&EPA
United States Industrial Environmental Research EPA-600/7-78-197b
Environmental Protection Laboratory October 1978
Agency Research Triangle Park NC 27711
Water-related
Environmental Effects
in Fuel Conversion:
Volume II. Appendices
Interagency
Energy/Environment
R&D Program Report
-------
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 endorsemerlt or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
-------
EPA-600/7-78-197b
October 1978
Water-related Environmental
Effects in Fuel Conversion:
Volume II. Appendices
by
Harris Gold and David J. Goldstein
Water Purification Associates
238 Main Street
Cambridge, Massachusetts 02142
Contract No. 68-03-2207
Program Element No. EHE823A
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
-------
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.
-------
CONTENTS
Page
PREFACE _ _ _ _ j^
FIGURES _ jy
TABLES vj
CONVERSION FACTORS x
Al. CALCULATIONS ON SOLVENT REFINED COAL 1
A2. CALCULATIONS ON THE SYNTHOIL PROCESS 34
A3. CALCULATIONS ON THE HYGAS PROCESS 58
A4. CALCULATIONS ON THE BIGAS PROCESS .... 75
A5. CALCULATIONS ON THE SYNTHANE PROCESS 86
A6. CALCULATIONS ON THE LURGI PROCESS 103
A7 - COOLING WATER REQUIREMENTS 120
A8. BOILERS, ASH DISPOSAL AND FLUE GAS DESULFURIZATION 203
A9. ADDITIONAL WATER NEEDS 205
A10. WORK SHEETS FOR NET WATER CONSUMED AND WET SOLIDS RESIDUALS GENERATED . . 213
All. WATER TREATMENT PLANTS 347
A12. CALCULATIONS ON OIL SHALE 417
A13. WATER AVAILABILITY AND DEMAND IN EASTERN AND CENTRAL REGIONS 436
A14. WATER AVAILABILITY AND DEMAND IN WESTERN REGION 504
A15. COST OF SUPPLYING WATER TO CHOSEN SITES . 615
iii
-------
Figures
Number Page
Al-l SRC dissolving section A 13
Al-2 SRC dissolving section B 14
Al-3 SRC hydrogen production by gasification A 15
Al-4 SRC hydrogen production by gasification B 16
A2-1 Flow diagram for process water streams in Synthoil process- 44
A2-2 Flow diagram for hydrogen production in Synthoil process 45
A3-1 Flow diagram for Hygas process 63
A4-1 Bigas Process Flowsheet 79
A5-1 Flow diagram for Synthane processes 91
A7-1 Cost of steam turbine condenser cooling in Farmington, N.M 140
A7-2 Cost of steam turbine condenser'cooling in Casper, Wyoming 141
A7-3 Cost of steam turbine condenser cooling in Charleston, W.V- 142
A7-4 Cost of steam turbine condenser cooling in Akron, Ohio 143
A7-5 The effect of water cost on water consumed for cooling turbine
condensers 144
A7-6 Cost of interstage cooling for compressing 1,000 Ib air
at Farmington, N.M 145
A7-7 Cost of interstage cooling for compressing 1,000 Ib air
at Casper, Wyoming 146
A7-8 Cost of interstage cooling for compressing 1,000 Ib air
at Charleston, W.V 147
A7-9 Cost of interstage cooling for compressing 1,000 Ib air
at Akron, Ohio 148
A7-10 The effect of water cost on water consumed for interstage
cooling when compressing 1,000 Ib air 149
A7-11 Turbine condenser cooling systems 150
A7-12 Turbine heat rates at full load 151
A7-13 Turbine condenser cooling requirements at full load 152
A7-14 Fan power reduction factor for air coolers 153
iv
-------
FIGURES (Cont.)
Number
A7-15 Air compressor design conditions 154
All-1 Water treatment block diagrams ................................... 352
All-2 Boiler feed water treatment schemes 355
All-3 Clarif ier costs 356
All-4 Approximate electrodialysis capital investment as a function
of capacity for various numbers of stages ........................ 357
A12-1 Flow diagram for surface processing of oil shale................. 419
A12-2 Paraho retorting process - direct mode 420
A12-3 Paraho retorting process - indirect mode......................... 421
A12-4 TOSCO II retorting process 422
A12-5 Shale oil upgrading plant- 423
A12-6 TOSCO II spent shale disposal process with quantities
appropriate to an integrated plant producing 50,000 bbls/day
of synthetic crude............................................... 430
A15-1 Pipeline construction costs- ..........................'.. 617
A15-2 Total annual costs for transporting water as a function of
pipe diameter - 622
A15-3 Effect of flow rate on the total annual costs of transporting
water- 623
A15-4 Unit cost of water supply-....................................... 626
A15-5 Water supply costs- 627
A15-6 Effect of interest rate on unit cost of water supply 629
A15-7 Effect of pipeline construction cost on the unit cost of water
supply- 630
A15-8 Effect of power cost on the unit cost of water supply 631
A15-9 Pipeline conveyance routes in the Belle Fourche-Cheyenne
River Basins from various water sources to Gillette, Wyoming,>_.e 642
A15-10 Pipeline conveyance routes in the Yellowstone-Missouri
Mainstem River Basin from various water sources to U.S.Steel
(Chupp) Mine, Montana. ................................... 643
A15-11 Pipeline conveyance routes in the Powder River Basin from
various water sources to Spotted Horse Mine, Wyoming 644
A15-12 Pipeline conveyance routes in the Tongue-Rosebud River Basin
from various water sources to Colstrip, Montana.................. 645
A15-13 Pipeline conveyance routes in the Heart and Cannonball River
Basins from various water sources to Dickinson Mine, N.D......... 646
V
-------
Tables
Number Page
Al-l ANALYSES OF COAL AND SOLVENT REFINED COAL. . 17
Al-2 ASSUMED ANALYSES OF SOLVENT REFINED COAL 17
Al-3 MATERIAL BALANCES FOR DISSOLVING SECTIONS OF 10,000 TONS/DAY
SRC PLANTS 18
Al-4 FLOW RATES IN PRODUCTION OF HYDROGEN IN 10,000 TONS/DAY SRC
PLANTS . 26
Al-5 GAS STREAMS IN PRODUCTION OF HYDROGEN IN 10,000 TONS/DAY SRC
PLANTS 27
Al-6 SYMBOLS AND VALUES USED FOR CALCULATIONS AROUND GASIFIER IN
10, 000 TONS/DAY SRC PLANTS - - 28
Al-7 APPROXIMATE HEAT BALANCES ON DISSOLVING SECTION OF 10,000
TONS/DAY SRC PLANTS - 29
Al-8 APPROXIMATE HEAT BALANCES ON GASIFICATION SECTIONS OF 10,000
TONS/DAY SRC PLANTS 30
Al-9 APPROXIMATE PLANT DRIVING ENERGY REQUIREMENTS FOR 10,000
TONS/DAY SRC PLANTS 31
Al-10 EFFICIENCY CALCULATION FOR 10,000 TONS/DAY SRC PLANTS- 32
Al-11 ULTIMATE DISPOSITION OF UNRECOVERED HEAT IN 10,000 TONS/DAY
SRC PLANTS ' 33
A2-1 MATERIAL BALANCE ON SYNTHOIL PLANT EXCLUSIVE OF HYDROGEN
PRODUCTION 46
A2-2 SUMMARY OF FLOWS FOR HYDROGEN PRODUCTION AND OTHER WATER STREAMS
IN 50,000 BBL/DAY SYNTHOIL PLANTS 52
A2-3 SUMBOLS AND VALUES USED TO CALCULATE BALANCES AROUND GASIFIER
IN 50,000 BBL/DAY SYNTHOIL PLANTS 53
A2-4 SUMMARY OF GAS STREAMS FOR HYDROGEN PRODUCTION IN 50,000 '
BBL/DAY SYNTHOIL PLANTS 54
A2-5 PLANT ENERGY REQUIREMENTS IN 50,000. BBL/DAY SYNTHOIL PLANTS ..... 55
A2-6 APPROXIMATE THERMAL EFFICIENCIES OF 50,000 BBL/DAY SYNTHOIL
PLANTS 56
A2-7 DISPOSITION OF UNRECOVERED HEAT IN 50,000 BBL/DAY SYNTHOIL PLANTS 57
VI
-------
Number Tables (Cont. )
A3-1 ANALYSIS OF COAL USED IN REFERENCE HYGAS PLANTS ...... ..,... 54
A3-2 PRETREATMENT MATERIAL RATES FOR REFERENCE HYGAS PLANTS .... ...... 65
A3- 3 PRETREATMENT ENERGY RATES FOR REFERENCE HYGAS PLANTS ..... ....... 66
A3-4 GASIFIER FLOW RATES FOR REFERENCE HYGAS PLANTS ........... - ..... 67
A3-5 GASIFIER ENERGY INFORMATION FOR REFERENCE HYGAS PLANTS .......... 68
A3- 6 GAS AND WATER STREAMS FOR REFERENCE HYGAS PLANTS ................ 69
A3-7 APPROXIMATE HEAT BALANCE AND ENERGY INFORMATION ON GASIFIER
TRAIN FOR REFERENCE HYGAS PLANTS ..................-..... 70
A3-8 DRIVING ENERGY FOR REFERENCE HYGAS PLANTS, FUEL REQUIRED IN
BOILER, EFFICIENCY , AND UNRECOVERED HEAT ...................' 71
A3-9 ULTIMATE DISPOSITION OF UNRECOVERED HEAT FOR REFERENCE HYGAS
PLANTS ... ..... ..... ..... . ........ ............................... 72
A3-10 FLOW RATES IN 250X10 SCF/DAY HYGAS PLANTS ...................... 73
A3-11 ENERGY FLOWS IN 250X10 SCF/DAY HYGAS PLANTS .................... 74
A4-1 FLOW RATES IN REFERENCE BIGAS PROCESSES ......................... 80
A4-2 WATER EQUIVALENT HYDROGEN BALANCES FOR TWO BIGAS PLANTS FROM
REFERENCE 1 ..... . . ............ . . ...... ............. ____ ......... 81
A4-3 ANALYSES OF VARIOUS COALS DRIED TO 1.3% MOISTURE FOR FEED TO
BIGAS PROCESS. . , . ............... ................................ 82
A4-4 WATER EQUIVALENT HYDROGEN BALANCES FOR BIGAS PLANTS ............. 83
A4-5 REQUIREMENTS FOR AUXILIARY ENERGY IN BIGAS PLANTS ...... ..... .... 84
A4-6 ULTIMATE DISPOSITION OF UNRECOVERED HEAT IN BIGAS PLANTS. ........ 85
A5-1 ANALYSES OF VARIOUS COALS DRIED TO 4.3% MOISTURE FOR FEED TO
SYNTHANE PROCESS ........................... ____ . ....... ......... 92
A5-2 FLOW AND ENERGY RATES FOR REFERENCE SYNTHANE PLANTS. ............. 93
A5-3 WATER EQUIVALENT HYDROGEN BALANCES FOR SYNTHANE REFERENCE PLANTS 94
A5-4 WATER EQUIVALENT HYDROGEN BALANCES AND FEED COAL RATES FOR
SYNTHANE PLANTS .................................... 95
A5-5 SYNTHANE GASIFIER HEAT BALANCES FOR REFERENCE LOCATIONS ......... 95
A5-6 HEAT BALANCE AROUND THE SYNTHANE GASIFIER TRAIN FOR REFERENCE
PLANTS ............. ..... .... ---- ................................ 97
A5-7 DRIVING ENERGY FOR REFERENCE SYNTHANE PLANTS ..---.... 99
A5-8 OVERALL PLANT HEAT BALANCES FOR REFERENCE SYNTHANE PLANTS ....... 99
A5-9 ULTIMATE DISPOSITION OF UNPECOVERED HEAT IN REFERENCE SYNTHANE
PI --iNTS. ........ ........ .......................................... 100
A5-10 DRIVING ENERGY, THERMAL EFFICIENCY AND ULTIMATE DISPOSITION OF
UNRECOVERED HEAT FOR SYNTHANE PLANTS .................... ____ . . . 101
A5-11 CHAR COMPOSITIONS IN REFERENCE SYTHANE PLANTS ................... 102
-------
Number Tables (Contr) Pa9e
A6-1 LURGI GASIFIER MATERIAL BALANCE HO
A6-2 LURGI GAS TRAIN BALANCE 116;
A6-3 PROCESS WATER AND OTHER STREAMS IN 250X10 SCF/DAY LURGI PLANTS 119
A7-1 ASSIGNMENT OF COOLING LOADS 155
A7-2 WATER AVAILABILITY AND EVAPORATION RATE 156
A7-3 NOMENCLATURE 157
A7-4 AVERAGE AMBIENT CONDITIONS 158
A7-5 HEAT TRANSFER COEFFICIENTS, FAN AND PUMP ENERGIES 159
A7-6 UNIT COSTS 160
A7-7 CALCULATIONS ON STEAM TURBINE CONDENSERS AT FARMINGTON, N.M. - 161
A7-8 CALCULATIONS ON STEAM TURBINE CONDENSERS AT CASPER, WYOMING - - - 166
A7-9 CALCULATIONS ON STEAM TURBINE CONDENSERS AT CHARLESTON, W.V. .- 171
A7-10 CALCULATIONS ON STEAM TURBINE CONDENSERS AT AKRON, OHIO 176
A7-11 SUMMARY OF WET/DRY CONDENSER COOLING CALCULATIONS 181
A7-12 ANNUAL AVERAGE COSTS FOR WET/DRY CONDENSER COOLING 182
A7-13 SUMMARY OF WET/DRY COMPRESSOR INTERSTAGE COOLING FOR AIR
COMPRESSORS AT FARMINGTON, N.M 183
A7-14 ANNUAL AVERAGE COST FOR WET/DRY COMPRESSOR INTERSTAGE COOLING
FOR AIR COMPRESSORS AT FARMINGTON, N.M 184
A7-15 CALCULATIONS ON INTERSTAGE COOLING OF AN AIR COMPRESSOR HANDLING
1000 LB AIR/HR AT FARMINGTON, N.M 185
A7-16 CALCULATIONS ON INTERSTAGE COOLING OF AN AIR COMPRESSOR HANDLING
1000 LBS AIR/HR AT CASPER, WYOMING 189
A7-17 CALCULATIONS ON INTERSTAGE COOLING OF AN AIR COMPRESSOR HANDLING
1000 LBS/HR AT CHARLESTON, W.V 193
A7-18 CALCULATIONS ON INTERSTAGE COOLING OF AN AIR COMPRESSOR HANDLING
1000 LBS AIR/HR AT AKRON, OHIO 197
A7-19 SUMMARY OF WET/DRY COMPRESSOR INTERSTAGE COOLING FOR AIR
COMPRESSOR 201
A7-20 ANNUAL AVERAGE COST FOR WET/DRY COMPRESSOR INTERSTAGE COOLING
FOR AIR COMPRESSOR 202
A9-1 OTHER WATER NEEDS 212
All-1 WATER TREATMENT BLOCKS AND OTHER COSTS 358
All-2 EFFLUENT WATER QUALITY 351
All-3 RAW WATER QUALITIES . 362
All-4 WATER TREATMENT PLANTS 366
Vlll
-------
(Cont>)
A12-1 NET INPUT AND OUTPUT QUANTITIES FOR AN INTEGRATED OIL SHALE
PLANT PRODUCING 50,000 BBL/DAY OF SYNTHETIC CRUDE ... .......... - 418
A12-2 RAW SHALE AND PRODUCT OUTPUT PROPERTIES. . ....... ................ 418
A12-3 RETORTING AND UPGRADING PROCESS WATER STREAMS FOR OIL SHALE
PLANTS PRODUCING 50,000 BBL/DAY OF SYNTHETIC CRUDE. ............. 425
A12-4 RETORT THERMAL BALANCES FOR 50,000 BBL/DAY OIL SHALE PLANTS ---- - 426
A12-5 THERMAL BALANCES, UNRECOVERED HEAT REMOVED BY WET COOLING
AND WATER EVAPORATED IN 50,000 BBL/DAY OIL SHALE PLANTS ........ 427
A12-6 WATER CONSUMED IN DUST CONTROL FOR MINING AND FUEL PREPARA-
TION FOR UNDERGROUND SHALE MINES INTEGRATED WITH SHALE OIL
PLANTS PRODUCING 50, 000 BBL/DAY OF SYNTHETIC CRUDE ............. 429
A12-7 OIL SHALE QUANTITIES IN TONS /DAY FOR INTEGRATED PLANTS
PRODUCING 50,000 BBL/DAY OF SYNTHETIC CRUDE. .................... 429
A12-8 WATER REQUIREMENTS FOR SPENT SHALE DISPOSAL FROM INTEGRATED
PLANTS PRODUCING 50,000 BBL/DAY OF SYNTHETIC CRUDE. ............. 433
A12-9 SERVICE AND OTHER WATER REQUIREMENTS FOR INTEGRATED OIL SHALE
PLANTS PRODUCING 50,000 BBL/DAY OF SYNTHETIC CRUDE ....... ---- .. 433
A12-10 SUMMARY OF WATER CONSUMED AND WET -SOLID RESIDUALS GENERATED
FOR INTEGRATED OIL SHALE PLANTS PRODUCING 50,000 BBL/DAY OF
SYNTHETIC CRUDE. ........... ____ ................................. 434
A15-1 COST PARAMETERS USED IN THE PRESENT STUDY. ............ ..... ..... 625
A15-2 ANALYSIS OF BUREAU OF RECLAMATION AQUEDUCT DATA. ................ 633
A15-3 MINE LOCATIONS WITH RESPECT TO RIVER BASINS. .................... 635
A15-4 WATER SOURCES AND SUPPLIES FOR SITE STUDIES ON AN ANNUAL BASIS
IN ACRE-FEET PER YEAR- .......................................... 636
A15-5 WATER REQUIREMENTS FOR PLANT SITE COMBINATIONS IN ACRE FT/YR
AND (mgd) ...................................... ..... ............ 638
A15-6 UNIT COSTS OF TRANSPORTING WATER TO GILLETTE, WYOMING .......... 640
A15-7 ROUTE DATA FOR GILLETTE , WYOMING- ............................... 640
A15-8 COST OF TRANSPORTING WATER TO GILLETTE, WYOMING- .......... ---- . . 641
A15-9 LOCAL SUPPLY TO INDIVIDUAL PLANTS .......... ...... ............... 648
A15-10 LARGE SCALE WATER CONVEYANCE COSTS .......... ..... . ..... .... ..... 650
-------
CONVERSION FACTORS
ACCELERATION
ENERGY/AREA-TIME
MASS/TIME
MASS/VOLUME
MISCELLANEOUS
POWER
SPEED
i to International System (SI) Units
Multiply
2
f oot/second
free fall, standard
acre_
feet2
Btu (mean)
calorie (mean)
ki lowatt- hours
Btu/foot hour
Btu/foot minute
Btu/foot second
calorie/on minute
dyne
kilogram force (Kg )
pound force (Ib, avoirdupois)
foot
mile
pound (avoirdupois)
ton (short, 2000 Ib)
pound/hour
pound/minute
ton (short) /hour
ton (short) /day
gram/centimeter
pound/ foot
pound/gallon (U.S. liquid)
Btu/hr-ft2-ซF
Btu/kw-hr
Btu/lb
Btu/lbm-*F
A
gal/10 Btu
kiloCAlorieAilogram
Btu/hour
Btu/minute
Btu/second
calorie/hour
calorie/minute
calorie/second
horsepower
atmosphere
foot of water (39.2ฐF)
psi (lbf/in )
lbf/foot2
foot/minute
foot/second
mi le/hour
Si
_1
3.048 x 10
9.807
4.047 x 103
9.290 x 10
' 1.056 x 103
4.190
3.60 x 10
3.152 x 10"1
1.891 x 10^
1.135 x 10*
6.973 X 10
1.00 x 10~5
9.807
4.448
3.048 x 10"1
1.609 x 10
4.536 x 10"1
1.00 x 10
9.072 x 10
1.260 X 10~^
7.560 X 10 ,
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 ป 103
4.184 x 10
3.585 x 10"12
4.184 x 10
2.929 x 10"1
1.757 x 10^
1.054 ป 10
1.162 x 10 ,
6.973 x 10"
4.184
7.457 x 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
4.470 x 10
To Obtain
2
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-n -*C
joules/kw-sec
joule/leg
joule/Xg-'C
meter /joule
jouleA9
watt
watt
watt
watt
watt
watt
watt
pascal (- nevton/m2)
pascal
pascal
pascal
meter/second
meter/second
meter/second
TEMPERATURE
0.556 (ฐF + 459.7)
(continued)
x
-------
Conversion Factors (Cont.)
acre foot
barrel (oil, 42 gal)
foot
gallon (U.S. liquid)
1.590
1.233
2.632
3.785
x 10
x 10
x 10
x 10"
51
-i
3
To Obtain
VOLUME/TIME
ft /sec
gal (U.S. liquid)/day
gal (U.S. liquid)/min
4.719 x 10_
2.832 x 10
4. 381 x 10~
6.309 x 10
meter /second
meter /second
meter /second
meter /second
Other Conversion Factors
The fallowing table is based on a density of water of 62.3 pounds per cubic fcot. This is the density
of water at 68*F (20*C) and corresponds to 8.33 pounds of water per gallon.
acres
acres
acre-feet
acrfifee t/year
acre- fee t/year
acre- fee t/year
barrels, oil
Btu
Btu
cubic feet
cubic feet
cubic feet of water
cubic feet/second
gallons
gallons
gall on s
gallons/minute
gallons/minute
gallons/minute
gallons of water/minute
horsepower
horsepower
ki Iowa tt-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 ,.,,,ซ
square feet
temperature, ฐC
temperature , *F-32
thousand pounds/hour
thousand pounds of water/hour
thousand pounds of water/hour
tons (short)
tons {short)
tons/day . .
tons/year
watts
-3,
1,
3.
j ,
6,
8,
4.
