulating cooling
water at 10 cycles, blowdown is removed, softened and used as  makeup to the
flue gas desulfurization scrubber.   All Synthane plants  are  shown on Figure 6-
3A.  Higas plants use the same flow scheme as Synthane.  Because of moisture
in the coal, many Lurgi plants yield more treated condensate than is required
in the cooling tower.  These plants use flow diagram Figure  6-3B.   When all
the condensate is consumed in the cooling tower, the same flow diagram  as
Synthane is used  (Figure 6-3A).  In selected plants, and as  required, cooling
tower blowdown in addition to that used for ash handling is  taken to maintain
10 cycles of concentration.  Figure 6-3C applies to all Bigas  plants and to no
others.  In some plants, fresh water or softened tower blowdown is  used for
dust control and FGD makeup because there is not enough  condensate.   Where
necessary the tower is blown down to maintain 10 cycles.
     Synthoil plants take in large amounts of quench water into the hydrogen
production train and put out large amounts of condensate.  Figure 6-3D  applies
                                       206

-------
to all Synthoil plants, and on  this  figure Stream  33  is  the  net  of input minus
output water to the hydrogen plant.  Furthermore,  all cooling  towers are blown
down at 10 cycles to Stream 33.   In  doing this we  have assumed that the
inorganic salts dissolved in the  quench water are  removed with fly ash somewhere
beyond the point of quench and  do not accumulate in the  system.   If the plant
were not designed this way, or  if this were not possible, then the quench
water would have to be of boiler  feed quality with hydrogen  plant condensates
returned through a polishing demineralizer.  Figure 6-3E is  used for all SRC
plants.  Condensate from the hydrogen plant is usually softened  before use as
makeup to the cooling tower.   The treated organically contaminated Stream 14
is small and with little organic  matter in the cooling tower the  blowdown is
used for dust control as well as  ash disposal.  Tower cycles of  concentration
sometimes reach as high as 14;  when high cycles are used, the  makeup is
softened to ensure satisfactory operation.
6.2  Costs
     Table 6-1 summarizes the range of water treatment costs for  standard size
plants for each of the conversion processes.  The costs  are  also  shown  in
C/10  Btu °f product heating value.  For each process, except  Bigas,  the  largest
water treatment cost corresponds  to the case where brackish water  is  used as  a
raw water source and reflects the large costs of boiler  feed water treatment
associated with demineralization.  The highest cost for  the Bigas process  is
for a lignite coal in North Dakota and reflects the high cost  of process
condensate treatment by ammonia separation.   It is clear that  the  highest  cost
for any process is for Lurgi because the quantities of steam required and
dirty condensate produced are greater than those for any of the other processes.
The costs of water treatment for  the other coal gasification processes  are
comparable and are determined by  the costs of both boiler feed water  treatment
and condensate treatment.   The  lowest costs are those for the  coal liquefaction
and SRC processes.   Although the process condensates for these processes  have
the worst quality,  the costs  are  determined primarily by the quantities of
process condensate produced and boiler feed water required, which  are quite
low for the Synthoil and SRC processes.   If the cost of  the product  fuel  is
about $2-3/10  Btu,  the water treatment charge, after taking credit  for
byproduct ammonia,  is one which is not likely to exceed  7 percent  of  the  sale
price of the product fuel for any of the plants.
                                      207

-------
     Table 6-2 is  a  regional  summary  of  the costs of water treatment in C/10
Btu.   In most of the  cases  the  range  of  water costs in each region is quite
narrow, except for some  unusual cases.   For example, as we have pointed out
above, the largest costs  are  incurred when brackish water is used as the water
source.  This is particularly true  for the Lurgi and SRC processes in the
Illinois coal region; the Synthane, Hygas  and SRC processes in the Powder
River-Ft. Union regions  for subbituminous  coals; and the SRC process in the
Powder River-Ft. Union regions  for  lignite.  In the Powder River-Ft.  Union
regions, the Lurgi plant  at Kemmerer, Wyoming requires treatment of the return
treatment condensate  to  the boiler  by reverse osmosis and carbon adsorption,
increasing the costs  substantially.   The cost of phenol extraction at the
Lurgi  plant at Wesco, Four  Corners  and some Synthoil plants in Ohio and Kentucky
is  quite high.

