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
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
-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
-------
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
-------
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
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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
-------
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
-------
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
-------
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.
-------
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
-------
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
-------
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
-------
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
-------
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.
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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
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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
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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
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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
-------
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
-------
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
-------
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
-
-
-------
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
-
_
-------
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
-------
SITE LOCATIONS
• primary sites
osecondary sites
WATER AVAILABILITY
marginal
adequate
APPALACHIAN COAL REGION
Figure 4-2 Water availability in the Appalachian coal region
103
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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:
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UJWER
COLORADO
MAINSTEM
ARIZONA
Figure 4-6 Subbasin boundaries - Upper Colorado River Basin
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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
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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
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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:
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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
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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
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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
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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
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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
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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
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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.
-------
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.
129
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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
-------
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.
131
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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
-------
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
134
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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
139
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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
140
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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.
142
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
2500
2000
1500
2 ,000
soo
ILLINOIS REGION
—
-
J?
|
y,
1
1
'*,
\
£3 STEAM AND BOILER FEED WATER REQUIRED
_ Rl DIRTY AND INTERMEDIATE QUALITY
• •*x
^
N\
.^
'•?
1
j
X
COHOENSATE
E3 NET PROCESS WATER CONSUMED
1
j
!
1
jh
!
1
~
APPALACHIAN
BITUMINOUS
1
I
1
X
1
i
™
REGION
COALS
APPALACHIAN REGION ~
LIGNITE COALS
J^
^
•^
Oj
y^
^
:
:•
:•
I J-
IJI li
P ^
z^ •'•"• '/ v,
1
-500
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
-
^
I
^
1 ra
I
! \
li \
1
«
POWDER RIVER AND FORT UNION REGIONS
LIGNITE COALS
I
\
^
^
|
^
1
J
1
1
'v
1
li
~
i
1
kj
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
-------
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
-------
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.
-------
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
-------
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
-------
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
i
i
y
{ REVEGETATION )
C RESERVOIR ^V*-EVAPORATION
•^
r
BOILER FEED — S.UA<;TF
TREATMENT — ^-IWOIE
•>
r
^ CONDENSATE
POLISHING
POTABLE
WATER
TREATMENT ^ J
r
U-[ PROCESS J
^ ' ^^ -^
(SERVICE AND A
SANITARY I
USE J ^
FO
TREAT
^
kf COQL
^\ Tnu
V
r
*- PHENOL
UL
NSATE *- AMMONIA
™T :~> SLUDGE
r
ING A
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
-------
o
Ul
25
26
,
RAW WATER Plow rate
4),-
C RESERVOIR ^)-22_* EVAPORATION
21 I 1
is
SOFTENER NO. 1 ^> SLUDGE
24 is
BOILER FEED
TREATMENT ZSWASTE
FIG. 11-2
I.
„ .. CONDENSATE
(REVEGETATION) ' POU!>H1Nli
27
.
POT/
WA'
TREA"
^-^
AT
«-52 ( PROCESS J
\BLE Ye
rf€NT j EXTRACTION — > PHENOL
1.
( SERVICE & "S AMMONIA _,. ^miK
\SANITARY USE,/ SEPARATION
(7vA~
36 JlO
'+11
16
HLItK ,. j
,." C DUST ^ C f(.
17 S '"***. VCONTROL J V
M^-^V TOWER y
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
-------
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
-------
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
-------
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)
-------
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)
-------
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)
-------
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
-------
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
-------
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
-------
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
-------
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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