. . 2,
3,
2.
7.
6.
4.
6.
3.
2.
1.
a.
i.
2.
1.
5.
6.
2.
3.
1
1.
1.
6.
3.
1,
1.
3.
2,
1.
5.
1,
4.
2.
2.
2
9.
8.
2.
3.
.36
.56
36
. 26
.38
91
.20
.93
.2
i?
,93
,30
.48
.23
44
.46
.07
,38
,34
11
,61
,23
.44
00
.11
.55
.41
.12
.55
.94
.47
,20
.60
.80
.30
.8
, 56
,2
18
,00
.88
x
,07
33
28
41
x
X
X
*
X
X
X
If
X
X
X
X
*
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
10
X
X
X
10
104
10%
-3
10 .
-5
in
-1
io""1 i
10
io2
"Is
10
;
10
-1
10l2
10 , 1
10
-3
10-3
- 1 '
10
io4
103
10
3
10
J '
i?
10-2
Jo2
io~5
-1
10
10 3
10
-3
310
io',1
Kf2
10-"
square feet
square miles
cubic feet
gallons
cubic feet/second
cubic meters/second
galIons/minute
million gallons/day
gallons
calories
horsepower-hours
acre-feet
gallons
pounds of water
gallons/minute
million 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-feet/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 ฐF
"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
xi
-------
APPENDIX 1
CALCULATIONS ON SOLVENT REFINED COAL
BASIS OF ANALYSIS
Solvent refined coal (SRC) plant designs are required for bituminous
coals at:
1, Bureau, Illinois
2. White, Illinois
3. Fulton, Illinois
4. Saline, Illinois
5. Rainbow, Wyoming
subbituminous coals at:
and lignites at:
6. Gillette, Wyoming
7. Antelope Creek, Wyoming
8. Colstrip, Montana
9. Marengo, Alabama
10. Dickinson, North Dakota
11. Bentley, North Dakota
12. Underwood, North Dakota
13. Otter Creek, Montana
14. Pumpkin Creek, Montana
15, Coalridge, Montana.
The experiments on solvent refining of coal are described in References
1-7. Most of the work has been done on bituminous coals from Pittsburgh,
Kentucky and Illinois. On Table Al-1 are shown three coal analyses and three
average SRC analyses derived from these coals. Very little work has been
done on solvent refining of lignite and subbituminous coals. Some experiments
1
-------
on North Dakota lignite and Wyoming subbituminous were done in a small
laboratory bench reactor; the solvent was not in balance, and the analyses of
the SRC are only suggestive of what might be obtained on a large scale;
However, the SRC derived from the Western coals seems very similar to that
derived from Eastern coals. We have assumed the analyses given on Table Al-
2.
An alternative process is under study, particularly as "Project Lignite,"
Q
at the University of North Dakota . In this process carbon monoxide or
synthesis gas (CO + H ) is used to dissolve the coal instead of hydrogen.
Water is used (with lignite this may be the coal moisture) and the shift gas
reaction, CO + HO -> H + CO , occurs in the dissolver, probably catalyzed by
2 2 2 9
coal mineral. It is this process which was studied by Ralph M. Parsons Co.
and Jahnig . This is not the process used here.
The dissolving section of the plant, based mostly on the pilot plant
design ' , is shown in simplified form in Figures Al-1 and Al-2. To obtain
the water requirements we have proceeded as follows:
1) From the pilot plant results a set of rules has been formulated
which give the material balance around the dissolving section of the plant.
2) The carbonaceous filter residue and extra coal were gasified to
produce hydrogen.
3) Approximate heat balances have been made around the gasification and
dissolving sections.
4) The energy needed to drive the plant was estimated. This energy was
supplied from waste heat recovery units and by burning the light oil and
gaseous hydrocarbon made in the dissolving section.
5) Surplus light oil and gaseous hydrocarbon was sold. So much energy
is needed to dry lignites as. feed to the dissolving section that very little
light fuel is available for sale. However, with bituminous coals quite a lot
of light fuel- is.available for sale. With bituminous and subbituminous coals
an alternative procedure (not considered here but detailed elsewhere ) is to
not add coal to the gasifier but to reform some gaseous hydrocarbon to
hydrogen instead.
6) The approximate plant conversion efficiencies were then stated.
7) Finally, the points of loss of unrecovered heat were tabulated.
-------
MATERIAL BALANCE ON DISSOLVING SECTION x
The yields of the various products are mostly reported as fractions of
the moisture-and-ash-free coal. Because of the high oxygen contents of
Western coals, this procedure has not been used to convert the yields from
Eastern coal to those from Western coals. Instead, we have used yields of
carbon. Based on the published experimental results, mostly the pilot plant
results , we have formulated the following rules for material balances in the
dissolving section of the plant:
1) 70 percent of the carbon in the coal appears as carbon in the SRC.
2) 14 percent of the carbon in the coal appears as carbon in light
liquid hydrocarbon product of composition CH .
1.6
3) 5 percent of the carbon in the coal appears as gaseous hydrocarbon
product of composition CH (about 75 percent CH and the balance higher
hydrocarbons).
4) 1 percent of the carbon in the coal appears as CO .
5) 10 percent of the carbon in the coal appears as carbon in undis-
solved residue.
6) The ratio O/C in the undissolved residue is the same as in the coal.
The balance of the oxygen appears as water.
7) A detailed description of the distribution of sulfur would be that
all of the sulfate sulfur stays in the mineral residue; 50 percent of the
pyritic sulfur is reduced to H S, and the balance appears in the ash; 60-70
percent of the organic sulfur is reduced to H S, and the balance is dis-
tributed between the SRC and undissolved residue. However, for lack of
sulfur analyses a simpler rule has been adopted: of the sulfur in the coal
which does not appear as SRC, 50 percent is converted to H S and 50 percent
stays in the residue.
8) Nitrogen from the coal appears in the SRC and the undissolved
residue with the balance appearing as ammonia. The ratio N/C is the same in
the coal and in the undissolved residue.
9) The ratio H/C in the filter residue is the same as in the coal.
10) Hydrogen is supplied as required, and 10 percent of the feed hydrogen
18 20
does not react. This in fact may be low based on some recent EPRI data
11) The remainder of the ash all appears in the undissolved residue.
-------
Application of these rules gives the material balances presented on
Table Al-3. On these tables stream numbers from Figures Al-1 and Al-2 have
been entered. It should be noted that for Stream 2 only the hydrogen content
has been stated. In fact, the hydrogen streams produced by gasification and
reforming contain only about 85 percent hydrogen with CO being the balance.
These extra gases are assumed to leave the dissolving section with the gas of
Stream 7. Not shown on Table Al-4 is 10,000 Ib/hr steam needed for the
vacuum ejectors in all plants. The condensate from this steam is rejected
with the dirty condensate from the dissolving section.
PRODUCTION OF HYDROGEN BY GASIFICATION
The production train is shown on Figures Al-3 and Al-4. A Koppers-
Totzek gasifier has been chosen because of the high ash content of the feed.
The gasifier rules are :
oxygen feed = 1.06 Ib/lb (carbon + hydrogen);
boiler feed water = 0.223 Ib/lb (carbon + hydrogen);
in the off-gas, the concentrations are given by;
(H )(CO )
= 0.47.
(CO)(H20)
Methane is not produced.
The weight rates of flow are given on Table Al-4 and molar rates of flow
on Table Al-5. They are found as follows.
1) The hydrogen required is shown on Table Al-3, Stream 2. Let this be
m moles/hr. Also, we assume the gas actually produced is 85 percent H and
H 2
15- percent CO. The total of H + CO in the product and in all gas streams
from the gasifier off-gas onwards is therefore m /0.85. The symbols and
H
values used in the following calculations are given on Table Al-6. The first
two equations are:
MH2 +MCO =
'V "W
= ฐ'47 <2>
-------
2) The elemental balances around the gasifier can now be written. They
are:
carbon
c.Wc/12 =
(say)
(3)
hydrogen
w.Wc/18
2MR =
H20
(say) (4)
oxygen
:-Wc/32
c.W
M
= MCO/2 + MC02 + MH20/2 = K3
Equations (3), (4) and (5) can be rearranged to give
M
H2
MCO = K2 + 2K1 ~ 2K3
= (from Eq. (1) ) ir^/0.85
(5a)
Equation (5a) can be solved for W , the weight of coal. Knowing W , Equations
\ * -
(3), (4) and (5) give M ,M and M in terms of M and substitution
L(J^ rlz tiZ(J (_O
into Equation (2) gives a quadratic in M .
3) The gasifier off-gas is quenched to 130 ฐF with condensation of
water. The water in the gas after quench is very small and is treated as
zero.
4) The shift reactor must have in its exit gas M moles/hr H and
H 2
lSnVj/85 = 0.176 m moles/hr CO. Also, from the stoichiometry of the shift
reaction, CO is converted to CO so the moles/hr CO in the exit case:
/- ' ^
= MC02 +MCO
Finally, the shift reaction is in equilibrium at 50ฐF, so the moles/hr
HO in the exit gas, M' is given by:
2
-------
ฐ-176VM'H20
8
The steam in Stream 14, M , is given by the hydrogen balance around the
o X
shift reactor:
MH2 + MST = MH + M'H20 (8)
5) The acid gas removal is, for simplicity, assumed to remove all the
CO . All the water leaving the shift reactor appears in Stream 15 as
condensate.
HEAT BALANCE ON DISSOLVING SECTION
Approximate heat balances on the dissolving section are given on Table
Al-7. They are calculated as follows:
1) Coal feed is given on Table Al-3.
2) ^Hydrogen is given on Table Al-3 and this stream is 15 percent CO and
85 percent H . The higher heating value of H is 123,000 Btu/mole, and of CO
^
-------
14,540C + 62,000(H - X/8)
where C, H and X are the pounds of carbon, hydrogen and oxygen. The heating
value of the gaseous hydrocarbon is taken to be 23,500 Btu/lb.
5) The steam recovered is the total from the two-fired heater plus the
energy given out when the solvent is cooled through 160ฐF.
6) Stack losses are 12 percent of the fired preheater duties.
7) Cooling loads involve cooling the flashed gas, water and light oil
from 550ฐF to 100ฐF and condensing the water and oil. Also, refluxed solvent
to the vacuum tower must be condensed, but this stream, while not known, must
certainly be very small because the separation requires very little reflux.
The total cooling loads are calculated as:
1,500 x (condensed water, Stream 5)
+ 360 x (condensed light oil, Stream 6)
+ 220 x (gas, Stream 7)
These numbers are totals of sensible and latent heat. Condensing water is
much the largest part of the load, and this is mostly done in the dry cooler.
Of the total load, 80 percent is assigned to dry cooling and 20 percent to
wet cooling. In addition to this load, the wet loading is arbitrarily
increased to force a balance.
8) Around the filter the stream is assumed to cool 100ฐF by convection
and radiation.
9) The SRC is assumed recovered as a liquid with a sensible heat of
130 Btu/lb.
9
10) The other losses are an arbitrary 0.5 x 10 Btu/hr. They are
assumed to be radiant and convective losses.
HEAT BALANCE ON THE GASIFICATION SECTION
Approximate heat balances on the gasification sections are given on
Table Al-8. They are calculated as follows.
1) The filter residue, Stream 4, is copied from Table Al-7. The coal.
Stream 17, is given on Table Al-4. The steam, Stream 14, is also given on
Table Al-4 and its enthalpy is 1120 Btu/lb. The hydrogen product. Stream 2,
is copied from Table Al-7.
7
-------
2) The heat in the ash and slag is the weight of ash in the total coal
feed to the plant multiplied by 543 Btu/lb, which multiplier, assumes a latent
heat of slag of 63 Btu/lb and a sensible heat of ash of 0.2 Btu/(lb)(ฐF) over
a range of 2400ฐF, i.e., 543 = (0.2)(2400) + 63.
3) The steam raised in the gasifier is found from a heat balance around
the gasifier. All the gasifier feed streams have been entered, as has the
slag stream leaving. The enthalpy of the off-gas is:
127,300 x (moles H2) +126,200 x (moles CO) + 6,460 x (moles CO )
+ 24,140 x (moles
The gas composition is given on Table Al-5 (Stream 12).
Additional steam is raised after the shift converter. This energy is:
3,290 x (moles H ) + 3,380 x (moles CO) + 5,130 x (moles CO )
ฃ
-------
PLANT DRIVING ENERGY
The approximate plant driving energy is shown on Table Al-9. The
moisture lost in drying is shown on Table Al-3. It is evaporated at
1,150 Btu/lb. The energy for acid gas removal is 28,400 Btu/mole CO
(a solvent type of system being assumed used). The CO adsorbed is the total
of that shown on Tables Al~3 and Al-5. The vacuum tower ejector stream
9 3
contains 0.01 x 10 Btu/hr. Stream 8 is therefore 10 x 10 Ib steam/hr at
all plants and Stream 9 is the same. Stream 9 is shown on the worksheets
added to the condensate from the dissolving section, Stream 5. The electri-
city is 15,000 kw. Oxygen production consumes 1,920 Btu/lb with the quantity
of oxygen being shown on Table Al-4. The synthesis gas compressor requires
9 3
0.02 x 10 Btu/10 moles gas where the gas is listed on Table Al-5, entering
9 3
shift. The hydrogen compressor requires 0.0126 x 10 Btu/10 moles gas. The
gas is Stream 2 on Table Al-5. The slurry pump requires
9 3
0.0000733 x 10 Btu/10 Ib dry coal. Thedry coal rate is given on Table
9
Al-3. The additional allowance is an arbitrary 0.2 x 10 Btu/hr.
PLANT EFFICIENCY AND UNRECOVERED HEAT
The plant efficiency calculation is given on Table Al-10. The coal
rates are given on Tables Al-7 and Al-8. The SRC product is given on Table
Al-7 as is the oil product and the gas product. The total steam recovered is
the sum of that recovered in the dissolving section (Table Al-7) and in the
gasification section (Table Al-8). Steam is consumed in the gasification
section as shown on Table Al-8. The plant driving energy, for which gas and
oil will be burnt, is shown taken from Table Al-9. In burning gas and oil to
raise steam, there is some stack loss,- this is 12 percent of the fuel or 13.6
percent of
(plant driving energy + steam required - steam recovered)
where all the terms are treated as positive no matter how entered on Table
Al-10.
The fuel to dissolver and vacuum preheaters is shown on Table Al-7. All
the plants have net gas or oil for sale.
-------
ULTIMATE DISPOSITION OF UNRECOVERED HEAT
The ultimate disposition of unrecovered heat is shown on Table Al-H-
The direct losses are the sum of:
from Table Al-7: Stack losses
Losses around filter
Sensible heat in SRC
Losses around dissolver and other
from Table Al-8: Ash and slag
from Table Al-9: Coal drying
Vacuum tower ejector
30% of energy to generate electricity
30% of energy to drive the slurry pump
from Table Al-10: Boiler stack losses
The dry cooling load is the sum of that entered on Tables Al-7 and Al-8.
The wet cooling load is the sum of that entered on Tables Al-7 and Al-8
plus the allowances on Table Al-9.
The gas purification system regenerator condenser load is the energy
entered on Table Al-9.
The total steam turbine condenser load is 70 percent of the sum of:
electricity
oxygen production
synthesis gas compressor
hydrogen compressor
slurry pump
all from Table Al-9.
The total gas compressor interstage cooler load is 30 percent of the sum
of:
oxygen production
synthesis gas compressor
hydrogen compressor
all from Table Al-9.
10
-------
REFERENCES, APPENDIX 1
1. Hydrocarbon Research, Inc., "Solvent Refining Illinois No. 6 and Pitts-
burgh No. 8 Coals," Electric Power Research Institute, Palo Alto, Calif.,
Report No. EPRI 389, June 1975.
2. Southern Services, Inc., "Status of Wilsonville Solvent Refined Coal Pilot
Plant," Electric Power Research Institute, Palo Alto, Calif,, Report No.
EPRI 1234, May 1975.
3. Anderson, R. Pr , and Wright, C. H., Pittsburgh and Midway Coal Mining
Co., "Development of a Process for Producing an Ashless, Low-Sulfur Fuel
from Coal, Vol. II; Laboratory Studies, Part 3; Continuous Reactor Experi-
ments Using Petroleum Derived Solvent," May 1975. U.S. Energy Research
and Development Administration, Research and Development Report Mo. 53,
Interim Report No. 8 (NTIS Cat. No. FE-496-T1).
4. Schmid, B. K., "The Solvent Refined Coal Process," presented at Symp. on
Coal Gasification and Liquefaction, University of Pittsburgh, August 1974.
5. Anderson, R. P., "Evolution of Steady State Process Solvent in the Pitts-
burgh and Midway Solvent Refined Coal Process," presented at Symp. on Coal
Processing, AIChE, Salt Lake City, August 1974.
6. 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.
7. Wright, C. H., et al, "Development of a Process for Producing an Ashless,
Low-Sulfur Fuel from Coal, Vol. II; Laboratory Studies, Part 2; Continuous
Reactor Studies Using Anthracene Oil Solvent," U.S. Energy Research and
Development Administration, Research and Development Report No. 53,
Interim Report No, 7, September 1975 (NTIS Cat. No. FE-496-T4).
8. University of North Dakota, "Project LigniteProcess Development for
Solvent Refined Lignite," U.S. Energy Research and Development Administra-
tion, Report 106, Interim Report No, 1, 1974 (NTIS Cat, Ho. FE-1224-T1K
9. Ralph M. Parsons Co,, "Demonstration Plant, Clean Boiler Fuels from Coal,
Preliminary Design/Capital Cost Estimate," U.S., Dept. of the Interior,
O.C.R., R&D Report No. 82, Interim Report No, 1, Volume II, 1975.
10. Jahnig, C. E., "Evaluation of Pollution Control in Fossil Fuel Conversion
Processes: Liquefaction; Section 2, SRC Process," U.S. Environmental Pro-
tection Agency,- Research Triangle Park, N.D., Report No, EPA-50/2-74-009-f,
March 1975.
11
-------
11. Pittsburgh and Midway Coal Mining Company, "Development of a Process
for Producing an Ashless, Low-Sulfur Fuel from Coal, Vol. Ill; Pilot
Plant Development Work, Part 2; Construction of Pilot Plant," May 1975,
U.S. Energy Research and Development Administration, Research and
Development Administration Report No. 53, Interim Report No. 9 (NTIS Cat.
No. FE-496-T2).
12. Nelson, W. L., Petroleum Refinery Engineering, 4th Ed., pp. 252-262,
McGraw-Hill, 1958.
13. Water Purification Associates, "Water Conservation and Pollution Control
in Coal Conversion Processes," Report EPA 600/7-77-065, U.S. Environ-
mental Protection Agency, June 1977.
14. Farnsworth, J. F. , Mitsak, D. M., and Kamody, J. F., "Clean Environment
with K-T Process," presented at EPA Symposium on Environmental Aspects
of Fuel Conversion Technology, St. Louis, Mo., May 1974.