                   TABLE  6-1  SUMMARY  OF WATER TREATMENT COSTS
                    FOR STANDARD SIZE SYNTHETIC FUEL PLANTS

                              $/hr            $1000/day           C/10  Btu
Coal Gasification
     Lurgi
     Synthane
     Hygas
     Bigas

Coal Refining
     Synthoil               55 -  129         1.3-3.1          0.4-1.1

Clear  Coal
     SRC                    60 -  220         1.5-5.2          0.4-1.6

     A summary of the average costs of water  treatment  in  a given region  is
shown  in Figures 6-4 and 6-5.   These results  indicate  that  the  costs  of
cooling water treatment are quite low and  that  the  costs  of condensate  treat-
ment in general  exceed those of  boiler feed treatment.   However,  there  are
530 -
170 -
230 -
160 -
1400
430
410
280
12.
4.
5.
3.
6 -
0 -
5 -
8 -
33.
10.
9.
6.
1
2
9
6
5.
1.
2.
1.
3 -
7 -
3 -
6 -
14.
4.
4.
2.
0
3
1
8
                                       208

-------
                    TABLE 6-2   REGIONAL SUMMARY  OF THE COST OF  WATER TREATMENT IN SYNTHETIC  FUEL PLANTS

                                                           IN C/106 BTU

Coal Gasification
Lurgi
Syn thane
Hygas
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC
Appalachian Region
Bituminous Lignite

12.5
1.87-3.00
2.31-2.75 2.89-2.95
-

0.33-0.55

1.16-1.42
Illinois Reqion
Bituminous

9.80-13.80
1.64-2.83
2.35-2.77
1.79-1.89

0.59-0.60

0. 57-1.42
Powder R/Ft. Union Region
Subbituminous
-Bituminous Lignite

6.70-8.70 8.40-8.60
2.91-4.26
2.65-4.13 2.66
1.57 2.52-2.81

0.65-0.70

0.67-1.53 1.00-1.64
Four Corners
Subbituminous

5.40-7.30
-
2.94-3.64
-

1.05

-
M
C

-------
M
M
O
                   14
                   12
                   10
               2   8
                   2 —
                                          ILLINOIS REGION
TREATMENT
 tI  COOLING WATER

 W77\  COHDEIJSATE

       BOILER FEED
                                                                                 APPALACHIAN REGION
                                                                                 BITUMINOUS COALS
                                                                                   APPALACHIAN
                                                                                  LIGNITE COALS
                        LURGI     SYNTHANE    HYGAS     BIGAS    SYNTHOIL   SRC
                                                                             SYNTHAHE     HYGAS    SYNTHOIL     LURGI  .   HYGAS
                                                                                                                              SRC
                            Figure 6-4  Regional summary of  the average costs of water  treatment
                                       (C/10  Btu in  product)  in coal conversion  plants
                                          located in  the Central and Eastern  states.

-------
   12
   10
o  8
                  POWDER RIVER-FORT UNION REGIONS
                      SU8BITUHINOUS COALS
TREATMENT
  [	]  COOLING WATER

        CONOENSATE

        BOILER FEED
                                                          POWDER RIVER-FORT UNION REGIONS
                                                                LIGNITE COALS
                                                                                                              FOUR CORNERS
         LURGI
                 SYNTHANE
                           HYGAS
                                    BIGAS
                                             SYNTHOIL   SRC
                                                                LURGI
                                                                         HYGAS
                                                                                   BIGAS
                                                                                             SRC
            Figure  6-5   Regional summary of  the  average  costs of  water  treatment
                         (C/10  Btu in product)  in  coal conversion plants
                                   located  in the Western states.
                                                                                                       LURGI     HYGAS    SYilTHOIL

-------
some situations in which the opposite is true and generalizations are
difficult to make because of many competing demands.   Nevertheless,  comparison
of Figures 6-4 and 6-5 with the process flow quantities  in Figures 5-9 and 5-10
give some indication of the strong dependence of the  costs on flow rate.
6.3  Energy Requirements
     The energy requirements for water treatment in standard size synthetic
fuel plants are shown in Table 6-3.  The energy requirements are  also shown as
a percent of the product energy.  The largest energy  requirements for any
conversion process are for the Lurgi process, followed by  the three  other
gasification processes, which are comparable.  Again,  the  coal liquefaction
and coal refining processes have the lowest energy requirements.  For all of
the processes, the energy required for the water treatment plants is controlled
by the amount needed for ammonia separation, which is  directly proportional to
the rate of production of foul condensate.   Therefore  the  largest energy