15. Farnsworth, J. F., Mitsak, D. M., Leonard, H. F., and Wintrell, R.,
"Production of Gas from Coal by the KOPPERS-TOTZEK Process," IGT
Symposium on Clean Fuels from Coal, Institute .of Gas Technology, Chicago,
111., September 10-14, 1973.
16. Mitsak, D. M., and Kamody, J. F., "Koppers-Totzek: Take a Long, Hard
Look," presented at 2nd Annual Symposium on Coal Gasification; Best
Prospects for Commercialization, University of Pittsburgh, August 1975.
17. Lange, N. A., Handbook of Chemistry, 10th Ed., p. 1516, McGraw-Hill, 1961.
18. Nongbri, G., "Solvent Refining of West Kentucky 9-14 Coal," EPRI Report
AF-499, Electric Power Research Institute, Palo Alto, Calif., May 1977.
19. Lewis, H.E., et al, "Operation of Solvent Refined Coal Pilot Plant at
Wilsonville, Alabama," EPRI Report AF-585, Electric Power Research Institute,
Palo Alto, Calif., November 1977.
20. Nongbri, G. and Ariadni, K., "Solvent Refining of Indiana V Coal and North
Dakota Lignite," EPRI Report AF-666, Electric Power Research Institute,
Palo Alto, Calif.,-January 1978.
12
-------
COAL
550ฐ F
HP
FLASH
DRUM
cw
L--*^
c
<
DECANTER J
/TV
L
LP
FLASH
DRUM
V
00
GAS
ACID
GAS
REMOVAL
CW
SOLUTION OF
SRC
WATER
*- OIL TO CLEAN UP TO FILTtR
Figure Al-1. SRC dissolving sectionA.
-------
STEAM \1
SRC
SOLUTION
FROM
SECTION A
WASH SOLVENT
TO FILTER
VENT
RECYCLE SOLVENT
TO SLURRY BLEND
TANK
SRC
Figure Al-2. SRC dissolving sectionB.
-------
FILTER
COAL
TO
SHIFT
REACTOR
SECTION B
6FW
700ฐ F
I5PSIA
r^\
STEAM
X
AS
RUB
r
130ฐF
WA
INT
COh
TER
RSTAGE
-JDENSATE
265PSIA
SYN GAS
COMPRESSOR
Figure Al-3. SRC hydrogen production by gasificationA.
-------
en
FROM
SECTION A
STEAM
600ฐF
SHIFT
CONVERSION
REACTOR
750ฐ F
SHIFT
CONVERSION
REACTOR
TO DISSOLVING
1700PSIA' SECTION
HYDROGEN
COMPRESSOR
Figure Al-4. SRC-hydrogen production by gasificationB.
-------
TABLE Al-1. ANALYSES OF COAL AND SOLVENT REFINED COAL
In wt % for dry materials.
C
H
N
O
s
Ash
HHV (Btu/lb)
Pittsburgh
Coal SRC
75.1 88.4
5.1 5.5
1.3 1.7
7.6 3.3
2.6 0.9
8.2 0.1
16,000
6
Illinois
Coal
SRC
70.8 87.1
5.1 5.6
1.3 1.6
8.7 4.6
3.2 0.9
1Q.8 0.1
16,000
Kentucky
Coal SRC
72.9 88.5
4.8 5.1
1.2 1.8
10.3 3.7
3.5 0.8
7.3 0.1
16,000
TABLE Al-2. ASSUMED ANALYSES OF SOLVENT REFINED COAL (wt %)
Bituminous
C
H
N
O
S
Ash
HHV (calculated)
Subbituminous
S Lignite
87
5
1
4
0
0
15,
.1
.6
.6
. 7
.9
.1
820
87
5
1
5
0
0
15,
.1
.3
.2
.7
.5
.2
540
17
-------
TABLE Al-3. MATERIAL BALANCES FOR DISSOLVING SECTIONS
OF 10,000 TONS/DAY SRC PLANTS
Units: 10 Ib/hr.
LOCATION: Bureau, Illinois (bituminous)
LOCATION: White, Illinois (bituminous)
Total C H N
Total C H N
As-received coal :
ry ng.
INTO DISSOLVING SECTION
1. Dry coal
2. Hydrogen
|_, TOTAL:
00
OUT
3. SRC
4. Filter residue
5. Water
V
NH3
6. Light oil
7. Gaseous hydrocarbons
co2
Un consumed H
TOTAL;
1,725 1,037
1,448 1,037
31
1,479 1,037
833 726
275 104
71
23
5
164 145
68 52
37 10
3
1,479 1,037
71 19 143 50 128
31
102 19 143 50 128
47 13 39 71
7 2 14 21 127
8 63
1 22
1 4
19
16
27
3
102 19 143 50 128
As-received coal:
Moisture lost in drying:
INTO DISSOLVING SECTION
1. Dry coal
2. Hydrogen
TOTAL:
OUT
3. SRC
4. Filter residue
5. Water
H2S
NH3
6. Light oil
7. Gaseous hydrocarbons
co2
Unconsuraed H_
TOTAL:
1,557 1,037
1,512 1,037 72 22
24 24
1,536 1,037 96 22
833 726 47 13
368 104 7 2
38 4
19 1
7 07
164 145 19
68 52 16
37 10
2 2
1,536 1,037 96 22
Ill 44 226
--
111 44 226
39 7 1
11 18 225
34
19
-_
27
Ill 44 226
-------
TABLE Al-3 (continued)
Units: 10 Ib/lir.
LOCATION: Fulton, Illinois (bituminous)
As
-received coal:
Moisture lost in arymg:
Total C
1,764 1,037
H N
O S Ash
INTO DISSOLVING SECTION
1.
2 f
Dry coal
Hydrogen
TOTAL:
1,488 1,037
29
1,517 1,037
72 19
29
101 19
129 55 176
-
129 55 176
OUT
3.
4.
5,
6.
7.
SRC
Filter residue
Water
H S
7
NH
3
Light oil
Gaseous hydrocarbons
Cฐ2
Un cons ume Q H
TOTAL:
833 726
325 104
56
26
5
164 145
68 52
37 10
3
1,517 1,037
47 13
7 2
6
2
1 4
19
16
3
101 19
39 7 1
13 24 175
50
24
27
_
129 55 176
LOCATION. Saline, Illinois (bituminous)
As-received coal:
Moisture lost in drying:
INTO DISSOLVING SECTION
1. Dry coal
2. Hydrogen
TOTAL.
OUT
Total C H N
1,527 1,037
104
1,423 1,037 69 21 104 47 145
29 29
1,452 1,037 96 21 104 47 145
3.
4.
5.
6.
7.
SRC
Filter residue
Water
H2S
m3
Light oil
Gaseous hydrocarbons
co2
Unconsumed H
TOTAL:
833
287
32
21
7
164
68
37
3
1,452
726
104
145
52
10
1,037
47 13
7 2
4
1
1 6
19
16
3
98 21
39 7 1
10 20 144
28
20
--
--
--
27
-
104 47 145
continued
-------
Table M-3 (continued)
Units: 10 Ib/hr.
LOCATION: Rainbow, Wyoming (bituminous)
LOCATION: Gillette, Wyoming Uubbituminous)
M
O
As-received coal:
Moisture lost in drying:
INTO DISSOLVING SECTION
1. Dry coal
2. Hydrogen
TOTAL:
OUT
3. SRC
4. Filter residue
5. Water
H2S
NH3
6. Light oil
7. Gaseous hydrocarbons
co2
Unconsumed H
TOTAL:
Total C
1,569 1,037
163
1,406 1,037
33
1,439 1,037
833 726
218 104
101
4
11
164 145
68 52
37 10
3
1,439 1,037
H N O S Ash
-
_
72 25 173 14 85
33
105 25 173 14 85
47 13 39 71
7 3 17 3 84
11 90
0 4
2 9
19
16
27
3
105 25 173 14 85
Total C H N
As-received coal:
Moisture lost in drying:
INTO DISSOLVING SECTION
1. Dry coal
2. Hydrogen
TOTAL;
OUT
3. SRC
4. Filter residue
5. Water
H,S
2
NH3
6. Light oil
7. Gaseous hydrocarbons
Cฐ2
Unconsumed H
TOTAL:
2,264 1,037
687
1,577 1,037
34
1,611 1,037
833 726
320 104
176
6
4
164 145
68 52
37 10
3
1,611 1,037
77 14 256 16 177
34
111 14 256 16 177
44 10 47 42
8 1 26 6 175
20 156
0 6
1 3
19
!6
27
3
111 14 256 16 177
continued
-------
TABIE Al-3 (continued)
Units: 10 Ib/hr,
LOCATION: Antelope Creek, Wyoming (subbituininous)
As-received coal:
Moisture lost in drying:
INTO DISSOLVING SECTION
1. Dry coal
2. Hydrogen
TOTAL:
OUT
Total C H I. O S Ash
1,971 1,037
515
1,456 1,037 71 12 237 10 69
35 35
1,491 1,037 106 12 237 10 B9
EFC
Filter residue
Water
H S
NH,
Light oil
Gaseous hydrocarbons
co2
Unconsumed H
TOTAL:
833
226
156
3
1
164
68
37
3
1,491
726
104
145
52
10
_.
1,037
44 10
7 1
17
0
0 1
19
16
3
106 12
47 4 2
24 3 87
139
3
-
27
237 10 89
LOCATION: Colstrip, Montana (subbitumlnous)
As- received coal :
Moisture lost in drying :
INTO DISSOLVING SECTION
1. Dry coal
2. Hydrogen
TOTAL:
OUT
3. SRC
4. Filter residue
5. Water
H2S
KH3
6. Light oil
7. Gaseous hydrocarbons
co2
Unconsumed H
TOTAL:
Total C
1,979 1 , 037
4 82
1,497 1,037
39
1,536 1,037
833 726
273 104
150
2
5
164 145
68 52
37 10
4
1,536 1,037
H N O S Ash
69 16 230 8 137
39
108 16 230 8 137
44 10 47 42
7 2 23 2 135
17 133
0 2
1 4
19
16
27
4 - - .. _
108 16 230 8 137
-------
TABLE JU-3 (continued)
Units.- 10 Ib/hr.
LOCATION: Marengo, Alabama (lignite)
As-received coal :
Moisture lost in drying :
INTO DISSOLVING SECTION
1. Dry coal
2. Hydrogen
TOTAL:
OUT
3. SRC
4. Filter residue
5. Water
H2S
NH
3
6. Light oil
7. Gaseous hydrocarbons
CO
2
Unconsumed H
TOTAL:
Total C H N
3,231 1,037
1,574
1,657 1,037 71 19
50 50
1,707 1,037 121 19
833 726 44 10
325 104 7 2
237 26
29 2
9 27
164 145 19
68 52 16
37 10
5 5
1,707 1,037 121 19
0 S Ash
317 58 155
317 58 155
47 4 2
32 27 153
211
27
27
317 58 155
LOCATION: Dickinson, North Dakota (lignite)
As-received coal:
INTO DISSOLVING SECTION
1. Dry coal
2. Hydrogen
TOTAL:
OUT
3. SRC
4. Filter residue
5. Water
H2S
NH3
6. Light oil
7. Gaseous hydrocarbons
co2
Unconsumed H_
TOTAL:
Total C
2,758 1,037
1,621 1,037
42
1,663 1,037
833 726
324 104
224
5
4
164 145
68 52
37 10
4
1,663 1,037
H h O S Ash
74 14 303 14 179
42
116 14 303 14 179
44 10 47 42
7 1 30 5 177
25 199
0 5
1 3
19
16
27
4
116 14 303 14 179
continued
-------
TABLE Al-3 (continued)
Units: 10 Ib/hr.
LOCATION: Bentley, North Dakota (lignite)
Total C
As-received coal:
Moisture lost in d.rying :
INTO DISSOLVING SECTION
1. Dry coal
2, Hydrogen
TOTAL:
OUT
3. SRC
<3 . Filter residue
5. Water
H2S
KH3
6. Light oil
7. Gaseous hydrocarbons
co2
Unconsumed H
TOTAL:
2,493 1,037
907
1,586 1,037
39
1,625 1,037
833 726
298 104
203
14
4
164 145
68 52
37 10
4
1,625 1,037
--
77 15 282 30 145
39
116 15 282 30 145
44 10 47 42
8 2 28 13 143
23 180
1 13
1 3
19
16
27
4 ..
116 15 282 30 145
LOCATION: Underwood, North Dakota (lignite)
As-received coal:
ols ure ost n ry ng :
INTO DISSOLVING SECTION
1. Dry coal
2. Hydrogen
TOTAL:
OUT
3. SRC
4. Filter residue
5. Water
H2S
3
6. Light oil
1, Gaseous hydrocarbons
co2
Unconsumed H
TOTAL:
Total C
2,429 1,037
860
1,569 1,037
42
1,611 1,037
833 726
281 104
216
4
4
164 145
68 52
37 10
4
1,611 1,037
H N 0 S Ash
73 15 296 12 136
42
115 15 296 12 136
44 10 47 42
7 2 30 4 134
24 192
0 4
1 3
19
16
27
4
115 15 296 12 136
-------
TABLE AJ-3 (continued)
Units: 103 Ib/hr.
LOCATION: Otter Creek, Montana (lignite)
LOCATION: Pumpkin Creek, Montana (lignite)
Total C H N
S Ash
Total C H N
As-received coal:
Moisture lost in drying:
INTO DISSOLVING SECTION
1. Dry coal
2. Hydrogen
ifc.
TOTAL:
OUT
3. SRC
4. Filter residue
5. Water
H S
2
f3
6. Light oil
7. Gaseous hydrocarbons
co2
Unconsumed H
TOTAL:
2,062 1,037
607
1,455 1,037 60 12 231 12 103
47 47
1,502 1,037 107 12 231 12 103
833 726 44 10 47 42
2ซ 104 6 1 23 4 101
151 -- 17 134
4 o 4
1 0 1
164 145 19
68 52 16
37 10 27
5 S
1,502 1,037 107 12 231 12 103
As-received coal:
Moisture lost in drying:
INTO DISSOLVING SECTION
1. Dry coal
2. Hydrogen
TOTALi
OUT
3. SRC
4. Filter residue
5. Water
H,S
2
NH3
6. Light oil
7. Gaseous hydrocarbons
CO,
2
Unconsumed H
TOTALi
2,325 1,037
713
1,612 1,037
43
1,655 1,037
833 726
328 104
212
4
S
164 145
68 52
37 10
4
1,655 1,037
72 16 291 12 184
43
115 291 12 184
44 10 47 42
7 2 29 4 182
24 188
0 4
1 4
19
16 ~
27
4 ~~ ~~~ ~~ "*~*
115 16 291 12 184
continued
-------
Al-3 (continued)
Units: 103 Ib/hr.
LOCATION: Coalridqe, Montana
As -received coal :
Moisture lost in drying:
INTO DISSOLVING SECTION
1. Dry coal
2. Hydrogen
TOTAL:
CUT
3. SRC
4 , Filter residue
5. Water
V
6. Light oil
7. Gaseous hydrocarbons
Cฐ2
Un consumed H
(lignite)
Total C H
2,946 1,037
1 1 RQ
1,757 1,037 71
58 58
1,815 1,037 129
833 726 44
376 104 7
320 36
4 0
7 1
164 145 19
68 52 16
37 10
6 6
N O S Ash
18 398 12 221
18 398 12 221
10 47 42
2 40 4 219
284
4
6
27
1,815 1,037 129 18 398
-------
TABLE Al-4. FLOW RATES IN PRODUCTION OF HYDROGEN IN
10,000 TON/DAY SRC PLANTS
Units: 10 Ib/hr.
- o c
01 C O
*J -H 4J
17 Coal feed
10 Oxygen
11 Boiler feed water to gasifier
13 Condensate from off-gas
15 Condensate to aftershift
14 Steam to shift
77.00 16.00 60.00 50.50
17.00 129.7 157.6 156.4
35.78 27.29 33.17 32.91
21.24 9.36 17.64 11.70
84.78 64.44 78.48 77.76
243.9 190.4 227.9 229.1
Sen fi
c 3
c ฃ ง
c *
O 4J
to 0
Stream
17 Coal feed B8.0 J45.0 140.0 180.0 500.0 308.0 225.0 272.0 286.0 270.0 620.0
10 Oxygen 183.6 194.3 201.1 224.3 299.5 249.2 225.3 249.4 277.9 254.2 364.8
11 Boiler feed water to gasifier 38.63 40.88 42.30 47.19 63.00 52.43 47.40 52.47 58.46 53.47 76.74
13 Condensate from off-gas 23.4 57.4 48.96 55.26 222.8 126.5 90.72 103.5 83.88 93.60251.3
15 Condensate to aftershift 91.98 97.2 101.7 113.6 152.8 126.7 113.0 127.1 143.1 129.3 188.5
14 Steam to shift 263.3 257.6 271.0 306.8 354.5 311.7 288.5 321.0 376.2 332.9 434.7
26
-------
TABLE Al-5. GAS STREAMS IN PRODUCTION OF HYDROGEN IN
10,000 TONS/DAY SRC PLANTS
Unitsi 10 molea/hr.
12 Gasifier off-gas: CO
CO,
2
H
Entering shift: CO
Leaving shift:
To dissolving: CO
H,
3 0
<0 C
0) -H
M i-H
D ^H
m M
11.56
0.96
6.66
1.18
11.56
0.96
6.66
0
2.73
9.79
15.5
4.71
2.73
15.5
.*
01
01
M
U
ซ oi a.
JQI 4J CT1 Q. fj* -H fl
Q C JJ C OC n C
J4 --< HJ-H r-l-H 4->lO
eg --< E , -! >, C >, O 0
2 L3 3 < S U Z
- 0
a> c
ฃ2
9.10
0.45
5.00
0.52
9.10
0.45
5.00
0
2.11
7.44
12.0
3.58
2.11
12.0
o al
Hareng
Alabam
c o
o c
y <-t
U. M
10.80
0.80
6.20
0.98
10.60
0.80
6.20
0
2.55
9.05
14.5
4.36
2.55
14.5
c n
0 U
in 0
c .x
-H 0
>; Q
u
Q 2
ft) O
C c
4 -H
a ^H
I/I M
10.98
0.54
6.09
0.65
10.98
0.54
6.09
0
2.55
8.97
14.5
4.32
2.55
14.5
id -D ซ
' *J p 4J
X 0 00
a .* J x
*-* i3 C to
*j a oj o
c ปo
4t . C
m 2: 3 z
.
J^
01
X V
V *-
U O 4)
^ tr.
u o cm -o ซ
.. S 2 S -25
01 4J a 4J ซ-! *J
*J C EC < C
4j o go o o
o ฃ o. x u z
12 Gasifier off-gas: CO 12.43 11.98 12.72 14.19 15.50 14.00 13.25 14.51 17.10 15.09 18.79
C02 1.08 2.22 2.09 2.34 6.54 4.31 3.22 3.84 3.55 3.61 8.06
H2 6.98 8.09 7.79 8.76 13.80 10.72 9.75 10.22 10.55 10.19 15.32
H20 1.30 3.19 2.72 3.07 12.38 7.03 5.04 5.75 4.66 5.20 13.96
Entering shift: CO 12.43 11.98 12.72 14.19 15.50 14.00 13.25 14.51 17.10 15.09 18.79
CO 1.08 2.22 2.09 2.34 6.54 4.31 3.22 3.84 3.55 3.61 8.06
H 6.98 8.09 7.79 8.76 13.80 10.72 9.75 10.22 10.55 10.19 15.32
HO 00000000000
Leaving shift: CO 2.90 2.99 3.08 3.43 4.40 3.70 3.43 3.70 4.14 3.78 5.10
CO 10.60 11.21 11.73 13.10 17.64 14.61 13.04 14.64 16.51 14.92 21.75
H 16.5 17.0 17.5 19.5 25.0 21.0 19.5 21.0 23.5 21.5 29.0
HO 5.11 5.40 5.65 6.31 6.49 7.04 6.28 7.06 7.95 7.18 10.47
2 To dissolving: CO 2.90 2.99 3.08 3.43 4.40 3.70 3.43 3.70 4.14 3.78 5.10
Hn 16.5 17.0 17.5 19.5 25.0 21.0 19.5 21.0 23.5 21.5 29.0
27
-------
TABLE Al-6. SYMBOLS AND VALUES USED FOR CALCULATIONS AROUND
GASIFIER IN 10,000 TON/DAY SRC PLANTS
FEEDS
Total coal
Coal carbon
Coal hydrogen
Coal oxygen
Coal moisture
Filter Residue
Carbon
Hydrogen
Oxygen
OFF-GAS
H2
CO
CO,
Flow Rates
(moles/hr)
W (lb/hr)
c.W /12*
h.Wc/2*
x.W /32*
w.W /18*
\~r
M
'H
M
O
M
H2
M
CO
M
C02
MH20
*c, h, x, w are weight fractions in as-received coal.