          TABLE 6-3 SUMMARY OF THE ENERGY CONSUMED IN WATER TREATMENT
                    IN STANDARD SIZE SYNTHETIC FUEL PLANTS

                                6                7             Percent Product
                              10  Btu/hr       10  Btu/day        Energy	
Coal Gasification
     Lurgi                    230 - 830         550 -  1980        2.3 - 8.3
     Synthane                 130 - 220         310 - 520         1.3 - 2.2
     Hygas                    100 - 400         240 - 950         1.0 - 4.0
     Bigas                    170 - 300         410 - 720         1.7 - 3.0

Coal Liquefaction
     Synthoil                   5-80           12 - 190         0.039 - 0.62
Coal Refining

     SRC                       16 - 130           38 - 310        0.12 - 0.96
                                     212

-------
requirements generally  correspond  to  those  plant-site combinations that
produce the most foul condensate.  For  Lurgi  this  would be at Marengo,  Alabama
(lignite coal); for Bigas, at Slope,  North  Dakota  (lignite coal);  for Synthoil,
at Lake-de-Smet, Wyoming  (subbituminous  coal);  and for SRC,  at Coalridge,
Montana (lignite coal).   The highest  energy requirements  for the  Synthane and
Hygas processes are at Antelope Creek, Wyoming where  the  raw water is brackish
and electrodialysis is  used to treat  the boiler feed  water,  requiring large
amounts of energy.   The  total energy  requirements  for the  water treatment
plants fall in the  range of 0.04 to over 8 percent  of the  product  energy, or
about 0.03 to 6 percent  of the energy in the feed coal.
     Table 6-4 shows  the energy consumed by region.   As mentioned  above,  the
principal variations  are due  to the variations in the process  condensate
produced,  with some variations due  to the raw water quality.
     Figure 6-6 and 6-7  present the average energy requirements by  region for
all of the processes.  Most of the  energy requirements are for process  condensate
treatment with very little  for boiler feed water treatment and none for
cooling water treatment.   The  energy  requirements for boiler feed water treat-
ment are for treatment of the  raw water  by electrodialysis and treatment  of
the process condensate for  return to  the boiler in those Lurgi plants where
all of the condensate is  not required in the cooling tower.  Table 6-5 shows
representative  values of  the energy required for the three different process
condensate treatments as  a  percentage  of the total energy required for process
condensate treatment.  It is clear  that  ammonia separation is the  largest
energy consumer in  water  treatment.
References - Section  6
1.    Goldstein,  D.J. and  Yung,  D.,  "Water Conservation and Pollution Control
     in  Coal  Conversion  Processes," Report No.  EPA-600/7-77,  U.S.  Environmental
     Protection Agency,  Research  Triangle Park,  N.C.,  June 1977.
2.    Probstein,  R.F. and  Gold,  H.,  Water in  Synthetic  Fuel Production  -  The
     Technology and Alternatives, The  MIT Press,  Cambridge, Mass.,  1978.
                                       213

-------
TABLE  6-4   REGIONAL SUMMARY  OF  THE ENERGY CONSUMED IN WATER TREATMENT




           IN  SYNTHETIC FUEL  PLANTS IN PERCENT  OF  PRODUCT ENERGY

Coal Gasification
Lurgi
Syn thane
Hygas
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC
Appalachian Region
Bituminous Lignite

8.3
1.3-1.5
1.1 1.0
-

0.039-0.22

0.68-0.72
Illinois Region
Bituminous

6.8-7.9
1.3-1.5
1.1
1.7-2.0

0.22-0.29

0.12-0.39
Powder R/Ft. Union Region
Subbituminous
-Bituminous Lignite

2.3-4.8 6.0-6.6
1.8-2.2
1.0 1.0
1.8 2.7-3.0

0.62

0.32-0.68 0.62-0.96
Four Corners
Subbituminous

3.7-5.2
-
1.0
-

0.46

-

-------
       TABLE 6-5  .ENERGY REQUIRED FOR WATER  TREATMENT AS A PERCENTAGE OF
        THE TOTAL ENERGY REQUIREMENTS FOR PROCESS  CONDENSATE TREATMENT
                              Phenol         Ammonia
                            Extraction      Separation       Biotreatment
Coal Gasification
     Lurgi                       35              60                 5
     Synthane                                    80                20
                                                95                 5
                                35              60                 5
     Hygas                                       95                 5
                                35              60                 5
     Bigas                                      100

Coal Liquefaction
     Synthoil                    30              50                20

Coal Refining
     SRC                         30              50                20
                                      215

-------
NJ
h->
cn
               UJ    .
               a.    4
                                         ILLINOIS REGION

                                      CONDENSATE TREATMENT

                                      BOILER FEED TREATMENT
                                                          V//A
APPALACHIAN REGION
BITUMINOUS COALS
                                                                                               &77A
APPALACHIAN REGION
  LIGNITE COALS
                         LURGI
                                SYNTHAHE
                                           HYGAS
                                                   BIGAS   SYHTHOIL
                                                                   SRC
                                                                            SYIITHANE
                                                                                       HYGAS
                                                                                              SYHTHOIL
                                                                                                          LURGI
                                                                                                                   HYGAS
                      Figure 6-6   Regional  summary of the  average energy  consumed for water treatment
                       in percent of  the heating value of  the product fuel  in  coal conversion plants
                                           located  in the Central  and Eastern  states.
                                                                                                                            SRC

-------
            POWDER RIVER-FORT UNION.REGIONS
                 SUBBITUMINOUS COALS
       W7A CONDEHSATE TREATMENT

       R$ffXi BOILER FEED TREAT1ENT
POWDER RIVER-FORT UNION REGIONS
      LIGNITE COALS
                                                                                                    FOUR CORNERS
LURG1    SYNTHANE    HYGAS     BIGAS    SYIITHOIL     SRC        LURGI      HYGAS     BIGAS     SRC        LURGI
   Figure 6-7   Regional summary  of the average  energy consumed for  water treatment
    in percent of  the  heating value of the  product fuel in coal conversion plants
                                located in  the Western states.
                                           HYGAS
                                                   SYHTHOIL

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                         7.   GENERALIZATION OF RESULTS

7.1  Process-Coal Combinations
     In Table 7-1 we have summarized the results presented in Sections 5 and
6 by conversion process with no distinction made between coal rank except for
the mining rates.  The results have been normalized with respect to the
heating value of the product.  In Table 7-2 we have summarized the results by
coal rank and process; the results are shown graphically in Figure 7-1.  The
difference in mining rates is due to the variation in the heating values of
the different rank coals and the different conversion efficiencies of the
processes considered.
     In general the net water requirements are largest for coal gasification,
followed by coal liquefaction and coal refining. The difference between the
last two processes is relatively small.  The differences in net water consumption
as a function of coal rank are small, except for the Lurgi process where the
smallest requirement is for the wet lignite coals.  The Lurgi process accepts
wet coal and the large quantities of dirty condensate produced are treated for
reuse and are subtracted from the process requirement.  For intermediate wet
cooling the water requirements for the Paraho Direct process are comparable
with the Synthoil process, which roughly produces the same product.  However,
the Paraho Indirect and TOSCO II processes have the largest net water requirements
due mainly to the larger requirements for spent shale disposal and revegetation.
     The maximum difference in water consumption for coal gasification between
high wet cooling and minimum practical wet cooling, with no distinction made
between site and gasification process, is about a factor of four, pointing up
the importance of the choice of process and cooling design in the amount of
water consumed in synthetic fuel production.  The maximum difference in water
consumption between high wet cooling and minimum practical wet cooling at a
given site is approximately 10 gal/10  Btu.  Minimum practical wet cooling
will be used if water is relatively expensive, that is about $1.50/1000 gal or
more.  Even so, minimum practical cooling will cost about 1.5C/106 Btu more
than high wet cooling because of the higher annual capital costs of dry cooling
systems.

                                       218

-------
               TABLE  7-1   SUMMARY OF RESULTS  BY CONVERSION PROCESS

Coal Gasification
Lurgi
Synth ana
Hygss
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC
Oil Shale
Paraho Direct
Paxaho Ind.
TOSCO II
Reactor Type

Fixed Bed
Fluid Bed
Fluid Bed
Hydrogasif i«r
Entrained Flow

Catalytic Fixed
Bed

Dissolver
Direct Retorting
Indirect Retort.
Indirect Retort.
£
Mininq Rates (lb/10 Btu)
Subbi-
Lignite tuminous Bituminous

250-360 160-220 140-160
250s 180-220* 130-160
200-240 120-180 110-140
220-270 - 110-140

120-170 100-120
t
180-280 160-180 110 -140
High Grade Shale
630
720
510
6
Net Hater Consumption (aal/10 Btu)
High Wet Intermediate Hin. Practical
Cooling Wet Cooling Wet Cooling