28
-------
TABLE Al-7. APPROXIMATE HEAT BALANCES ON DISSOLVING SECTION OF
10,000 TONS/DAY SRC PLANTS
Units: 109 Btu/hr.
Stream
1 Dry coal
2 Hydrogen I carbon monoxide
preheater
TOTAL IN:
3 SRC
4 Filter residue
6 Oil
7 Gas (hydrocarbon + H }
Stack losses
Dry cooling load
Wet cooling load
Losses around filter
Sensible heat in SRC
Losses around dissolver; other
TOTAL OUT:
Stream
1 Dry coal
2 Hydrogen 6 carbon monoxide
Fuel to dissolver 6 vacuum
preheater
TOTAL IN:
3 SRC
4 Filter residue
6 Oil
7 Gas (hydrocarbon + H )
Steain recovered
Stock losses
Dry cooling load
Wet cooling load
Losses around filter
Sensible heat in SRC
Losses around dissolver; other
TOTAL OUT:
o o
n c
41 -H
k >-<
3,2
White,
Illino
18.56 18.84
2.24 1.73
1.49 1.55
22.29 22.12
Fulton
Illino
18.79
2.09
1.53
22.41
13.16 13.16 13. 16
1.83 1.86 1.85
3.29 3.29 3.29
1.7B 1.72 1.78
0.62 0.66 0.65
0.18 0.19 0.18
0.14 0.10 0.13
0.5 0.35 0.56
0.18 0.18 0.19
0.11 0.11 0.11
0.5 0.5 0.5
0 0
c c
H -H
H r-<
-------
TABLE Al-8. APPROXIMATE HEAT BALANCES ON GASIFICATION SECTIONS OF
10,000 TONS/DAY SRC PLANTS
Units: 10 Btu/hr.
Stream
4 Filter residue
17 Coal
14 Steam
TOTAL IN:
16 Hydrogen product
Total steam generated
Ash and slag
Dry cooling load
Het cooling load
TOTAL OUT:
Stream
4 Filter residue
17 Coal
14 Steam
TOTAL IN;
16 Hydrogen product
Total steam generated
Ash and slag
Dry cooling load
Wet cooling load
TOTAL OUT:
9 M
o
2ฃ
1.81
1.03
0.29
3.13
2.38
0.45
0.05
0.14
0.11
3.13
0)
*J C
i-t ฃ
2s
1.
1.
0.
3.
2.
0.
0.
0.
0.
3.
7*
j
*i
E
81
15
29
25
46
39
10
19
11
25
Creek,
u
a 01
0 c
V ฃ
Sฃ
1.76
1.26
0.30
3.32
2.53
0.44
0.05
0.18
0.12
3.32
ซ c
v* -<
P *-i
ffi tH
1.83
0.83
0.27
2.93
2.24
0.39
0.07
0.13
0.10
2.93
a
-< ซ
ฃ ง
tn 4->
81
1.77
1.60
0.34
3.71
2,82
0.47
0.08
0.21
0.13
3.71
- o
01 C
15
1.86
0.19
0.21
2.26
1.73
0.29
0.08
0.09
0.07
2.26
o ซ
CT> E
c a
ฃ -3
ฃ X
1.69
2.67
0.40
4.76
3.60
0.44
0.10
0.44
0.18
4.76
C 0
o c
U. M
1.85
0.64
0.26
2.75
2.09
0.35
0.10
0.12
0.09
2.75
c* 1
o +J
m o
C Jฃ
i ซ
0
Q Z
1.71
1.94
0.35
4.00
3.04
0.40
0.11
0.30
0.15
4.00
ซ 0
c c
I-t r-t
ซ rH
in M
1.87
0.62
0.26
2.75
2.09
0.38
0.08
0.11
0.09
2.75
X o
01 .V
JJ Q
u .
ID Z
1.79
1.61
0.32
3.72
2.81
0.44
0.09
0.25
0.13
3.72
o *
5 a
o o
a a
c
^ z
1.71
1.94
0.36
4.01
3.04
0.48
0.08
0.26
0.15
4.01
.*
V
u IB
* 5
V 4->
ฑ> O
o r
1.71
2.37
0.42
4.50
3.40
0.61
0.06
0.27
0.16
4.50
x
u
0
M
u
c a
H C
x ซ
a. -t->
1 0
& ฃ
1.72
2.01
0.37
4.10
3.11
0.46
0.11
0.27
0.15
4.10
V
0*
o ซ
"2 i
r-t *J
8 j
1.64
3.47
0.49
5.60
4.19
0.55
0.14
0.51
0.21
5.60
30
-------
TABLE Al-9. APPROXIMATE PLANT DRIVING ENERGY REQUIREMENTS FOR
10,000 TONS/DAY SRC PLANTS
Unitsi 10 Btu/hr.
c o
o c
Coal drying
Acid gag removal (two places)
Vacuum tower ejector
Electricity
Oxygen production
Synthesis gas compressor
Hydrogen compressor
Slurry pump
Water treatment & allowance for
other low-level uses
Coal drying
Acid gas removal (two places)
Vacuum tower ejector
Electricity
Oxygen production
Synthesis gas compressor
Hydrogen compressor
Slurry pump
Water treatment 6 allowance for
other low-level uses
0.32 0.05 0.32 0.12
0.30 0.24 0.28 0.28
0.01 0.01 0.01 0.01
0.18 0.18 0.18 0.18
0.33 0.25 0.30 0.30
0.38 0.29 0.36 0.35
i
0.20 0,15 0.18 0.18
0.11 0.11 0.11 0.10
fc
si
-H O
Si
o
*J C7<
-y c
o y
Creek ,
0)
1-1
v
4J
s
1
0.
2.
ฃ
H
4-1
tfl
.-)
O
U
2
03
ffl
s
c
0
s
0.2 0.2
1.48 1.94
is
Ort in 0
II p
X < 0 Z
0.2
1.72
- 5 "S3
>, 0 60
AJ a ai o
c -a
u . c
ซ 2 D 2
X
0)
0)
o
0)
w
a
c
ฃ
u
C d
P
9 o
CM ฃ
(U
S!i
3S
0.19 0.79 0.59 0.55 1.81 1.31 1.04 0.99 0.70 0.82 1.37
0.32 0.34 0.36 0.40 0.52 0.49 0.39 0.44 0.49 0.45 0.64
0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01
0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18
0.35 0.37 0.39 0.43 0.58 0.48 0.43 0.48 0.53 0.49 0.70
0.41 0.45 0.45 0.51 0.72 0.58 0.52 0.57 0.62 0.58 0.84
0.21 0.21 0.22 0.25 0.32 0.27 0.25 0.27 0.30 0.27 0.37
0.10 0.12 0.11 0.11 0.12 0.12 0.12 0.12 0.11 0.12 0.13
0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2
1.97 2.75 2.51 2.64 4.46 3.64 3.14 3.26 3.14 3.12 4.44
31
-------
TABLE Al-10. EFFICIENCY CALCULATION FOR 10,000 TON/DAY SRC PLANTS
Units: 10 Btu/hr.
Coal to dissolving
Coal to gasifier
Total input energy
30 * o co
e c ซ c os
HI -rf U -rf V ~t
3 rt 0
W 1-1
18.56 18.84 18.79 18.72
0.83 0.19 0.64 0.62
19.3919.0319.4319.34
SRC product
Oil product
Gas product
Total steam recovered
Steam required in gasification
Plant driving energy
Boiler stack loss
Fuel to dissolver S vacuum preheater
Total output energy
13.16 13.16 13.16 13.16
3.29 3.29 3.29 3.29
1.78 1.72 1.78 1.78
1.01 0.95 1.00 1.00
-0.27 -0.21 -0.26 -0.26
-2.03 -1.48 -1.94 -1.72
-0.41 -0.29 -0.39 -0.36
-1.49 -1.55 -1.53 -1.46
15.04 15.59 15.11 15.43
Unrecovered heat
4.35
3.44
4.32
3.91
Conversion efficiency %
77.56 81.92 77.77 79.78
Coal to dissolving
Coal to gasifier
Total input energy-
3C <
a z
n z
01 J-< & 4J M *-"
*> C EC fl C
jj 0 90 00
5 X ฃ E O Z
18.22 17.93 17.74 17.63 17.25 17.40 17.80 17.34 17.05 17.34 16.50
1.03 1.15 1.26 1.60 2.67 1.94 1.61 1.94 2.37 2.01 3.47
19.25 19.08 19.00 19.23 19.92 19.34 19.41 19.28 19.42 19.35 19.97
13.16 12.92 12.92 12.92 12.92 12.92 12.92 12.92 12.92 12.92 12.92
3.29 3.29 3.29 3.29 3.29 3.29 3.29 3.29 3.29 3.29 3.29
1.78 1.78 1.78 1.84 1.91 1.84 1.84 1.84 1.91 1.84 1.97
1.07 1.08 1.08 1.13 1.17 1.11 1.14 1.17 1.25 1.17 1.32
-0.29 -0.29 -0.30 -0.34 -0.40 -0.35 -0.32 -0.36 -0.42 -0.37 -0.49
-1.97 -2.75 -2.51 -2.64 -4.46 -3.64 -3.14 -3.26 -3.14 -3.12 -4.44
-0.42 -0.53 -0.51 -0.55 -0.89 -0.71 -0.62 -0.66 -0.68 -0.65 -0.94
Fuel to dissolver ฃ vacuum preheater -1.45 -1.62 -1.50 -1.55 -1.71 -1.67 -1.64 -1.62 -1.52 -1.67 -1.83
Total output energy
SRC product
Oil product
Gas product
Total steam recovered
Steam required in gasification
Plant driving energy
Boiler stack loss
Unrecovered heat
15.19 13.68 14.25 14.10 11.83 12.79 13.47 13.32 13.61 13.11 11.80
4.08 5.20 4.75 5.13 8.09 6.55 5.94 5.96 5.81 6.24 8.17
Conversion efficiency
78.Bl 72.75 75.00 73.32 59.39 66.13 69.40 69.09 70.08 67.75 59.09
32
-------
TABLE Al-11. ULTIMATE DISPOSITION OF UNRECOVERED HEAT IN
10,000 TONS/DAY SRC PLANTS
Unitsi 10 Btu/hr.
ffl H
!งM
P rH
Direct losses
Assigned to dry cooling
Assigned to wet cooling
Gas purification system regenerator
condenser
Total steam turbine condenser
Total gas compressor interstage
cooler
1.86 1.49 1.89 1.63
0.27 0.19 0.25 0.21
0.8 0.62 0.85 0.77
0.30 0.24 0.28 0.28
0.85 0.69 0.80 0.78
0.27 O."21 0.25 0.24
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35
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4.32
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-------
APPENDIX 2
CALCULATIONS ON THE SYNTHOIL PROCESS
BASIS OF ANALYSIS
Calculations on the Synthoil process are required for bituminous
coals at:
1. Jefferson, Alabama
2. Gibson, Indiana
3. Warrick, Indiana
4. Harlan, Kentucky
5. Pike, Kentucky
6. Tuscarawas, Ohio
7. Jefferson, Ohio
8. Somerset, Pennsylvania
9. Mingo, West Virginia
and subbituminous coals at:
10. Lake de Smet, Wyoming
11. Jim Bridger, Wyoming
12. Gallup, New Mexico
The only integrated plant design (including hydrogen production) which
we have seen is that of the Bureau of Mines made for a Wyoming coal and made
specifically'for cost estimating purposes. For the purpose of estimating
water requirements we have chosen to make our own, somewhat simplified,
design using the block diagram from Reference 1 reproduced as Figure A2-1 in
a form suitable for present purposes. The overall material balances, not
including hydrogen production, were made using the following rules.
34
-------
OVERALL MATERIAL BALANCES
1) 50,000 bbl/stream day of dry oil equals 700 x 10 Ib/stream hr
(Reference 1) and the oil is assumed to be 90 wt % carbon, 8.5 wt % hydrogen,
1.0 wt % oxygen and 0.5 wt % nitrogen and other elements.
2) Five barrels of oil are produced from each ton of carbon in the
coal. This is the average of published results:
Ref. No. bbl oil/ton carbon in coal
1 4.7
2 5.3
3 5.0
used in this work 5.0
The feed to the reactors (Streams 2 and 5) must therefore contain
0.833 x 10 Ib/stream hr of carbon. Coal is assumed dried to 0.5 wt %
moisture. This moisture is assumed to remain in the product oil.
3) Hydrogen requirements have been given as:
^ f ,, scf H /bbl oil
Ref. No. 2_
1 4830
2 4200
3 4730
used in this work 4700
4
The hydrogen in Stream 6 is therefore 2.58 x 10 moles/stream hr, or
51.6 x 103 Ib/stream hr. Stream 6 is taken to be 97 mole % H2 and 3 mole % CO.
4) The carbon in the char has been given as:
Carbon in Char as
Ref. No. % of Carbon in Coal
1 about 6.3
2 6
used in this work 6.2
35
-------
so the char (Stream 9) contains 51.6 x 10 Ib/stream hr of carbon; the
hydrogen and oxygen are assumed to be negligible.
5) The oxygen in the coal is assumed converted as follows:
10 percent to gas and oil;
12.8 x 103 Ib/stream hr reacts with CO in Stream 6 to yield
CO which remains in the gas;
the balance is converted to water, Stream 13.
6) The balance of the carbon and hydrogen appears in the gas. The
overall material balance calculations resulting from the above rules are
given on Table A2-1 for each site. The water from phase separation has been
copied onto the summary table, Table A2-2. This stream is controlled by the
oxygen content of the coal.
HYDROGEN PRODUCTION
There are many ways to make hydrogen: 1) The gas can be put through a
steam reforming reaction (this is quite efficient but necessitates burning
char and coal for plant energy, and both char and coal contain sulfur)- 2)
The char, with added coal, can be partially oxidized (gasified) to make
synthesis gas which can be converted to H by the shift reaction (this
procedure yields the sulfur as H S which can be readily removed; the gas
produced in the oil plant is also stripped of H S and is then burnt as a
fuel). We have assumed that gasification is used, and the hydrogen produc-
tion train is shown in Figure A2-2. Extrapolating from Reference 1,
the following rules were used to calculate the various water streams of
Figure A2-2.
1) The gasifier is pressurized and yields hydrogen at 450 psig which is
compressed to 4000 psig for use in the Synthoil reactor.
2) The gasifier off-gas comes off at 1800ฐF. The mole ratio
H2:CO = 0.72. Since the hydrogen stream (No. 6) contains 2.58 x 10 moles
4 4
H2/hr and 0.08 x 10 moles CO/hr, or 2.66 x 10 total moles/hr, and since one
mole CO yields one mole H in a shift reaction, the total CO + H in the
4 4
off-gas must also be 2.66 x 10 moles/hr and must be 1.11 x 10 moles H /hr
4
and 1.55 x 10 moles CO/hr.
36
-------
At two locations, Lake de Smet, Wyoming and Jim Bridger Mine, Wyoming,
the coal is particularly wet and there is not enough byproduct gas to drive
the plant. At these two locations extra coal is gasified to produce extra
gas which is burnt for fuel, as shown on Figure A2-2. At Lake de Smet 7.4
percent of the gasifier off-gas is burnt, and at Jim Bridger 16.7 percent of
the gasifier off-gas is burnt.
3) In addition to char, steam, oxygen and coal are fed to the gasifier
at rates determined by the simultaneous solutions of the carbon, hydrogen and
oxygen elemental balances and the thermal balance. For this high temperature
gasifier it is assumed that 80 percent of the steam feed is decomposed.
Hydrogen in the coal is first used up making the oxygen in the coal into
water; only the surplus is available for reaction. Moisture in the coal
passes unchanged into the gas.
In deriving the equations and performing the calculations, the symbols
and numerical values shown on Table A2-3'were used. The balances are:
Carbon
c.W 712 + 4,300 = II + 15,500 (1)
Hydrogen
Moisture
h.W /2 - x.W /16 +0.8 M = 11,100 (2)
v ( oT
w.Wc/18 +0.2 MST + x.Wc/16 = MH2Q (3)
Oxygen
0.4 Mr,m + OX = 7,750 + Kl (4)
Thermal
9 9
H W + 0.748 x 10 + 21,100 M = 3.598 x 10 + 20,500 M
C C o J_ C_,O 2.
+ 34,800 M (5)
37
-------
Equations (1) to (4) can be rewritten to give:
M = 0.0833 c.W_ - 11,200 (6)
CO2 C
M = 13,875 - 0.625 h.VJ + 0.0781 x.W (7)
ST (- '-
MH20
= 2,775 + 0.0556 w.W - 0.12.5 h.W + 0.0781 x.W (8)
OX = -9,000 + W (0.0833 c + 0.25 h - 0.0312 x) (9)
Equation (5) gives:
W (H - 1,708 c - 8,838 h - 1,935 w - 1,070 x) = 2.424 x 10 (10)
W \^
The coal feed, steam and oxygen have been calculated and entered on
Table A2-2. Selected gas rates have been calculated and entered on Table
A2-4.
Table A2-3 shows 11,100 moles H and 15,500 moles CO in the gasifier
off-gas (as calculated in Step 2 above) and Equations (1) to (10) use these
quantities. At Lake de Smet and Jim Bridger, Wyoming, where extra gas is
made for fuel, the gasifier off-gas composition must be that shown on Table
A2-4 and Equations (1) to (10) must be modified accordingly.
4) Water is added to the gasifier off-gas to quench it. The quenched
gas then goes to the first stage shift reaction which the gas leaves at 900ฐF
and assumed to be in equilibrium at 950ฐF.
Let M1 be the moles/hr leaving the first stage shift; let. M be, as
before, the moles/hr leaving the gasifier; and let M = moles quench
water/hr. The equilibrium equation is:
M'C02 M'H2
W & = 4.55 (11)
CO H20
38
-------
The carbon balance is:
M'C02 + M'CO = MC02
or
M'C02 = MC02 + 15'5ฐฐ - M'CO = (Say) K12 - M'CO
From the stoichiometry of the shift reaction:
M'H2 +M
-------
The results of the calculations have been entered onto Tables A2-2 and A2-4.
5) When the gas is cooled to 300ฐF, assuming a pressure at this point
of 430 psig, the water vapor is reduced to 15 mole % and all the rest of the
water in the gas condenses. Total removal of CO is assumed in the first
acid gas removal system. In fact, the removal is over 95 percent and the
assumption of total removal simplifies the calculations while introducing
negligible error.
6) The gas leaving the second stage shift reactor is in equilibrium at
550ฐF. The compositions of the gas streams are (in moles/hr):
C00
2
H20
CO
IN
0
^20
mco
OUT
,
CO 2
m'H20
800
25,800
Also, let in be the moles of steam added.
From the carbon balance:
= mCO
the equilibrium equation is:
(25,800)
(800)(m'H20)
= 46.7 (19)
which gives m'H2o having found m'co2 from Equation (18). The steam added,
iri , can be found from the hydrogen balance :
= 25'8ฐฐ + m'H20
7) It is sufficiently accurate to assume 100 percent removal of CO in
the second acid gas removal and to take the clean condensate, Stream 17, as
40
-------
100 percent of the water vapor in the gas leaving the second stage shift,
Stream 22.
PLANT ENERGY REQUIREMENTS
The approximate plant energy requirements are given on Table A2-5,
Those listed are the principal requirements, but not all the energy loads in
the plant. Since all the energy requirements may not have been found, the
stated efficiencies may be high. This will not affect cooling water require-
ments, which is the sole reason for preparing Table A2-5. In preparing that
table the following calculations were made :
1) Drying coal requires 1100 Btu/lb water evaporated plus 200 Btu/lb
coal feed to heat the coal.
2) The slurry contains 2 Ib oil per 1ฑ> coal and the pumps require
146 Btu/lb dry coal.
3) The heat load on the dissolver-heat exchanger-phase separation
'section was taken from Reference 1. The heat load to char de-oiling was
treated similarly.