18-30 9-22 7-21
22-27 16-19 15-17
21-26 16-19 15-19
25-27 16-18 14-17

17-21 11-14 10-14

13-21 8-13 7-11
18
28
29
Wet Solid
Residuals
(lb/10 Btu)

59-126
40-56
32-64
27-61

7-28

12-40
520
630
470
Hater Treatm^ni-
Cost
(C/106 Btu)

5.4-14.0
1.7-4.3
2.3-4.1
1.6-2.8

0.3-1.1

0.7-1.6



Energy
(\ Prod. Energy)

2.3-8.3
1.3-2.2
1.0-4.0
1.7-3.0

0.04-0.6

0.1-1.0



Data from Ref. 1.  Refers only to number and not to range.

-------
        TABLE 7-2   SUMMARY  OF RESULTS BY  CONVERSION PROCESS



                 AND COAL RANK OR GRADE OF OIL SHALE
                                  LIGNITE COAL

Coal Gasification
Lurgi
Syn thane
Hygas
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC
Mining Rate
(lb/106Btu)

250-360
310*
200-240
220-270

200*

180-280
Net Water Consumption (gal/10 Btu)
High Wet Intermediate Min. Practical
Cooling Wet Cooling Wet Cooling

18-24 9-15 7-13
24* 15* 13*
21 16 15
26-27 18 16-17

19* 14* 13*

15-21 8-12 7-11
Wet Solid
Residuals
(lb/106 Btu)

61-96
33*
32-35
34-69

34*

20-34
Water Treatment
Cost
(C/106 Btu)

8.4-12.5

2.7-3.0
2.5-2.8



1.0-1.6
Energy
(» Prod. Energy)

6.0-8.3

1.0
2.7-3.0



0.6-1.0
                                SUBBITUMINOUS COAL

Coal Gasification
Lurgi
Eyn thane
Hygas
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC
Mining Rate
(lb/106Btu)

160-220
180-200*
120-180


120-170

160-180
5
Net Water Consumption (gal/10 Btu)
High Wet Intermediate Min. Practical
Cooling Wet Cooling Wet Cooling

23-30 15-22 14-21
25-28* 17-19 16-17
21-23 16-18 15-17


17-22* 11-16* 10-16*

14-21* 8-11* 7-10*
Wet Solid
Residuals
(lb/106 Btu)

59-126
46-59
32-64


21-72*

19-86*
Water Treatment
Cost
(C/106 Btu)

5.4-7.5
2.9-4.3
2.7-4.1


0.7-1.1

0.9-1.5
Energy
(* Prod. Energy)

2.3-5.2
1.8-2.2
1.0-4.0


0.5-0.6

0.5-0.7
"Data from Jtef.  1.  Refers only to number and not to range.
                                        220

-------
TABLE 7-2  (continued)
                                             BITUMINOUS COALS



Coal Gasification
Lurgi
Syn thane
Hygas
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC

Mining Rate
(lb/106Btu)
140-160
130-160
110-140
110-140
120-170
160-180
Net Water Consumption (gal/10 Btu)
High Wet Intermediate Kin. Practical
Cooling Wet Cooling Wet Cooling
25-29 19-21 17-20
22-23 16-17 15-16
23-26 18-20 17-19
24-27 16-16 14-16
18-21 13-15 12-14
13-17 8-13 7-12
Wet Solid
Residuals
(lb/106 Btu)
65-95
40-54
29-55
27-56
7-28
12-40

Cost
(C/106 Btu)
9-14
1.6-3.0
2.3-2.8
1.6-1.9
0.3-0.6
0.6-1.4

Energy
(% Prod. Energy)
5-8
1.3-1.5
1.1
1.7-2.0
0.04-0.3
0.1-0.4



Oil Shale

Paraho Direct

Paraho Indirect

TOSCO II

Mininq Rate
(lb/106Btu)


630

720

510
Net Water Consumption (gal/10 Btu)
Intermediate Minimum
Wet Cooling







Wet Solid
Residuals

(lb/10 Btu)





470

                                                   221

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NJ
M
NJ
                             30
                             60
                             40-
                             20.
                             300
                        °    200
                            100
                                                                                    WET SOLID RESIDUALS
COAL MINED
                                 P^sSJ LIGNITE COAL

                                 E£8£j SUBS I TUMI NOUS COAL

                                 |    | BITUMINOUS COAL
                                           LURGI
                                                             SYNTHANE
                                                                                  HYGAS
                                                                                                   BIGAS
                                                                                                                    SYIITH01L
                                                                                                                                         SRC
                                                     Figure 7-1   Summary  of  process-site  results