4) Coal and char are assumed fed to the gasifier through lock hoppers
and variations from coal to coal is too small a part of the total energy to
be considered.
5) Acid gas removal requires 30,000 Btu per mole CO removed. The rate
of removal of CO is given on Table A2-4.
6) The waste heat recovery in the hydrogen production plant was calcu-
lated from the heat capacities of the gases. Since at 300ฐF and 410 psig the
water vapor will saturate the gas when it is 13 mole percent of the gas,
there will be no condensation in the waste heat recovery unit. The heat
recovered is:
1419 M + 1407 M + 2098 M + 1672
where M is the moles/hr in Stream 22 leaving the second stage shift. That
is:
3.744 x 107 + 2098 14 + 1672 M_ Btu/hr
CO2 H2O
41
-------
The loads on the dry and wet coolers will also be needed and were calcu-
lated as follows. At 140ฐF after acid gas removal, water vapor is reduced to
1.25 x 10 moles/hr. The dry cooling load is:
2.984 x 107 + 18,756 H Btu/hr
where M is the moles of water condensed in the dry cooler.
The wet cooling load is 3.126 x 1C)7 Btu/hr for all the plants.
7) The hydrogen compression load is the same for all the plants.
8) The energy for oxygen production is 2.03 x 10 Btu/thousand Ibs
oxygen.
9) Electricity generated is 15,000 kw at 11,700 Btu/kw-hr.
10) The low level requirements are arbitrary.
11) The boiler stack loss is 15 percent of the fuel burnt, which is the
total heat load.
The approximate plant conversion efficiencies are shown on Table A2-6.
All heating values are calculated from the formula:
W
H = 14,540 V? + 62, 000 (W__ - )
C xi o
where W , W , and W are the weights of carbon, hydrogen and oxygen in the
C H O
stream.
ULTIMATE DISPOSITION OF UNKECOVERED HEAT
The ultimate disposition of unrecovered heat is given on Table A2-7.
The calculations were made as follows. The direct losses consist of the
energy to dry coal for the .Synthoil reactor (Table A2-5), the boiler stack
loss (Table A2-5), char de-oiling energy, which is a stack loss (Table A2-5) ,
30 percent of the electricity generation energy, 30 percent of the slurry
pump energy and an arbitrary allowance for convection losses. Other losses
begin with the acid gas removal regenerator condenser which is taken as all
the energy into the acid gas removal (Table A2-5). Air cooling consists of
air cooling in the hydrogen plant (calculation is described above) plus 80
percent of the energy to condense the condensate out of phase separation (at
1040 Btu/lb condensate). The energy dissipated in the turbine drive
42
-------
condensers is taken as 70 percent of slurry pump energy plus 70 percent of
the energy to feed solids to gasifier (i.e., the lock hopper compressor
energy) plus 70 percent of hydrogen compression energy plus 70 percent of
oxygen production energy plus 70 percent of electrical generation. Compressor
interstage cooling is taken as 30 percent of lock hopper compressor energy
plus 30 percent of hydrogen compression energy plus 30 percent, of oxygen
production energy. The wet cooling load is the balance.
In estimating solid residues these plants use no flue gas desulfuriza-
tion. All the ash in the entering coal (fed to reactor plus gasifier) leaves
the gasifier and is listed as bottom ash.
REFERENCES, APPENDIX 2
1. 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., 1975; summarized
in: Kate11, S., and White, L. G., "Economic Comparison of Synthetic
Fuels Gasification and Liquefaction," presented at ACS National Meeting,
Division of I&EC, New York, April 1976.
2. Akhtar, S., Mazzocco, N. J., Weintraub, M., and Yavorsky, P- M.,
"SYNTHOIL Process for Converting Coal to Non-Polluting Fuel Oil,"
4th Synthetic Fuels from Coal Conference, Oklahoma State University,
Stillwater, Oklahoma, May 6-7, 1974.
3. Akhtar, S. , Lacey, J. J., Weintraub, M., Rezik, A. A., and Yavorsky,
P. M., "The SYNTHOIL ProcessMaterial Balance and Thermal Efficiency,"
presented at 67th Annual Meeting, AIChE, Washington, D.C., Dec. 1-5, 1974.
43
-------
COAL
WATER
VAPOR
COAL
PREPARATION
ft DRYING
HYDROGEN
HYDROGEN
PRODUCTION
a
COMPRESSION
STEAM
a
WATER
OXYGEN WATER
CONDENSATE
RECYCLE OIL
COAL
SLURRY
PREPARATION
230ฐ F
WATER
CONDENSATE
CHAR
I
HEAT '
EXCHANGER
I I
I I
800* F
PHASE
SEPARATION
CHAR
DE-OILING
REACTOR
-*- OIL
GAS
-> SALES GAS
* PLANT FUEL
Figure A2-I. Flow diagram for~ฃ>rocess water streams in Synthoil process.
-------
COAL
aCHAR
OXYGEN
GASIHER
FUE.L (WHERE REQUIRED)
\ 1800'F
900*f
DIRTY
CONDENSATE
STEAM
CLEAN
CONDฃNSATE<
Figure A2-2. Flow diagram for hydrogen production in Synthoil process.
-------
TABLE A2-1. MATERIAL BALANCE ON SYNTHOIL PLANT
EXCLUSIVE OF HYDROGEN PRODUCTION
Units: 10 lii/streajn hr.
LOCATION: Jefferson, Alabama
LOCATION: Gibson, Indiana
Total Moisture C
CTi
2 Coal, as-received 1173.3 27.0 833
fi P- Ash NtS
51.6 44.6 188.9 28.2
4 Water lost in
drier
21.2 21.2
5 Coal, dry 1152.1
6 Makeup hydrogen 74.0
TOTAL 5,6 1226.1
5.8 833.0 51.6 44.6 IBS.9 28.2
9.6 51.6 12.6
842.6 103.2 57.4 188.9 28.2
7 Oil
B Gas: CO from CO
in makeup
hydrogen
Other
13 Water from phase
separation
705.8
5.8 630.0 59.5
3.5
240.5
22.8
9.6 25.6
151.4 41.2 4.5 24.7
51.6 188.9
2.5 20.3
TOTAL 7,8,9,13
1226.1
842.6 103.2 57.4 188.9 28.2
Stream Total Moisture C_
2 Coal, as-received 1221.3 122.1 833
4 Water lost in
drier
116.0 116.0
H^ O Ash HES
56.2 92.8 76.2 39.0
5 Coal, dry 1105.3
6 Makeup hydrogen 74
TOTAL 5,6 1179.3
6.1 833 56.2 92.8 78.2 39.0
9.6 51.6 12.8
842.6 107.8 105.6 78.2 39.0
7 Oil
8 Gas: CO_ from CO
in makeup
hydrogen
Other
9 Char
706.1
6.1 630
59. 5
3.5
"N f
} 272-6 \
J (.
13 Water from phase
separation
129.8
70.8
9.6 25.6
151.4 41.2 9.3 35.5
51.6 78.2
7.1 63.7
TOTAL 7,8,9,13
842.6 107.8 105.6 78.2 39.0
(continued)
-------
Table A2-1 (continued)
Units: 10 Lb/streain hr.
LOCATION: Warrick, Indiana
2
4
5
6
7
a
9
13
Coal, as-received 1285.5 119.6
Water lost in
drier 113.2 113.2
Coal, dry 1172.3 6.4
Makeup hydrogen 74
TOTAL 5,6 1246.3
Oil 706.4 6.4
Gas: CO from CO
in makeup
hydrogen "> (
\ 282.8 /
Other J V
Char 158.3
Water from phase
separation 98.8
TOTAL 7,8,9,13 1246.3
833 59.1 120.8 106.7 46.3
833 59.1 120.8 106.7 46.3
9.6 51.6 12.8
842.6 110.7 133.6 106.7 46.3
630 59.5 7 3.5
9.6 25.6
151.4 41.3 12.1 42.8
51.6 106.7
9.9 88.9
842.6 110.7 133.6 106.7 46.3
LOCATION: Harlan, Kentucky
4
5
6
7
8
9
13
Water lost in
drier 33.1
Coal, dry 1037.6
Makeup hydrogen 74
TOTAL 5,6 1111.6
Oil 705.4
in makeup
hydrogen > j
254.5
Other J 1
Char 92.3
Water from phase
separation 59.4
TOTAL 7,8,9,13 1111.6
33 ^
5.4 833 54.6 81.4 40.7 22.5
9.6 51.6 12.8
842.6 106.2 94.2 40.7 22.5
5.4 630 59.5 7 3.5
;9.6 25.6
151.4 40.8 8.1 19.0
51.6 40.7
5.9 53.5
842.6 106.2 94.2 40.7 22.5
(continued)
-------
Table A2-1 (continued)
Units: 10 Hi/stream hr.
LOCATION: Pike, Kentucky
Stream
2 Coal, as-received
4 Water lost in
drier
Total
1046.5
26.2
Moisture C
31.4 833
26.2
H
53.4
O
55.5
Ash HSE
50.2 23.0
5 Coal, dry 1020.3 5.2 833 53.4 55.5 50.2 23.0
6 Makeup hydrogen 74 9.6 51.6 12.8
TOTAL 5,6 1094.3 842.6 105.0 68.3 50.2 23.0
7
8
9
13
Oil 705.2
Gas: CO from CO
in makeup
hydrogen -\
} 253.9 j
Other ) '
Char 101.8
Water from phase
separation 33.4
TOTAL 7,8,9,13 1094.3
5.2 630 59.5 7 3.5
f 9.6 25.6
1 151.4 42.2 5.6 19.5
51.6 50.2
3.3 30.1
842.6 105.0 68.3 50.2 23.0
LOCATION: Tus
5, Ohio
Coal, as-received 1169.9
Total Moisture C_
73.7 833
2. P_ Ash NCS
57.3 94.8 65.5 45.6
4 Water lost in
drier
67.9
67.9
5 Coal, dry 1102.0
6 Makeup hydrogen 74
TOTAL 5,6 1176.0
5.8 833 57.3 94.8 65.5 45.6
9.6 51.6 12.8
842.6 108.9 107.6 65.5 45.6
7
8
9
13
Oil
Gas: CO from CO
in makeup
hydrogen
Other
Char
Water from phase
separation
TOTAL 7,8,9,13
705.8 5.8
} -- c
117.1
72.8
1176.0
630 59.5 7 3.5
9.6 25.6
151.4 42.1 9.5 42.1
51.6 65.5
7.3 65.5
842.6 108.9 107.6 65.5 45.6
(continued)
-------
Table A2-1 (continued)
Units: 10 Ib/stream hr.
LOCATION: Jefferson, Ohio
Stream Total Moisture C H
4 Water lost in
drier 22.2 22.2
5 Coal, dry 1149.3 5.9 833 57.4
6 MaXeup hydrogen 74 9.6 51.6
TOTAL 5,6 1223.3 842.6 109.0
7 Oil 705.9 5.9 630 59.5
8 Gas: CO from CO
in makeup
hydrogen "^ f 9.6
\ 307.4 /
Other J I--- 151.4 45.5
9 Char 169.9 51.6
13 Water from phase
separation 40.1 4.0
TOTAL 7,8,9,13 1223.3 -- 842.6 109.0
0 Ash NSS
62.1 118.3 72.6
12.8
74.9 118.3 72.6
7 3.5
25.6
6.2 69.1
116.3
36.1
74.9 118.3 72.6
LOCATION: Somerset, Pennsylvania
Total Moisture C
2
4
5
6
7
8
9
13
Coal, as-received 1125.7 20.3 833 45.0 34.9 153.1
Water lost in
drier 14.7 14.7
Coal, dry 1111.0 5.6 833 45.0 34.9 153.1
Makeup hydrogen 74 9.6 51.6 12.8
TOTAL 5,6 1185.0 842.6 96.6 47.7 153.1
Oil 705.6 5.6 630 59.5 7
Gas: CO from CO
in makeup
hydrogen -s r -~ 9.6 25.6
\ 261.8 1
Other J L -- 151.4 35.8 3.5
Char 204.7 51.6 153.1
Water from phase
separation 12.9 1.3 11.6
TOTAL 7,8,9,13 1185.0 842.6 96-6 47.7 153.1
39.4
39.4
-
39.4
3.5
35.9
-
39.4
(continued)
-------
Table A2-1 (continued)
Units: 10 Lb/stream hr.
LOCATION: Mingo, West Virginia
LOCATION: LaXe de Smet, Wyoming
Ln
O
Stream Total Moisture C_
2 Coal, as-received 1047.8 23.1 833
i O Ash N5S
54.5 61.8 51.3 24.1
Total Moisture
Water lost in
drier
17.9
17.9
5 Coal, dry 1029.9 5.2 833 54:5 61.8 51.3 24.1
6 Makeup hydrogen 74 9.6 51.6 12.8
TOTAL 5,6 1103.9 842.6 106.1 74.6 51.3 24.1
7
a
9
13
Oil
Gas : CO from CO
in makeup
hydrogen "
Other
Char
Water from phase
separation
TOTAL 7,8,9,13
705.2 5.2
\ 256.0 |
/ V. ~
102.9
39.8
1103.9
630 59.5 7 3.5
9.6 25.6
151.4 42.6 6.2 20.6
51.6 51.3
4.0 35.8
842.6 106.1 74.6 51.3 24.1
2 Coal, as-received 1724.7 407.0 833
4
H 9. Ash N6S
60.4 227.7 167.3 29.3
Water lost in
drier
398.4 398.4
S Coal, dry 1326.3
6 Makeup hydrogen 74
TOTAL 5,6 1400.3
8.6 833 60.4 227.7 167.3 29.3
9.6 51.6 12.B
842.6 112.0 240.5 167.3 29.3
7 Oil
8 Gas: CO_ from CO
in maXeup
hydrogen
Other
9 Char 218.9
708.6 8.6 630 59.5 7
drogen "\ f
\ 267.1
er J ^
13 Water from phase
separation 205.7
TOTAL 7,8,9,13
3.5
9.6 25.6
151.4 31.9 22.8 25.8
51.6 167.3
00 20.6 185.1
1400.3 842.6 112.0 240.5 167.3 29.3
(continued)
-------
Table A2-1 (continued)
Units: 10 Ib/stream hr.
LOCATION: Jim Bridger, Wyoming
LOCATION: Gallup, New Mexico
Total Moisture
Total Moisture
2 Coal, as-received 1605.1 340.3 833 51.4 223.1 131.6 25.7
4 Water lost in
drier 332.3 332.3
5 Coal, dry 1272.8 8.0 833 51.4 223.1 131.6 25.7
6 Makeup hydrogen 74 9.6 51.6 12.8
TOTM, 5,6 1346.8 842.6 103.0 235.9 131.6 25.7
7 Oil 708.0 8.0 630 59.5 7 3.5
8 Gas: CO ฃrom CO
in makeup
hydrogen N r 9.6 25.6
\ 25"'5
Other J L-- 151.4 23.4 22.3 22.2
9 Char 183.2 51.6 131.6
13 Water from phase
separation 201.1 20.1 181.0
2 Coal, as-received 1318.0 199.0 833 61.9 137.1 67.2
4 Water lost in
drier 192.4 192.4
5 Coal, dry 1125.6 6.6 833 61.9 137.1 67.2
6 Makeup hydrogen 74 9.6 51.6 12.8
TOTAI, 5,6 1199. & 842.6 113.5 149.9 67.2
7 Oil 706.6 6.6 630 59.5 7
8 Gas: CO from CO
in makeup
hydrogen s r 9.6 25.6
259.1
Other ) \. 151.4 42.5 13.7
9 Char 118.8 51.6 - 67.2
13 Water from phase
separation 115.1 11. S 103.6
19.8
19.8
19.8
3.5
16.3
TOTAL 7,8,9,13
842.6 103.0 235.9 131.6 25.7
TOTAL 7,8,9,13 1199.6
842.6 113.5 149.9 67.2 19.E
-------
TABLE A2-2. SUMMARY OF FLOWS FOR HYDROGEN PRODUCTION AND OTHER WATER STREAMS
IN 50,000 BBL/DAY SYNTHOIL PLANTS
Units: 103 lfe/hr
C
0
ui <
M C
td a)
is s>5
203
199
155
274
73
73
64
y
u
Q) 4-1
H 01
ft ซ
196
197
152
268
63
77
66
m
nJ
(0
M
m
u o
CO -H
EH O
220
197
154
278
83
65
61
o
w
0)
4H O
IH -rH
0) ,ฃ
in O
214
189
148
265
59
77
66
td
H
*ia
4-1 >
ID rH
>H U)
OJ C
e c
O Q)
en ft
213
193
163
266
59
82
68
H
C
Cn
H
O
Cn 4-1
CJ to
H 0)
S 5
196
197
151
267
62
77
66
4-1
0)
CO
CD en
id c
cu E
td ^i
1-3 3
413
271
183
352
243
25
45
0)
en
H tj1
>H C
CQ -H
E |
>-3 3
449
322
196
351
234
22
43
o
u
H
^ X
a o
3 S
rH
rH 5
td o)
0 2
258
216
151
302
130
46
53
Stream
3 Coal to gasifier
10 Oxygen to gasifier
U 21 Steam to gasifier
14 Water to gas quench
15 Medium quality con-
densate from hydrogen
16 Steam to second stage
shift
17 Clean condensate
13 Water from phase
separation 23 71 99 59 33 73 40 13 40 206 201 115
-------
TABLE A2-3. SYMBOLS AND VALUES USED TO CALCULATE BALANCES AROUND
GASIFIER IN 50,000 bbl/day SYNTHOIL PLANTS
TOTAL COAL:
Flow Rates
Wc(lb/hr)
Enthalpies
H (Btu/lb) VWC
(moles/hr)
(Btu/mole)
(Btu/hr)
Coal carbon
Coal hydrogen
Coal oxygen
Coal moisture
Char carbon
Steam
Oxygen
Off-gas:
H2
CO
co2
H 0
c.W^/12*
h.Wc/2*
x.Wc/32*
w.W /18*
4,300
MST
OX
11,100
15,500
M
C02
Muoซ
174,000 0.748 x 1Q9
21,100 21,100 M
O J.
0 0
135,300 1.502 x 1Q9
135,200 2.096 x 1Q9
20,500 20,500 M
34,800 34,800 MTI0^
*c, h, x, w are weight fractions in as-received coal.
53
-------
TAปLE A2-4. SUMMARY OF GAS STREAMS FOR HYDROGEN PRODUCTION
IN 50,000 BBL/DAY SYNTHOIL PLANTS
Units: 10 mole/hr.
4)
-------
TABLE A2-5. PLANT ENERGY REQUIREMENTS IN 50,000 BBL/DAY SYNTHOIL PLANTS
9
Units: 10 Btu/hr.
Jefferson,
Alabama
0.26
0.17
0.4
0.23
0.02
0.49
-.05
0.49
0.39
0.17
0.50
0.50
Gibson,
Indiana
0.37
0.18
0.4
0.23
0.02
0.50
-.05
0.49
0.42
0.17
0.50
0.53
War rick,
Indiana
0.38
0.19
0.4
0.23
0.02
0.50
-.05
0.49
0.41
0.17
0.50
0.53
Harlan,
Kentucky
0.25
0.16
0.4
0.23
0.02
0.50
-.05
0.49
0.40
0.17
0.50
0.50
Pike,
Kentucky
0.24
0.15
0.4
0.23
0.02
0.50
-.05
0.49
0.40
0.17
0.50
0.49
Tuscarawas ,
I Ohio
0.30
0.17
0.4
0,23
0.02
0.50
-.05
0.49
0.40
0.17
0.50
0.51
Jefferson ,
Ohio
0.30
0.17
0.4
0.23
0.02
0.48
-.05
0.49
0.38
0.17
0.50
0.50
Somerset ,
Pennsylvania
I
0.24
0.16
0.4
0.23
0.02
0.50
-.06
0.49
0.39
0.17
0.50
0.49
Mingo,
West Virginia
1
0.23
0.15
0.4
0.23
0.02
0.49
-.05
0.49
0.40
0.17
0.50
0.49
Jj
0)
W
at (r>
'd c
rH
S %
%ฃ
0.78
0.25
0.4
0.23
0.02
0.56
-.05
0.49
0.51
0.17
0.50
0.64
Jim Bridger,
Wyoming
0.69
0.23
0.4
0.23
0.02
0.57
-.05
0.49
0.51
0.17
0.50
0.62
Gallup ,
New Mexico
0.47
0.19
0.4
0.23
0.02
0.51
-.05
0.49
0.44
0.17
0.50
0.55
Drying coal to
liquefaction
Slurry pumps
Heat exchanger of
phase separation
^ Char de-oiling
Solids feed to
hydrogen gasifier
Acid gas removal in
hydrogen production
Waste heat recovery in
hydrogen production
Hydrogen compression
Oxygen production
Electrical generation
Water treatment &
other low-level uses
Boiler stack loss
Approximate total
heat load 3.57 3.76 3.77 3.57 3.54 3.64 3.59 3.53 3.52 4.5 4.38 3.92
-------
TABLE A2-6. APPROXIMATE THERMAL EFFICIENCIES OF 50,000 BBL/DAY SYNTHOIL PLANTS
9
Units: 10 Btu/hr.
c
o
w tg
^ B
M a
rti 0)
>fi w
tv
u
- 3
0) 4J
^! C
H (1)
in
(0
fti
M
0 0
in -H
c
0
in
M
a)
m o
M-l -H
0) J5
^ o
(0
-H
^ง
-P >
i
M in
(U C
e c
O 0)
W (X
m
H
C
Cn
H
O
Cn 4->
C in
H (U
s s
0)
w
a) Cn
T^l C
H
0) g
31
V-l
0)
d
H tn
n c
n -i-i
9|
o
o
ซ X
CM 01
D S
r-H
H 5
tt) Q)
U 3
Coal to synthoil reactor 15 14.9 14.97 14.88 14.96 15.09 15.35 14.72 14.98 14.14 13.64 14.39
Coal to gasifier 2.79 2.85 2.87 2.82 2.80 2.84 2.80 2.79 2.80 3.39 3.81 2.92
Total coal 17.79 17.74 17.84 17.7 17.76 17.93 18.15 17.51 17.78 17.53 17.45 17.81
Heating value of product
oil 12.7 12.7 12.7 12.7 12.7 12.7 12.7 12.7 12.7 12.7 12.7 12.7
Heating value of gas
produced 4.72 4.68 4.69 4.69 4.77 4.74 4.97 4.39 4.79 4.0 3.48 4.73
Heating value of gasifier
off-gas burnt for fuel 0 0 0 0 0 0 0 0 0 0.50.90
Plant driving energy -3.57 -3.76 -3.77 -3.57 -3.54 -3.64 -3.59 -3.53 -3.52 -4.5 -4.38 -3.92
Total output energy 13.9 13.6 13.6 13.8 13.9 13.8 14.1 13.6 14.0 12.7 12.7 13.5
Unrecovered heat 3.94 4.12 4.22 3.88 3.83 4.13 4.07 3.95 3.81 4.83 4.75 4.3
Approximate conversion
efficiency % 77.9 76.8 76.3 78.1 78.4 77.0 77.6 77.4 78.6 72.4 72.8 75.9
-------
TABLE A2-7. DISPOSITION OF UNRECOVERED HEAT IN 50,000 BBL/DAY SYNTHOIL PLANTS
9
Units: 10 Btu/hr.
Jefferson,
Alabama
0.26
0.5
0.23
0.051
0.051
0.10
1.192
0.49
0.12
0.87
0.27
1.00
Gibson,
Indiana
0.37
0.53
0.23
0.051
0.054
0.10
1.335
0.50
0.15
0.90
0.28
0.96
1
Warrick ,
Indiana
0.38
0.53
0.23
0.051
0.057
0.10
1.348
0.50
0.15
0.90
0.28
1.04
Harlan,
Kentucky
0.25
0.50
0.23
0.051
0.048
0.10
1.179
0.50
0.13
0.87
0.27
0.93
Pike,
Kentucky
!
0.24
0.49
0.23
0.051
0.045
0.10
1.156
0.50
0.13
0.86
0.27
0.91
Tuscarawas ,
Ohio
0.30
0.51
0.23
0.051
0.051
0,10
1.242
0.50
0.14
0.88
0.27
1.10
I
i Jefferson,
J Ohio
!
0.30
0.5
0.23
0.051
0.051
0.10
1.232
0.48
0.12
0.86
0.28
1.10
Somerset,
Pennsylvania
0.24
0.49
0.23
0.051
0.048
0.10
1.159
0.50
0.13
0.86
0,27
1.03
Mingo ,
iWest Virginia
0.23
0.49
0.23
0.051
0.051
0.10
1.152
0.49
0.13
0.86
0.27
0.91
j
Lake de Smet ,
Wyoming
0.78
0,64
0.23
0.051
0.075
0.10
1.876
0.56
0.26
1.01
0.31
0.81
!
Jim Bridger,
Wyoming
0.69
0.62
0.23
0.051
0,069
0.10
1.76
0.57
0.25
0.99
0.31
0.87
Gallup,
i New Mexico
i
0.47
0.55
0.23
0.051
0.057
0.10
1.458
0.51
0.17
0.92
0.29
0.95
Coal drying
Boiler stack loss
Char de-oiling
Electricity used
Slurry pump loss
Other direct loss
Subtotal direct losses
Acid gas removal regen-
erator condenser
Air cooling in phase sep-
aration & hydrogen plant 0.12
Turbine drive condensers
Compressor interstage
cooling
Wet cooling load
Grand Total 3.94 4.12 4.22 3.88 3.83 4.13 4.07 3.95 3.81 4.83 4.75 4.3
-------
APPENDIX 3
CALCULATIONS ON THE HYGAS PROCESS
Calculations on the Hygas process are needed for bituminous coals at:
1. Jefferson, Alabama
2. Gibson, Indiana
3. Warrick, Indiana
4. Tuscarawas, Ohio
5. Jefferson, Ohio
6. Armstrong, Pennsylvania
7. Fayette, West Virginia
8. Monongalia, West Virginia
9. Mingo, West Virginia
for subbituminous coals at:
10. Gillette, Wyoming
11. Antelope Creek, Wyoming
12. Belle Ayr, Wyoming
13. Hanna Coal Field, Wyoming
14. Decker, Montana
15. Colstrip, Montana
16. El Paso, New Mexico
17. Gallup, New Mexico
and for lignites at:
18. Marengo, Alabama
19. East Moorhead, Montana
Gasifier and pretreatment balances have been provided by the Institute
of Gas Technology for the Hygas-oxygen process operating on two coals shown
on Table A3-1. Complete calculations of material and energy have been made
for two reference plants, one in West Virginia and one in Wyoming. The
58
-------
required information for plants consuming bituminous coals has been taken
from the West Virginia reference plant. The required information for plants
consuming subbituminous coals and lignites has been taken from the Wyoming
reference plant.
First the two reference plants will be described. The flow diagram is
shown on Figure A3-1. Wyoming coal is dried to 2 percent moisture before
feeding to the gasifier. West Virginia coal is pretreated in air to prevent
caking. Pretreatment material rates are given on Table A3-2. The pretreatment
balance was made by assuming a 1.1 wt % loss as fines and 1.08 wt % loss as
tar and oil. The coal incurs about a 10 percent weight loss during treatment.
The pretreatment energy information is given on Table A3-3. The imbalance on
the pretreater is assumed lost to the atmosphere.
The coal is slurried to 50 percent solid concentration (by weight) with
recycle slurry oil from downstream in the process. The char-oil slurry is
then pumped to the gasifier operating pressure of 1200 psig and heated in an
external heater to 200ฐF. Gasifier flow rates are given on Table A3-4, and
energy rates are given on Table A3-5. The gasifier is in thermal balance,
and the only energy rates listed are those needed to define the plant unrecovered
heat and cooling load. The raw off-gas contains the slurry oil as vapor.
The oil made about equals the oil lost in purification or left in the product
gas.
According to most process flow sheets, the gasifier product gas is
quenched with oil to about 400ฐF to cool the gas and recover a portion of the
slurry oil without condensation of water. The steam is left in the feed gas
so that the amount of steam required for shift conversion is minimized.
A portion of the gas next undergoes shift reaction at an equilibrium
temperature of 750ฐF to adjust the ratio of hydrogen to CO for the downstream
methanation reaction. The shifted gas is cooled to 100ฐF to ensure condensa-
tion of the oil. Water also condenses at this point. A circulating water
scrub may be used to ensure that all the ammonia, phenol and other soluble
species are removed from the gas. It has been assumed that these species can
be adequately removed by the quantity of water which condenses. Circulating
water has not been shown on Figure A3-1.
A physical-solvent based system is used for acid-gas removal to recover
the remainder of the BTX stream, dehydrate the gas, generate an H S-rich gas
59
-------
for sulfur recovery, discharge a CC^-rich gas with minimum H S concentration
and provide a treated gas of sufficient purity that only a nominal sulfur
guard is required prior to methanation. Based on the recommendation of IGT,
the following losses are assumed to occur in gas purification: 0.5% loss of
H and CO, 1% loss of CH. and 25% loss of C H . The process is assumed
2 4 ^ o
capable of reducing CO to one percent. All other acid gases were completely
absorbed.
Gas and water streams for the two reference plants are shown on Table
A3-6. The calculations are illustrated by the Wyoming case. In the raw gas,
Stream 6, there is:
CO 20.55
H2 25.21
Total: 45.76
After shift, in Stream 10, one wants H /CO = 3.1, so in Stream 10 one must have:
CO 11.16
H2 34.60
Total: 45.76
The moles of gas shifted are 20.55 - 11.66 = 9.39, so CO in Stream 10 =
19.32 + 9.39, and the HO in Stream 11 = 25.81 - 9.39 (assuming complete
condensation at 100ฐF)- Most of the "other gases" are assumed to leave with
the condensate. A little N will be left in the gas as shown. (For the West
Virginia plant the ratio after shift was H /CO = 3.05, because there is less
ethane to hydrogenate in the methanator.)
Streams 8 and 9, which are needed for heat calculations, can now be
found. Let x be the fraction of gas in Stream 6 which enters the shift reactor.
Since 9.39 thousand moles/hr are shifted, the composition of Stream 9 is:
CO 20.55x - 9.39
H2 25.21x + 9.39
C02 19.32x +9.39
H20 25.81x - 9.39
and since Stream 9 is in equilibrium at 750ฐF:
(CO )(H )
= 11.8
(CO)(H20)
so, x = 0.827.
60
-------
Stream 12 reflects the losses after gas purification, as stated above.
In methanation all of the CO is assumed reacted to methane and water, and the
ethane is assumed hydrogenated to methane.
The heat balance and additional energy information for the gasifier
trains are given on Table A3-7. The heat loads were calculated from the
enthalpies of the streams listed on Table A3-6, For a solvent type acid gas
removal process, 28,400 Btu are consumed to remove 1 Lb mole of CO .
On Table A3~8 is tabulated the total plant driving energy (most of which
is taken from preceding tables,, the rest of which is arbitrary) and the
calculation of unrecovered heat and conversion efficiency. Table-A3-8 suggests
that for Wyoming, all the net driving energy goes to produce steam for the
gasifier and that ail the steam used for other uses could be raised in waste
heat recovery units. At West Virginia even some of the steam for the gasifier
is shown raised in waste heat recovery units. This is not practical. Waste
heat is not available to raise steam at much over 700 psi. Steam for the
gasifiers must be raised in a boiler and, in addition, some of the 700 psi
steam from waste heat recovery must be superheated in a boiler for use to
drive turbines. In fact, the plants have surplus low temperature steam.
Unless this steam is used, the theoretical plant conversion efficiencies
given overstate the practical efficiency. This does not affect the cooling
water requirements as the surplus waste heat will be lost through air coolers,
not by evaporative cooling.
The ultimate disposition of unrecovered heat, needed for estimation of
cooling water,- is presented on Table A3-9 and was calculated as follows. The
direct losses are taken from preceding tables, except electricity used which
is 30,000 kw and slurry pump loss which is 30 percent of the driving energy.
The dry cooling load is from Table A3-7. The wet cooling load is from Table
A3-7 plus the "allowance" on Table A3-8. The turbine condenser load is 100
percent of pretreatment air compressor, plus 70 percent of slurry pump, plus
70 percent of oxygen production compressors, plus 70 percent of energy to
produce electricity. The gas compressor interstage cooling load is 30 percent
of the oxygen production compressors.
From the reference plants the necessary information has been scaled for
all the desired plants and entered on Table A3-10 in weight flow units and on
61
-------
Table A3-11 in energy flow units. First the energy in the coal to pretreat-^
1
ment was taken to be that of the reference plants and the weight of coal is!
as determined.
All coals are dried to 2 percent. If W Ib coal/hr containing w fracti'aS
moisture are dried to 2 percent, then the water evaporated is:
w.W - (l-w)W x 2/98 = W(1.0204w - 0.0204)
The weight of water evaporated in the dryer is entered on Table A3-10. The
weight of steam to the gasifier is taken from the reference plants (Stream -5
as are the effluent water streams (Streams 11 and 14); all water streams are
entered on Table A3-10.
The energy to dry coal is 1150 Btu/lb water evaporated, and the total
energy is entered on Table A3-11. Next on Table A3-11 is the other driving*
energy from Table A3-8, the net driving energy, the boiler stack loss which'
is 12 percent of the boiler fuel, and the boiler fuel. The coal to the
boiler is copied, in weight units, on Table A3-10. l'|
The energy table is then completed by entering fines, tar and oil, and I
product gas from Table A3-8, and calculating the unrecovered heat and conver;
sion efficiency. Since the only changes in the ultimate disposition of ^
unrecovered heat were in the direct losses, these were not entered on Table $
A3-11 but taken directly from Table A3-9 onto the work sheets in a later
appendix.
62
-------
OXYGEN STEAM
WYOMING
COAL
W, VIROINlA
COAL
WATER
1
HEAT
EXCHANGER
\
S^j METHA
1
>
NATOft
STEAM
}f
PRODUCT GAS (T?)
^=/
BFW
8FW
Figure A3-1. Flow diagram for Hygas process.
-------
TABLE A3-1. ANALYSIS OF COAL USED IN REFERENCE HYGAS PLANTS (wt %)
West Virginia Wyoming
Moisture 2.5 19.9
C 74.6 54.2
H 4.7 4.0
O 3.3 14.5
N 1.5 0.8
S 2.7 0.6
Ash 10.7 6.0
100 100
64
-------
TABLE A3-2. PRETREATMENT MATERIAL RATES FOR REFERENCE HYGAS PLANTS
TABLE A3-2. PRETREATMENT MATERIAL RATES FOR REFERENCE RYGAS PLANTS
01
(Jl
Moisture
C
H
O
N
S
Ash
WEST VIRGINIA:
C
H
0
N
S
Ash
Moisture
Coal IN
(103 Ib/hr)
809
51
36
16
30
116
26^
1,084
Coal IN
HO3 Ib/hr)
262
713
53
191
10
e
78
1,315
737
36
29
15
21
113
(10 Ib/hr)
22
713
53
191
10
8
76
1,075
Hater Vapor OUT
240
Coal OUT Fines OUT
(103 Ib/hr) (103 Ib/hr)
7.7
0.6
0.7
0.2
0.4
2.2
Tar 6 Oil OUT
(103 Ib/hr)
9.4
0.8
0.9
0.1
0.4
11.6
(803 x 103 Ib/hr)
{10 moles/hr)
N2 22.0
O2 5.8
CO
co2
H2ฐ
so2
CH4
C2H6
C3He
Gas OUT
(10 moles/hr)
21.0
0
0.7
2.8
6.3
0.2
0.5
0.1
0.2
-------
TABLE A3-3. PRETREATMENT ENERGY RATES FOR REFERENCE HYGAS PLANTS
9
Units: 10 Btu/hr
Wyoming West Virginia
IN
Coal 12-18 14-70
OUT
Coal 12.18 12.79
Steam 0.26
Fines, tar & oil (HHV) 0.32
Sensible heat of effluent
solids at 800ฐF 0.14
Total heat of effluent
gases at 800ฐF 0.82
Radiation & convective
losses 0.63
Heat to dry coal 0.26 0
Energy to compress air to
10 psig 0.09
66
-------
TABLE A3-4. GASIFIER FLOW RATES FOR REFERENCE HYGAS PLANTS
Stream
3
4
5
7
Pretreated coal
Slurry oil
Oxygen
Steam
Ash residue*
Wyoming
[10 Ib/hr)
West Virginia
(10 Ib/hr)
1
1
1
,075
,075
249
,015
99
951
951
295
1,434
132
(10 moles/hr)
(10 moles/hr)
Raw gas:
CO
H2
co2
CH.
C2H6
Other**
20.
25.
19.
25.
13.
1.
0.
55
21
32
81
77
04
76
14
26
25
34
15
0
1
.41
.61
.68
.10
.82
.37
.44
Composition of ash residue: Wyoming C wt % 17.80, H wt % 0.19; West
Virginia C wt % 9.56, H wt % 1.09.
, NH, HS, HCN, COS.
67
-------
TABLE A3-5. GASIFIER ENERGY INFORMATION FOR REFERENCE HYGAS PLANTS
Units: 10 Btu/hr.
Steam (1250 psia, 1000ฐF)
Energy to produce oxygen
Slurry pump
Recycle oil heater
Sensible & chemical heat in ash
residue at 1850ฐF
Wyoming
1.48
0.57
0.04
0.06
0.32
West Virginia
2.09
0.68
0.04
0*
0.31
*The coal is not from the pretreatment and the slurry heater is not needed.
68
-------
Units: 10 molea/hr.
5 treara numhters from Figure A3-1.
TABLE A3-6. GAS AND WATER STREAMS FOR REFERENCE HYGAS PLANTS
Stream 10:
Wyoming
CO
H2
co2
H20
CH
4
C2H6
Other
CO
H2
Cฐ2
"lฐ
CH4
C,H
2 6
Other
CO
H2
co2
H20
CH4
C2H6
Other
3
4
3
4
2
0
0
7
30
25
11
11
0
0
11
34
28
0
13
1
0,
.56
.36
.34
. 47
.38
. 18
. 13
.60
.24
. 37
.95
. 39
.86
.63
. 16
.60
.71
. 77
.04
.09
West Virginia
7.
14
14
18
8
0
0
2.
16.
15.
10.
7.
0
0.
10
30
29.
0
15.
0.
0.
.98
.75
.23
.89
.49
.21
.80
. 14
. 14
.74
.92
.33
.16
.64
.12
.89
.97
.82
.37
.09
Wyoming
Stream 11:
Stream 12:
Stream "13 :
Stream 14:
Stream 15:
H20
Other
CO
H2
co2
CH4
C2H6
N2
H2
Cฐ2
CH4
C2H6
H2ฐ
"2
H2ฐ
H2
co2
CH4
N
16
0.
11
34
0
13.
0
0
0.
0.
26.
0
11.
0
11
0
0
26
0.
.42
.67
.10
.43
.60
.63
.78
.09
. 35
.60
.29
.10
.09
.10
.35
.60
.29
.09
West Virginia
29
1
10
30
0
15
0
0
0.
0.
26.
0
10
0
10
0
0.