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                                                800
                                                                                           OIL SHALE
                                                                   MINED
                                                                                                       WET SOLID RESIDUALS
tv)
U)
                                                700
                                                600
                                                500
                                                400
                                                300
                                                200
                                                 100
                                                           PARAHO    PARAHO    TOSCO
                                                           DIRECT   INDIRECT    II
PARAHO
DIRECT
 PARAHO
INDIRECT
TOSCO
 II
                                                                             Figure  7-1.  (continued)

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NJ
      30









      25










 e    20
 CO

to
 o

 ^


 3    15








      10
                                            LIGNITE COALS



                                            SUBBITUMIHOUS COALS



                                       I    | BITU1IHOUS COALS
TOTAL NET HATER CONSUMED



    HIGH WET COOLING

                                               LURGI
                                                                   SYNTHANE
                                                                                         HYGAS
                                                                                                            BIGAS
                                                                                                                             SYNTHOIL
                                                                                                                                                     SRC
                                                                        Figure 7-1  (continued)

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30
25
20
15
]0
Rv\
-------
to
M
                                      12
                                      10
                                       2  _
                                                                                   ENERGY FOR WATER TREATMENT
                                                                                    COST OF WATER TREATMENT
                                                                                                                                   LIGNITE COALS


                                                                                                                                   SUBBITUHIHOUS COALS


                                                                                                                                   BITUMINOUS COALS
                                                 LURGI
                                                                   SYHTHAHE
                                                                                        HYGAS
                                                                                                           BIGAS
                                                                                                                           SYNTHOIL
                                                                                                                                                SRC
                                                                           Figure  7-1  (concluded)

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     As we have pointed out in Section 5, the largest quantities  of  wet  solid
residuals for the Lurgi, Hygas and Synthoil proccesses occur  in areas  with the
highest ash coals.  For the Synthane and SRC processes the  largest residuals
are generated at sites utilizing groundwater since large  amounts  of  wastewater
from the boiler feed water treatment plants must be disposed  of.  For  the
-Bigas process, the quantities of both ash and flue gas desulfurization sludge
determine the sites with the largest residuals.
     The highest cost of water treatment is for the Lurgi process because  the
quantities of steam required and dirty condensate produced  are greater than
those for any of the other processes.  The costs of water treatment  for  the
other three processes are comparable and reflect the sum of the costs  of
boiler feed water treatment and dirty process condensate treatment.  The
lowest costs are for the coal liquefaction and coal refining processes because
of the small quantities of process condensate produced and  boiler feed water
required, although these condensates have the worst quality of any of  the
other processes.  The variation in cost between coal rank is small,  except
when brackish water is used as a raw water source.
     The energy requirements for water treatment, in general, follow the same
trend as the costs of water treatment.   For all of the processes the energy
required for the water treatment plants is controlled by the amount  needed for
ammonia separation, which is directly proportional to the rate of production
of foul condensate.
7.2  Process-Site Combinations
     A breakdown of the results by conversion technology and for each  coal and
oil shale region was presented in Section 5 and 6.  In Sections 4 and  5 we
specified the cooling option that would be most suitable in a given  region.,
based on the availability and/or cost of water at a particular site.    In the
East and Central regions we have picked the cooling option  based on  the
availability of water, since in general the cost of transporting water in
these regions is very low because of the close proximity of the coal conversion
plant to the water source (Riparian Doctrine).  Figures 4-2 and 4-3  shows
those areas where water is plentiful, marginally available  and scarce; the
results are generally valid for both low water demand where approximately one
                                       227