26
0
.81
.35
.12
.89
.56
.82
.37
.09
.65
.56
68
.00
.09
.00
.16
.56
.68
.09
Stream 15, scf/day:
Btu/hr:
250 x 10
10.11 x 10
250 x 10
10.34 f. 10
-------
TABLE A3-7. APPROXIMATE HEAT BALANCE AND ENERGY INFORMATION ON GASIFIER
TRAIN FOR REFERENCE HYGAS PLANTS
9
Units: 10 Btu/hr
Wyoming West Virginia
IN
Pretreated coal 12.18 12.79
Steam 1-48 2.09
Recycle oil heater 0.06
OUT
13.72 14.88
Product gas 10.11 10.34
Steam produced 2.38 3.10
Combustibles lost in gas purification 0.26 0.25
Dry cooling of process streams 0.55 0.78
Wet cooling of process streams 0.10 0.10
Sensible & chemical heat in ash residue 0.32 0.31
13.72 14.88
Energy consumed in gas purification 0.80 0.84
70
-------
TABLE A3-8. DRIVING ENERGY FOR REFERENCE HYGAS PLANTS, FUEL REQUIRED IN
BOILER, EFFICIENCY, AND UNRECOVERED HEAT
Units: 109 Btu/hr
Driving Energy
Coal drying
Pretreatment air compression
Slurry pump
Recycle oil heater
Oxygen production
Gas purification
Gasifier steam
Electrical production (30,000 kw)
Steam raised in process
Allowance for water treatment & other
low-level uses
Net driving energy required
Boiler stack losses
Coal to boiler
Coal to pretreatment
Fines, tar & oil
Product gas
Unrecovered heat
Wyoming
0.26
0.04
0.06
0.57
0.80
1.48
0.35
(-2.38)
0.30
1.48
0.20
1.68
12.18
10.11
3.75
West Virginia
0.09
0.04
0
0.68
0.84
2.09
0.35
(-3.10)
0.30
1.29
0.18
1.47
14.70
0.32
10.34
5.51
Conversion efficiency
72.9%
65.9%
71
-------
TABLE A3-9. ULTIMATE DISPOSITION OF UNRECOVERED HEAT FOR REFERENCE HYGAS PLANTS
9
Units: 10 Btu/hr
Coal drying
Boiler stack losses
Pretreatment losses
Slurry pump
Hot ash residue
Electricity used
Combustibles lost in purification
Subtotal Direct Losses
Wyoming
0.26
0.20
0.01
0.32
0.11
0.26
West Virginia
0.18
1.59
0.01
0.31
0.11
0.25
1.16
2.45
Assigned to dry cooling
Assigned to wet cooling
Acid gas removal regenerator condenser
Total turbine condensers
Total gas compressor interstage cooling
Total
0.55
0.40
0.80
0.67
0.17
3.75
0.78
0.40
0.84
0.84
0.20
5.51
72
-------
TABLE A3-10. FLOW RATES IN 250 x 10 SCF/DAY HYGAS PLANTS
Units. 10 Lb/hr
c
0
v 3
0) ,-(
- nj
g 5
* C
U H
U C
H a
ra c
S H
(0
3
fD
M
fl
U 0
tn -H
ฃg
C
0
m
Vt o
flj j^
H, o
tr>
c
0
M
2
ง
>
>,
C
OJ
tt.
"Si
CJ -H
4J
0} jJ
>i 10
a -H
H M
(0 --!
O AJ
c in
0 0)
ฃ 2
Q-
O>
c
X
"&
M
>
10
U
1)
-ซJ Qi
r-* O
-H >>
o 4
Coal to pretreatment 1149.3 1204.9 1261.8 1139.5 1122,1 1097.0 1050.0 1035.2 1028.0 1537.9
Water evaporated in
drying 0* 92.73 88.05 44.46 0* 0* 5.43 6.41 0* 445.69
Steam to gasifier 1,434 1,434 1,434 1,434 1,434 1,434 1,434 1,434 1,434 1,015
Dirty condensate 537 537 537 537 537 537 537 537 537 296
Methanation water 180 1BO 180 180 180 180 180 180 180 200
Coal to boiler 114.93 130.33 135.62 117.83 112.21 109.70 105.71 104.23 102.80 248.74
u
Oi
o c
i 1 -H
-U 0
s?
^
M
C
-i B
rH 0
Sf
-H 0
0 2
U
C rH
C OJ
rd -H
' ซ
)-. C
11 IU
Ji -M
CJ C
01 O
Q ฃ
Q.
ij 3
V) -P
rH C
0 0
U E
O
U
- -i-i
O X
w a>
a z
P-
3
0
0
- X
Is
nj ฃ
u z
ฐ" s
c 3
Jj J5
M >9
j:
8 .
Z ง
yi c
S r
Coal to pretreatment 1353.3 1308.3 1142.6 128.;.8 1367.0 1413.0 1077.9 2280.9 1730.1
Water evaporated in
drying
Steam to gasifier
Dirty condensate
Hethanation water
Coal to boiler
334.19 263.00 114.27 287.12 312.47 206.19 144.09 1086.93 602.01
1,015 1,015 1,015 1,015 1,015 1,015 1,015 1,015 1,015
296 296 296 296 296 296 296 296 296
200 200 200 200 200 200 200 200 200
202.22 185.62 143.53 185.65 202.02 192.58 139.82 147.79 308.24
Coal moisture content is below 2.5%.
73
-------
6
TABLE A3-11. ENERGY FLOWS IN 250 x 10 SCF/DAY HYGAS PLANTS
q
Units: 10 Btu/hr
Coal to pretreatment
Coal drying
Other driving energy
Net driving energy
Boiler stack loss
Coal to boiler
Fines, tar b oil
Product gas
Unrecovered heat
Conversion effi-
ciency (\)
Coal to pretreatment
Coal drying
Other driving eneroy
Net driving energy
Boiler stack loss
Coal to boiler
Fines, tar I, oil
Product gas
Unrecovered heat
Conversion effi-
ciency ( \ )
Jefferson,
Alabama
14.70
0
1.29
1.29
0.18
1.47
0.32
10.34
5.51
65.92
Antelope Creek,
Wyoming
12.18
0. 38
1.22
1.60
0. 22
1.82
0
10.11
3.89
72.21
GLbson ,
Indiana
14.70
0.11
1.29
1.40
0.19
1.59
0.32
10.34
5.63
65.44
Belle Ayr,
Wyoming
12.18
0. 30
1.22
1.52
0.21
1.73
0
10. 11
3.80
72.68
Warrick,
Indiana
14.70
0.10
1.29
1.39
0.19
1.5B
0.32
10.34
5.62
65.48
M O
o a
u
Q ri
C M
C V
X I*
12.18
0.13
1.22
1.35
0.18
1. 53
0
10.11
3.60
73.74
0 C
J 0
a n
iti QJ
0 O "^ O
14.70 14.70
0.05 0
1.29 1.29
1.34 1.29
0.18 0.18
1.52 1.47
0.32 0.32
10.34 10.34
5.56 5.51
65.72 65.92
n
O M V -H
Sm ฃ >
EC > ซ
14.70 14.70
0 0.01
1.29 1.29
1.29 1.30
0.1B 0.18
1.47 1.48
0.32 0.32
10.34 10.34
5.51 5.52
65.92 65.88
0 0
o o
ox - X
ft V Oj Q)
a E 3 E
&l M
M & R3 ฃ
12.18 12.18
0.24 0.17
1.22 1.22
1.46 1.39
0.20 0.19
1.66 1.58
0 0
10.11 10.11
3.73 3.65
73.05 73.47
4 Q
- C C
M * H V
n) -H M 4J en
C 0 w -g
CO) C W MO
O W -H 01 -H >,
14.70 14.70 12.18
0.01 0 0.51
1.29 1.29 1.22
1.30 1.29 1.73
0.1B 0.18 0.24
1.48 1.47 1.97
0.32 0.32 0
10.34 10.34 10.11
5.52 5.51 4.04
65.88 65.92 71.45
a
ฃ
U
MB WC
12.18 12.18
1.25 0.69
1.22 1.22
1.47 1.91
0.20 0.26
1.67 2.17
0 0
10.11 10.11
3. 74 4.24
73.00 70.45
74
-------
APPENDIX 4
CALCULATIONS ON THE BIGAS PROCESS
Calculations for the Bigas process are required for bituminous coals at:
1. Bureau, Illinois
2. Shelby, Illinois
3. Vigo, Indiana
4. Kemmerer, Wyoming
and for lignites at:
5. Slope, North Dakota
6. Center, North Dakota
7. Scranton, North Dakota
8. Chupp Mine, Montana
Two designs (for economic analysis) are available from the Bureau of
Mines . We have extracted all necessary information from these reference
designs, one for a Montana subbituminous coal and one for a Kentucky bitumi-
nous coal, and used the reference designs as models from which to determine
the required information by extrapolation to the chosen coals. It should be
noted that at this time representative steady state operation of the Bigas
plant has not been achieved. First, details of the reference designs will be
given.
The process flow diagram is Figure A4-1. Coal is fed, as a 50 percent
slurry in water, to a spray dryer as shown in the upper center of the figure.
The main flow streams, taken from Reference 1, are entered on Table A4-1 as
are the gas stream analyses at five points labeled in Figure A4-1. The elemental
balances are reasonably closed. The Bigas process yields negligible hydrocarbon
byproduct'.. The hydrogen balances, expressed as equivalent weights of water,
are shown on Table A4-2.
On Table A4-3 are presented the analyses of the chosen coals calculated
after drying to 1.3 percent moisture as is done in the reference plants.
75
-------
Also shown on Table A4-3 are: 1) calculated higher heating values; 2) Ib/hr
9
dried coal fed assuming 12.5 x 10 Btu/hr for bituminous coals and
n
12.1 x 10 Btu/hr for lignites; 3) Ib/hr water evaporated to dry the coal to
1.3 percent calculated as 0.987wx/(100-w) where x = Ib/hr dried coal and w =
% moisture in as-received coal; 4) Ib/hr as-received coal which equals
moisture plus dried coal.
On Table A4-4 are given water equivalent hydrogen balances for the
chosen Bigas plants. Most of the quantities come from Tables A4-2 and A4-3.
It is assumed that if steam heat is needed in the spray dryer, the heat can
be transferred through a wall so that water is not consumed. Live steam, as
shown in the Kentucky reference plant, has not been assumed. The balances on
Table A4-4 are forced to close because the condensate is varied to ensure
this.
To determine the cooling water requirement, an estimate is made of the
auxiliary energy required to drive the plants. The estimate is given on
Table A4-5 as well as the plant thermal efficiency. The energy needed to
vaporize water in the feed coal is calculated for each coal. This energy is
lost up the stack.
The slurry feed pump for the western Kentucky reference plant consumes
9
about 4,000 hp, that is about 0.035 x 10 Btu/hr assuming a steam turbine
drive requiring 11,700 Btu/kw-hr. The energy for other plants has been
scaled by the rate of dry coal feed. Of this energy 70 percent is lost in
the turbine condenser and 30 percent is lost through heating the slurry or
through pipe walls.
The gas purification system is assumed to be hot potassium carbonate
requiring 30,000 Btu/mole CO^ removed with 34 x 1Q3 moles CO removed per
hour on the average (the average difference between Streams 2 and 3 on Table
A4-1). This energy is dissipated in the condenser of the acid gas removal
regenerator.
The gasifier steam is given in Table A4-4.
The production of 495 x 10 Ib/hr of oxygen at 1,250 psig requires
93,000 kw or 1.09 x 1Q9 Btu/hr. The energy input is for steam to compressor
drives for compressing air and oxygen. The energy content of the compressed
oxygen is very small; 70 percent of the input energy is lost in the turbine
condensers and 30 percent is lost in the compressor interstage coolers.
76
-------
Enough electricity is generated to run the plant (particularly the
cooling water circulation pumps and the acid gas removal liquor circulation
9
pumps). 42,000 kw are generated requiring 0.5 x 10 Btu/hr with 70 percent
q
of this (0.35 x 10' Btu/hr) being lost in the turbine condensers.
An additional allowance is made, based on experience, for energy consumed
in water treatment and for other losses.
1 9
According to the Bureau of Mines , 2.2 x 10 Btu/hr will be recovered in
the two waste heat recovery units. This is quite a. conservative recovery.
The balance of the energy required is produced by raising steam in a
coal fired boiler assumed to operate at 85 percent efficiency with .15 percent
stack loss.
The overall thermal efficiency is calculated from the formula:
HHV product fuel
HHV coal to gasifier + boiler
The energy not recovered as product fuel is also listed on Table A4-5.
It is obtained by burning coal in a boiler. It remains to find how this
energy is dissipated to the atmosphere and how much cooling water is needed.
Part of this information is presented on Table A4-6. On this table the stack
losses are the sum of drying energy and boiler stack losses. The electricity
generated and slurry pump transmitted energy is next listed. The carbon
losses have been entered so as to force total unrecovered heat to equal the
9
values on Table A4-5. A loss of 0.4 x 10 Btu/hr for bituminous coals and
9
nearly zero for lignites occurs simply because 12.5 x 10 Btu/hr are fed as
9
bituminous coals and only 12.1 x 10 Btu/hr as lignites. When the losses for
bituminous coals are converted to weight units by taking 14,500 Btu/lb for
carbon, the apparent loss is 4 percent of the carbon in the feed coal for all
cases, and this is problably too high. However, for the purpose of studying
water quantities all that matters is that this energy loss has been assigned
to "direct losses" which cannot require cooling water.
The coal ash leaves the gasifier as slag with a heat content of about
560 Btu/lb which is used to evaporate quench water.
77
-------
The energy to the acid gas removal system is listed next. The con-
densers are frequently air cooled. Reference 2 shows that air cooling is
preferable if cooling water costs more than about $0.46/thousand gallons. A
lot of heat is dissipated through the condensers on the turbine drives for
oxygen production, electrical generation and the slurry pumps. Dry cooling
is expensive here, but a wet/dry combination will be used at some sites.
Interstage cooling on air and oxygen compressors will be wet cooling, unless
cooling water is severely restricted or very expensive (Reference 2).
The remaining unrecovered heat is lost by cooling process streams in the
gas production train and is also the auxiliary energy added for water treat-
ment and allowances in Table A4-5. It is shown that air, or dry cooling, is
more economical on process streams down to about 140ฐF, with wet cooling
below this temperature. Much the largest part of the load, which is condens-
ing water out of gas streams, occurs above 140ฐF. Most of the auxiliary
energy will go to ammonia recovery stills which are likely to require wet,
low-temperature condensers. On Table A4-6 the balance of the unrecovered
heat has been arbitrarily distributed 50 percent to wet cooling and 50 percent
to dry cooling.
In copying the water quantities from Table A4-4 onto the work sheets,
the quantity of dirty water input was taken as the sum of water to char
quench and water to slurry coal.
REFERENCES, APPENDIX 4
1. 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.
2. "Water Conservation and Pollution Control in Coal Conversion Process,"
Report EPA 600/7-77-065, U.S. Environmental Protection Agency, June 1977.
78
-------
Figure A4-1. Bigas Process Flowsheet,
-------
TABLE A4-1. FLOW RATES IN REFERENCE BIGAS PROCESSES"
Western
Feed to Gasifier
Coal (1.3% moisture)
Oxygen
Steam
Water Feeds
Steam to dryer
Water vaporized to
quench char
ง Product Gas
Gas Streams
(10 moles/hr)
1, Gasifier off-gas
2, Aftershift
3, Into methanation
4, Out of methanation
5, Product
946 x
12.5 x
499 x
410 x
201 x
214 x
250 x
9.90 x
Cฐ2 CO CH4
11.6 36.5 12.
32.3 13.0 12.
0.3 13.0 12.
0.3 0 25.
0.3 0 25.
10
10
10
10
10
10
10
10
9
2
2
1
1
Kentucky
3 Ib/hr
9 Btu/hr
3 Ib/hr
3 Ib/hr
3 Ib/hr
3 Ib/hr
scf/day
Btu/hr
H2 H2ฐ Other
20.2 7.3 1.8
40.5 56.9 1.8
40.5 0.4 0.5
1.5 13.0 0.5
1.5 0 0.5
Montana
1089 x
12.1 x
488 x
691 x
214 x
250 x
9.90 x
Cฐ2 CO CH4
18.6 30.6 12.
35.1 13.0 12.
0.3 13.0 12.
0.3 0 25.
0.3 0 25.
10 3 Ib/hr
10 Btu/hr
10 3 Ib/hr
10 3 Ib/hr
0
10 3 Ib/hr
106 scf/day
10 9 Btu/hr
H2 H2ฐ
7 23.8 17.7
4 40.2 70.9
4 40.2 0.4
3 1.2 13.0
3 1.2 0
Other
0.6
0.6
0.4
0.4
0.4
-------
TABLE A4-2. WATER EQUIVALENT HYDROGEN BALANCES FOR
TWO BIGAS PLANTS FROM REFERENCE 1
Water Equivalent to Hydrogen
(103 Ib/hr)
Western Kentucky Montana
IN
Water equivalent of hydrogen in coal 428 446
1.3% moisture in coal 13 14
Steam to gasifier 410 691
Water vaporized to quench char 214 214
Live steam to spray drier 201 0
Water vaporized from coal slurry (equals
weight of coal fed) 946 1,089
2,212 2,454
OUT
Condensate (Stream 2-3) 1,017 1,269
Water from methanation (Stream 4) 234 234
Water equivalent of hydrogen in product
gas (Stream 5) 931 932
2,182 2,435
Error in balance: 1.4% 0.1
81
-------
TABLE A4-3. ANALYSES OF VARIOUS COALS DRIED TO 1.3% MOISTURE
FOR FEED TO BIGAS PROCESS
w. Kentucky Bureau, Shelby, Vigo, Kemmerer,
(Ref. 1) 111- Hi-
Type
Moisture
C
H
0
N
S
Ash
HHV calculated*
Dried coal feed**
As received coal feed
Water removed on drying**
Type
Moisture
C
H
0
N
S
Ash
HHV calculated*
Dried coal feed**
As-received coal feed**
Water removed on drying**
*103 Btu/lb.
**103 Ib/hr.
1.3
73.4
5.0
7.9
1.4
3.8
7.2
S 13-3
T
946
Montana
[Ref. 1)
sub-
bit.
1.3
66.8
4.6'
18.2
0.8
0.7
7.6
11.1
1089
1.3
70.6
4.9
9.7
1.4
3.4
8.7
12.7
984
1170
186
Slope,
N.D.
1.3
64.2
4.7
8.2
1.5
3.5
16.6
11.8
1059
1228
169
Center,
N.D.
Ind.
1.3
74.9
5.2
9.5
1.6
0.7
7.7
13.4
933
1111
178
Scran ton.
N.D.
Hyp.
1.3
73.0
5.1
9.1
1.2
1.0
9.3
13.1
954
981
27
Chupp Mine,
Mont.
1.3
58.4
4.7
19.4
1.1
3.2
11.9
10.0
1210
2164
954
1.3
61.8
4.3
17.0
0.9
1.4
13.3
10.4
1163
1814
651
1.3
62.7
4.3
16.2
1.0
2.1
12.4
10.6
1141
1898
757
1.3
64.5
4.0
17.0
1.0
0.5
11.7
10.6
1141
1840
696
82
-------
TABLE A4-4. WATER EQUIVALENT HYDROGEN BALANCES FOR BIGAS PLANTS
Units: 10 Ib/hr as HO.
Bureau, Shelby, Vigo, Kernmerer, Slope, Center, Scranton, Chupp Mine,
111. 111. Ind. Wyo. N.D. N.D. N.D. Mont.
IN
Water equivalent of hydrogen
in coal
Moisture in coal
Steam to gasifier
Water vaporized to quench char
Water to slurry coal
TOTAL
OUT
Condensate
Water from methanation
Water equivalent of hydrogen
in product gas
TOTAL
434
13
410
214
984
2055
890
234
931
2055
448
14
410
214
1059
2145
980
234
931
2145
437
12
410
214
933
2006
841
234
931
2006
438
12
410
214
954
2028
863
234
931
2028
512
16
691
214
1210
2643
1478
234
931
2643
450
15
691
214
1163
2533
1368
234
931
2533
442
15
691
214
1141
2503
1338
234
931
2503
411
15
691
214
1141
2472
1307
234
931
2472
-------
TABLE A4-5. REQUIREMENTS FOR AUXILIARY ENERGY IN BIGAS PLANTS
Units: 10 Btu/hr.
CO
Coal drying
Slurry pump
Gas purification
Gasifier steam
Oxygen production
Electrical production
Water treatment & allowances
TOTAL
Less energy recovered
Energy out of boilers
Boiler stack losses
Net coal to boilers
Plant overall thermal
efficiency %
Unrecovered energy
As-received coal feed to
boiler (1Q3 Ib/hr)
Bureau,
111.
0.19
0.04
1.02
0.45
1.09
0.50
0.30
3.59
(2.20)
1.39
0.24
1.63
70.1
4.23
She Iby ,
111.
0.17
0.04
1.02
0.45
1.09
0.50
0.30
3.57
(2.20)
1.37
0.24
1.61
70.2
4.21
Vigo,
Ind.
0.18
0.04
1.02
0.45
1.09
0.50
0.30
3.58
(2.20)
1.38
0.24
1.62
70.2
4.22
Kemmerer ,
Wyo.
0.03
0.04
1.02
0.45
1.09
0.50
0.30
3.43
(2.20)
1.24
0.22
1.46
71.0
4.06
Slope,
N.D.
0.95
0.05
1.02
0.76
1.09
0.50
0.30
4.67
(2.20)
2.47
0.43
2.90
66.0
5.10
Center,
N.D.
0.65
0.04
1.02
0.76
1.09
0.50
0.30
4.36
(2.20)
2.16
0.38
2.54
67.6
4.74
Scranton, '
N.D.