-------
or two standard size coal conversion plants are located in each  one  of  the
coal regions/ and high water demand, where approximately  1x10  barrels/day  of
                                                          T "?
synthetic crude,.or its equivalent in other fuels of 5.8x10  Btu/day  are to  be
produced in each one of the coal regions.
     In the Western region the cooling option is based on the  cost of  transport-
ing water.  For low water demand, Figure 4-11 shows that  except  for  plants
located near the main stem of the major rivers, intermediate cooling would  be
used for a large majority of sites in the Upper Missouri  Basin and the  Four
Corners region.  In general we could extend this result to the Upper Colorado
Basin. For high water demand, 1x10  barrels/ day of synthetic  crude, or its
equivalent in other fuels, are produced in each of the three principal  coal
bearing regions: Ft. Union, Powder River and Four Corners;and  in the principal
oil shale region, Green River Formation.  The water requirements for each of
the drainage subareas within a coal or oil shale region have been divided
equally.  Figure 4-12 shows the cost of transporting water to  some of the
major coal producing regions.  Here again, except for large scale development
near the main stem of the major rivers intermediate or minimum practical
cooling would be desirable for most of the regions.
     Table 7-3 shows the range in total net water consumption  for intermediate
and minimum practical cooling as a percentage of the total net water consumption
for high wet cooling.  The numbers in parentheses are the averages for  all  of
the sites for a given conversion process.  For coal gasification and liquefaction
the total net water consumption with intermediate wet cooling  is  about  72
percent of the total net water consumption for high wet cooling,  and 66 percent
with minimum practical wet cooling.   The percentages for  coal  refining  are  63
and 56 percent, respectively. The cost and energy for water treatment are
relatively insensitive to the degree of wet cooling.
     The average total net water consumed for all the processes  is shown in
Table 7-4 in 10  gpd for standard size plants and in gal/106 Btu.
                                      228

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     TABLE 7-3  TOTAL NET WATER CONSUMPTION FOR INTERMEDIATE AND MINIMUM
            PRACTICAL WET COOLING AS A PERCENTAGE OF TOTAL NET WATER
                         CONSUMPTION FOR HIGH WET COOLING

                                    Intermediate       Minimum Practical
                                    Wet Cooling           Wet Cooling
Coal Gasification

     Lurgi                            0.63-0.74             0.55-0.68
                                       (0-71)                 (0.65)
     Synthane                        0.68-0.74             0.62-0.70
                                       (0.72)                 (0.67)
     Hygas                            0.74-0.79             0.72-0.76
                                       (0.77)                 (0.74)
     Bigas                            0.64-0.68             0.58-0.62
                                       (0.67)                 (0.60)
Coal Liquefaction

     Synthoil                        0.64-0.73             0.58-0.70
                                       (0.71)                 (0.65)
Coal Refining

     SRC                              0.56-0.72             0.47-0.68
                                       (0.63)                 (0.56)


7.3  Large Scale  Synthetic Fuel Production

     In this  section results are presented  for a  synthetic  fuel production
level of 1x10  barrels/day of synthetic crude,  or its  equivalent in  other
               12
fuels of 5.8x10   Btu/day.  Table 7-5  lists the number of standard size plants
required to produce 5.8x10   Btu/day  for the  conversion  technology and product
output indicated.  The range is from  18 clean  coal plants each producing
10,000 tons/day of solvent refined coal to  24  coal gasification plants
producing 250x10  scf/day of pipeline  gas.  For coal gasification the low and
high ends of the range were derived using the  high and low values in Table 7-1
for  all four gasification processes.

References - Section 7

1.   Probstein, R.F. and Gold, H., Water in Synthetic  Fuel Production -
     The Technology and Alternatives,  MIT Press,  Cambridge, Mass. 1978.
                                       229

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                                TABLE 7-4  TOTAL NET WATER  CONSUMED BY  CONVERSION PROCESS
            Coal  Gasification
            Coal  Liquefaction
            Coal  Refining
            Oil Shale
              Direct  Retort
              Indirect  Retort
High Wet
Cooling
5.8
5.9
5.1


6
10 gpd
Intermediate Min. Practical
Wet Cooling Wet Cooling
4.1 3.8
4.3 4.0
3.2 2.9
5.3
8.4
High Wet
Cooling
24
19
16


gal/10 Btu
Intermediate
Wet Cooling
17
14
10
18
29
Min. Practical
Wet Cooling
16
13
9


U)
O
                   TABLE 7-5  NUMBER OF  STANDARD  SIZE PLANTS  REQUIRED  TO  PRODUCE  1  x 10   BARRELS/DAY
                                                                               12
                              OF  SYNTHETIC  CRUDE  OR ITS EQUIVALENT  OF  5.8 x  10   BTU/DAY
                         Conversion
                         Technology
                     Coal gasification
                     Coal liquefaction
                     Coal refining
                     Oil shale
       Product
Unit Output
   Number of
Standard Size Plants
     Pipeline gas    250 x 10  scf/day       24
       Fuel oil      50,000 barrels/day      19
Solvent refined coal 10,000 tons/day         18
    Synthetic crude  50,000 barrels/day      20

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TABLE 7-6  SUMMARY OF RESULTS FOR  THE  PRODUCTION OF 1 X 10  BARRELS/DAY




       OR ITS EQUIVALENT IN OTHER  FUELS  OF  5.8 x 10   BTU/DAY


Coal Gasification
Coal Liquefaction
Coal Refining

Oil Shale
Mining Rates (1000 tons/day)
Subbi-
Lignita tuminoua Bituminous
580-10.10 350-640 320-460
350-490 290-350
520-810 460-520 320-410
High Grade
1480-2090
Net Water Consumption (10 gal/day)
High Wet Intermediate Kin. Practical
Cooling Wet Cooling Wet Cooling
100-170 50-130 40-120
100-120 60-80 60-90
75-120 50-75 40-65

100-170
Wet Solid
Residuals
(1000 ton/day)
80-360
20-80
35-115

1360-1830
Water 1
Cost
(5103/day)
93-810
20-70
40-90


"reatment
Energy
(1010 Btu/day)
5-50
0.3-3
0.6-6



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                                TECHNICAL REPORT DATA
                          (Please read Instructions on the reverse before completing)
1. REPORT NO.
 EPA-600/7-78-197a
                                                       3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE Water-related Environmental Effects
in Fuel Conversion: Volume I.  Summary
                                 5. REPORT DATE
                                  October 1978
                                 6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)

Harris Gold and David J. Goldstein
                                                       8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Water Purification Associates
238 Main Street
Cambridge,  Massachusetts  02142
                                  10. PROGRAM ELEMENT NO.
                                  EHE623A
                                  11. CONTRACT/GRANT NO.

                                  68-03-2207
 12. SPONSORING AGENCY NAME AND ADDRESS
 EPA, Office of Research and Development
 Industrial Environmental Research Laboratory
 Research Triangle Park, NC 27711
                                  13. TYPE OF REPORT ANQPE
                                  Final; 10/76 - V/8
                                                                         RIOD COVERED
                                 14. SPONSORING AGENCY CODE
                                   EPA/600/13
 15. SUPPLEMENTARY NOTES jjERL-RTP project officer is Chester A.  Vogel, Mail Drop 61,
 919/541-2134.
 is. ABSTRACT
              repOrj- gives results of an examination of water-related effects that can
be expected from siting conversion plants in the major U.S.  coal and oil shale bearing
regions. Ninety plant-site combinations were studied: 48 in the Central  and Eastern
U.S. and 42 in the Western. Synthetic fuel technologies  examined include: coal gasifi-
cation to convert coal to pipeline gas; coal liquefaction to convert coal to low sulfur
fuel oil; coal refining to produce a de-ashed, low-sulfur solvent refined (clean) coal;
and  oil shale retorting to produce synthetic crude. Results presented include the range
of water requirements, conditions for narrowing the range and optimizing the use of
water, ranges of residual solid wastes , and cost and energy requirements for waste-
water treatment. A comparison of water requirements with those of two recently pu-
blished studies shows  widely varying estimates and emphasizes the need for both site-
and  design-specific calculations.  A review of various combinations of cooling require-
ments indicates a factor of 4 difference in water consumption across all processes stu-
died. Where water costs < 25^/1000 gal. , a high degree of wet cooling appears best.
If >#1. 50/1000 gal, a minimum of wet cooling should be considered. Between these,
a more balanced mix needs to be reviewed. All water requirements  of this study are
based on complete  water re-use; i.e. ,  no direct water discharge to  streams or rivers.
17.
                             KEY WORDS AND DOCUMENT ANALYSIS
                 DESCRIPTORS
                                          b.IDENTIFIERS/OPEN ENDED TERMS
                                              c.  COSATI Field/Group
Pollution
Water Consumption
Coal Gasification
Coal
Shale Oil
Liquefaction
Fuel Oil
Crude Oil
Water Cooling
Waste Water
Wastes
Water Treatment
Waste Treatment
Pollution Control
Stationary Sources
Fuel Conversion
Synthetic Fuels
Coal Refining
Solvent Refined  Coal
Solid Waste
13B

13H
2 ID

07D
13A
 B. DISTRIBUTION STATEMENT
 Unlimited
                                           19. SECURITY CLASS (This Report)
                                           Unclassified
                                              21. NO. OF PAGES
                                                    253
                                          20. SECURITY CLASS (This page)
                                           Unclassified
                                              22. PRICE
EPA Form 2220-1 (9-73)
                   232

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