0.76
0.04
1.02
0.76
1.09
0.50
0.30
4.47
(2.20)
2.27
0.40
2.67
67.0
4.87
Chupp Mine ,
Mont.
0.70
0.04
1.02
0.76
1.09
0.50
0.30
4.41
(2.20)
2.21
0.39
2.60
67.3
4.80
151
158
143
113
514
378
415
394
-------
TABLE A4-6. ULTIMATE DISPOSITION OF UNKECOVEKED HEAT IN BIGAS PLANTS
Units: 10 Btu/hr.
Stack losses
Electricity used & pump
losses
Carbon loss
SUBTOTAL, Direct Losses
Slag quench
Acid gas removal regenerator
condenser
CD
01 Turbine steam condensers
Compressor interstage
cooling
Air cooling in the process
Water cooling in the process
GRAND TOTAL, Unrecovered
Heat
Carbon lost as % of feed coal
Bureau, Shelby, Vigo, Kemmerer, Slope, Center, Scranton, Chupp Mine,
111.
0.43
0.16
0.41
1.00
0.04
1.02
1.14
0.33
0.35
0.35
4.23
4.1
111.
0.41
0.16
0.41
0.98
0.10
1.02
1.14
0.33
0.32
0.32
4.21
4.1
Ind.
0.42
0.16
0.40
0.98
0.04
1.02
1.14
0.33
0.36
0.35
4.22
3.9
Wyo.
0.
0.
0.
0.
0.
1.
1.
0.
0.
0.
4.
3.
25
16
40
81
04
02
14
33
36
35
05
9
N.D.
1.38
0.16
0.01
1,55
0.08
1.02
1.14
0.33
0.49
0.48
5.09
0.1
N.
1.
0.
0.
1.
0.
1.
1,
0.
0.
0.
4.
0.
D.
03
\
16
01
20
08
02
14
33
49
48
74
T
_L
M.
1.
0.
0.
1.
0.
1.
1.
0.
0.
0.
4.
0.
D.
16
16
01
33
08
02
14
33
49
48
87
1
Mont.
1.
0.
0.
1.
0.
1.
1.
0.
0.
0.
4.
0.
09
16
02
27
08
02
14
33
48
48
80
2
-------
APPENDIX 5
CALCULATIONS ON THE SYNTHANE PROCESS
Synthane plant designs are required for bituminous coals at:
1. Jefferson, Alabama
2. Gibson, Indiana
3. Sullivan, Indiana
4. Floyd, Kentucky
5. Gallia, Ohio
6. Jefferson, Ohio
7. Armstrong, Pennsylvania
8. Kanawha, West Virginia
9. Preston, West Virginia
and for subbituminous coals at:
10. Antelope Creek, Wyoming
11. Spotted Horse, Wyoming
12. Colstrip, Montana
Designs for economic analysis have been given by the Bureau of Mines
for a Wyoming subbituminous and a Pittsburgh seam bituminous coal. We have
taken the gasifier details from Reference 1, and an ash quench design from
Reference 2, and made the calculations for the rest of the plant. The design
using the Wyoming coal has been presented in great detail , and the design
using the Pittsburgh coal follows the same procedure. Both the Wyoming and
the Pittsburgh designs are given below. The water streams and heat loads for
all the bituminous coals have been extrapolated from the Pittsburgh design.
The water streams and heat loads for all the subbituminous coals have been
extrapolated from the Wyoming design.
Figure A5-1 is the flow diagram. The coal analyses, after drying to 4.3
percent moisture where drying is required, are given on Table A5-1. Flow and
86
-------
energy rates for the two reference designs are given on Table A5-2. The
stream numbers on Table A5-2 correspond to those on Figure A5-1. The coal
feed, oxygen feed, steam feed, gasifier off-gas and product gas (Streams 1,
2, 3, 4 and 13) come from Reference 1. The char compositions, and hence the
heating value, were estimated from Reference 2 and are presented in Table A5-
11 (details will be found in Reference 3), The heating value of the tar was
calculated from the composition which is the residue of carbon and hydrogen
to close the elemental balances around the gasifier. There is no need here
to distinguish tar and char, and the distinction is approximate.
The total condensate (Stream 5 plus Stream 6) results when the gasifier
off-gas is cooled to 273ฐF as shown in Figure A5-1. The steam raised by
quenching char (Stream 6) will vary with the ash content of the coal and has
been estimated for each case.
The shift gas reaction is taken to be in equilibrium at 750ฐF, so that
in Stream 8:
(CO )(H )
= 11.8
(H20)(CO)
Also in Stream 8:
(H )/(CO) is set equal to 3.18
These two equations, with the carbon, hydrogen and oxygen elemental balances
around the shift reactor, fix both Streams 7 and 8.
The water left in the gas after shift is mostly condensed when the gas
is cooled to 225ฐF, as shown on Figure A5-1, and the balance is condensed at
100ฐF after acid gas removal. Water made in the methanator is equivalent to
the CO reacted as shown on Table A5-2.
Overall hydrogen balances for the two reference plants, with hydrogen
expressed in units of HO equivalent, are given in Table A5~3. Hydrogen
balances for the chosen sites are given in Table A5-4. On Table A5-4 the
moisture and hydrogen in the coal are taken from Table A5-1 when the coal
9 9
feed rate is 15,91 x 10 Btu/hr for bituminous coals and 17,08 x 10 Btu/hr
87
-------
for subbituminous coals. The rate of ash production varies with the coals.
This results in variations in the small quantity of steam raised by quenching
ash. This further results in small variations in the steam added for the
shift reaction and in the condensate recovered after the scrub. All the
remaining streams are unchanged from the reference plants. This procedure
gives the biggest errors when the ash content of the coal is most different
from the reference coal.
Heat balances around the gasifiers at the two reference locations are
shown on Table A5-5. An "unaccounted loss" has been introduced to force a
balance. This is assumed lost directly to the atmosphere. By calculating
the duty of the various heat exchangers and waste heat recovery units, the
heat balance has been extended to the complete gasifier train as shown on
Table A5-6. An additional unaccounted loss has been found which is arbitrarily
assumed 50 percent lost to cooling water and 50 percent lost directly to the
atmosphere.
Some of the char from the gasifier is burnt in a boiler to provide energy
to drive the plant. The amount of char burnt is calculated in Table A5-7.
Wyoming coal is dried from 20 percent to 4.3 percent moisture and the coal is
heated to 220ฐF. Pittsburgh coal requires no drying. The lock hopper
compressors use 6,800 kw . Gas purification is by the hot potassium carbonate
process consuming 30,000 Btu/mole CO . The energy for oxygen production is
that required to compress air to 90 psia and oxygen from 15 psia to 1015 psia,
which is 2.17 x 10 Btu/lb oxygen. The electricity produced is more than
enough for pumping the circulating cooling water and gas purification liquor .
The other uses listed are arbitrary. The steam raised in the process can all
be used, and so it is subtracted from the need.
The overall plant heat balances can now be calculated and are presented
in Table A5-8. It remains to find how the unrecovered heat is dissipated to
the atmosphere and how much cooling water is needed. Part of this information
is presented on Table A5-9. Most of the entries come directly from preceding
tables. The electricity used is 31,000 kw. The unaccounted losses in the
gasifier train have been assumed 50 percent lost to the atmosphere and 50
percent lost to cooling water. The first group of losses has been called
"direct losses" because the loss is directly to the atmosphere and water
cannot be used.
88
-------
9
In the list of driving energy requirements, 0.3 x 10 Btu/hr was added
for water treatment and other uses. A lot of this energy is used in ammonia
recovery stills which are likely to need wet cooling to a low temperature.
All of this energy is assumed lost to cooling water. The steam turbines
driving the electric generator, the lock hopper compressors, and the air and
oxygen compressors are taken to be condensing steam turbines with 70 percent
of the energy lost in the condensers. For gas compressors the other
30 percent of the energy is lost in interstage cooling because the energy
stored in a compressed gas is very small. Whether or not the turbine condensers
and interstage coolers will be wet cooled or combined wet and dry. will depend
on cost and will vary from site to site . The energy put into acid gas
removal is mostly lost in the regenerator condenser. It is quite feasible
for this to be a dry condenser , but the decision will vary with the site.
The ultimate disposition of unrecovered heat has been extended to the
desired sites on Table A5-10. Coal drying requirements have been calculated
for each site. In all other respects the plants follow the reference plants.
The plant thermal efficiencies vary, but this is reflected in variations in
direct losses and not in cooling requirements.
In evaluating solid residues account had to be taken of ash leaving the
plant in char. The quantities of char sold, or not fired to the boiler, and
of char fired are given on Table A5-10 in energy units. The ash in the
entering coal is distributed between sold and fired in the ratio of the char
energies. Of the ash in the char fired, 80 percent is fly ash and 20 percent
is bottom ash.
In estimating water for flue gas desulfurization the char composition of
the reference plants was assumed and the char weight fired was estimated from
the char energy fired.
REFERENCES, APPENDIX 5
1. Bureau of Mines, "Preliminary Economic Analysis of Synthane Plant
Producing 250 million SCFD High-Btu Gas from Two Coal Seams: Wyodak
and Pittsburgh," EPJ3A-76-59, March 1976 (available from NTIS) .
2. Strakey, J.P-, Jr., Forney, A.J., and Haynes, W.P., "Effluent
Treatment and its Cost for the Coal-to-SNG Process," presented at
American Chemical Society 168th National Meeting, Atlantic City,
89
-------
N.J., September 1974, Div. of Fuel Chemistry reprint Vol. 19,
No. 5, p. 94.
3. Water Purification Associates, "Water Conservation and Pollution Control
in Coal Conversion Processes," Report EPA 600/7-77-065, U.S. Environ-
mental Protection Agency, June 1977.
90
-------
COAL
ISO"?
WAItป
Figure A5-1. Flow diagram for Synthane processes.
-------
TABLE A5-1. ANALYSES OF VARIOUS COALS DRIED TO 4.3% MOISTURE*
FOR FEED TO SYNTHANE PROCESS
Moisture
C
H
0
N
S
Ash
Type
Calculated
HHV
is ir
v " ง
4.3 2.5
64.5 73.8
4.1 5.2
16.8 8.0
1.0 1.5
0.8 1.6
8.5 7.4
Sub-
bit.
10,600 13,400
Jeffers
2
71
4
3
1
0
16
12,
0
.3
.0
.4
.8
.5
.9
.1
800
c
0
m
31
0 M
4,
72
4.
8,
1
2.
6,
.3
.5
.9
.1
.2
.2
.8
Bituminous
13,000
-H
<-*
3 C
tfl M
4.3
70.7
5.0
7.9
1.5
2.4
8.2
12 , 800
a
Si
3.4
79.8
5.2
6.5
1.6
0.6
2.9
14,300
I
3. o,
2.3
73.6
4.9
5.3
1.4
2.8
fs
S a
1.9
75.1
4.9
6.7
1.4
0.7
9.7 9.3
13,400 13,400
4J 0}
0. X
2.5
74.6
4.7
3.3
1.5
2.7
10.7
13,600
O
!
V '
*J o
5. 1"
4.3
68.2
4.7
15.6
0.8
0.6
5.8
11,600
f f,
5^
9 "
O, 4J
CO (/>
4.3
62.2
4.7
16.3
0.9
1.2
10.4
S ubb i tumi nous
10,700
Q.
i .
0) JJ
^ C
5 ฃ
4.3
66.4
4.4
14.7
1.0
0.5
8.7
11,200
Coals with less than 4.3ป moisture listed "as-received."
92
-------
TABLE A5-2. FLOW AND ENERGY RATES FOR
REFERENCE SYNTHANE PLANTS
Coal feed0
Oxygen feedฎ
Steam feedฎ
product gas U~3)
Char
PITTSBURGH
1187 x 10 Ib/hr
15.91 x 10 Btu/hr
304 x 10 Ib/hr
1170 x 103 Ib/hr
9.79 x 10 Btu/hr
362 x 10 Ib/hr
3.55 x 10 Btu/hr
0.6 x 10 Btu/hr
1605 x 10 Ib/hr
17.08 x 10 btu/hr
482 x 10 Ib/hr
978 * 10 Ib/hr
9.79 x 10 Btu/hr
410 x 10 Ib/hr
4.02 x 10 Btu/hr
0.8 x 10 Btu/hr
PITTSBURGH
Gas Streams
(103 moles/hr)
Gaaifier off-gasฎ
Dirty Condensate (5)
Char quench (6J
Steam for Shiftฎ
After Shiftฎ
Condenaate after
Shiftฎ
Condensate after ^
Acid Gas Removal (10'
Me thanation
Water (12)
CO
19.66 11.34 16.63 18.91 40.08 0.54
33.23
3.76
3.68
23.77 7.22 16.63 23.02 6.42 0.54
5.02
1.4
7.22
CO, CO CH H H O C H
2 42226
25.89 16.70 15.24 16.03 36.43 1.12
28.68
4.27
10.51
34.77 7.82 15.24 24.91 9.38 1.12
7.68
1.7
7.82
93
-------
TABLE A5-3.
WATER EQUIVALENT HYDROGEN BALANCES
FOR SYNTHANE REFERENCE PLANTS
IN
Moisture in coal
Water equiv. to hydrogen in coal
Steam to gasifier and shift converter
TOTAL
10 Ib/hr
PITTSBURGH
30
556
1236
1890
WYOMING
69
592
1167
1828
OUT
Condensate after scrubbing
Condensate after shift reactor
Condensate after acid gas removal
Methanation water
Water equiv. to hydrogen in byproducts
Water equiv. to hydrogen in product gas
TOTAL
Error
598
90
25
130
87
920
1850
2.1%
516
138
31
141
87
920
1833
0.3%
94
-------
TABLE A5-4. WATER EQUIVALENT HYDROGEN BALANCES
AND FEED COAL RATES FOR SYNTHANE PLANTS
Units: 103 Lb/hr
a o e o c
MCt4bCC>C~ (0 t-t H .C O
_ U)4-**WOin-HซH-^>, r-fO^OW ซJ > Ifl >
4->O OO|-^C'*-IS3J3T3'HT3 O''~'-HIW-H C' C QJ
. .
4-> O QO-HCl*-(S3J3
S>> Q, > 0 O OJ ซ-H -H
4 LOS uz h>*co
As-received coal 1472 1596 1525 1243 1224 1243 1113 1315 1215 1167 1187 1170
to drying
Dried coal to 1409 1527 1459 1214 1171 1190 1075 1258 1186 1160 1164 1141
gasifier
HYDROGEN BALANCE
Moisture in 63 69 66 29 53 53 38 57 29 27 23 29
coal
Water equiv. to 623 675 604 492 540 559 521 568 536 523 523 495
hydrogen in coal
Steam to gasifier 1177 1162 1168 1215 1237 1234 1247 1228 1229 1231 1232 1229
and shift converter
1863 1906 1838 1736 1830 1846 1806 1853 1794 1781 1778 1753
Condensate after 526 511 518 578 599 595 609 590 591 593 594 591
scrub
Condensate after 138 138 138 90 90 90 90 90 90 90 90 90
shift reactor
Condensate after 31 31 31 25 25 25 25 25 25 25 25 25
acid gas removal
Methanation 141 141 141 130 130 130 130 130 130 130 130 130
water
Water equiv. to 87 87 87 87 87 67 87 87 87 87 87 87
hydrogen in byproducts
Water equiv. to 920 920 920 920 920 920 920 920 920 920 920 920
hydrogen in product gas
1843 1828 1835 1830 1851 1847 1861 1842 1843 1845 1846 1843
Error 1.1% 4.14 0.2* 5.4% 1.1% 0 3.04 0.64 2.7% 3.6% 3.8% 5.1%
95
-------
TABLE A5-5. SYNTHANE GASIFIER HEAT BALANCES
FOR REFERENCE LOCATIONS
10 Btu/hr
IN
OUT
PITTSBURGH
WYOMING
Coal
15.91
17.08
Steam
1.34
1.12
17.25
18.20
Gas
12.46
12.14
Steam raised in jacket
0.38
0.61
Char heating value
3.67
4.16
Char sensible energy
0.08
0.09
Tar heating value
0.60
0.80
Unaccounted losses
0.06
0.40
17.25
18.20
96
-------
TABLE A5-6.
HEAT .BALANCE AROUND THE SYNTHANE
GASIFIER TRAIN FOR REFERENCE PLANTS
IN
Coal
Steam
OUT
Product gas
Char
Tar
Losses around gasifier
Combustibles lost in gas purification
Sensible heat of condensate
Steam produced in waste heat
recovery (stream (ง) ) and methanation
Dry cooling of process streams
Wet cooling of process streams
Unaccounted losses
10 Btu/hr
PITTSBURGH
15
1
17
9
3
0
0
0
0
1
1
0
0
.91
.51
.42
.79
.67
.60
.06
.10
.15
.40
.38
.07
.20
WYOMING
17.
1.
18.
9.
4.
0.
0.
0.
0.
1.
1.
0.
0.
08
43
51
79
16
80
40
10
14
61
33
07
11
17.42
18.51
97
-------
TABLE A5-7- DRIVING ENERGY FOR REFERENCE
SYNTHANE PLANTS
10 Btu/hr
PITTSBURGH
WYOMING
Coal drying
0.42
Lock hoppercompressors
0.08
0.08
Gas purification
0.69
1.01
Process steam
1.51
1.43
Oxygen production
0.66
1.05
Electrical production (31,000 kw)
0.36
0.36.
For water treatment and other uses
0.30
0.30
Driving energy required
3.60
4.65
Less steam raised in process
(1.40)
(1.61)
Net heat required from fuel
2.20
3.04
CHAR FIRED BOILER
Heat yield
2.20
3.04
Stack loss
0.30
0.41
Hot bottom ash
0.02
0.02
98
2.52
3.47
-------
TABLE A5-8. OVERALL PLANT HEAT BALANCES FOR REFERENCE
SYNTHANE PLANTS
IN
OUT
10 Btu/hr
PITTSBURGH
WYOMING
Coal
15.91
17.08
Product gas
9.79
Char not burnt in boiler
1.15
0.69
Tar
0.60
0.80
Unrecovered heat
4.37
5.80
15.91
17.08
Plant thermal efficiency
72.5%
66.0%
99
-------
TABLE A5-9. ULTIMATE DISPOSITION OF UNKECOVERED HEAT
IN REFERENCE SYNTHANE PLANTS
109 Btu/hr
PITTSBURGH WYOMING
Coal drying ฐ ฐ'42
Heat lost in hot condensate 0.15 0.14
Losses around gasifier 0.06 0.40
Electricity used 0.11 0.11
Char boiler stack losses 0.30 0.41
Combustibles lost in gas purification 0.10 0.10
50% of gasifier train unaccounted losses 0.10 0.05
Subtotal direct losses 0.82 1.63
Air cooling of plant process streams 1.38 1.33
Wet cooling of plant process streams + 50%
of gasifier train unaccounted losses + other 0.47 0.43
uses of driving energy
Bottom ash quench from char boiler 0.02 0.02
Total turbine condenser losses 0.77 1.04
Total compressor interstage cooling 0.22 0.34
Acid gas removal regenerator condenser 0.69 1.01
4.37 5.80
100
-------
TABLE A5-10. DRIVING ENERGY, THERMAL EFFICIENCY AND ULTIMATE DISPOSITION
OF UNRECOVERED HEAT FOR SYNTHANE PLANTS
Units: 10 Btu/hr
Coal drying
Other driving energy from Table A5-7
Total driving energy
Net heat required from fuel
Char fired to boiler
Char not fired in boiler
Unrecoverad heat
Plant thermal efficiency
0 0.07 0.11 0 0.04 0000
3.60 3.60 3.60 3.60 3.60 3.60 3.60 3.60 3.60
3.60 3.67 3.71 3.60 3.64 3.60 3.60 3.60 3.60
2.20 2.27 2.31 2.20 2.24 2.20 2.20 2.20 2.20
2.52 2.59 2.64 2.52 2.56 2.52 2.52 2.52 2.52
1.15 l.OS 1.03 1.15 1.11 1.15 1.15 1.15 1.15
4.37 4.44 4.49 4.37 4.41 4.37 4.37 4.37 4.37
72.5ป 72.14 71.8* 72.5% 72.3* 72.5% 72.54 72.54 72.51
Direct losses
Air cooling of plant process streams {Table A5-9)
Wet cooling (Table A5-9)
Bottom a^h quench from boiler (Table A5-9)
Turbine condenser loss (Table A5-9)
Compressor interstage (Table A5-9)
Acid gas system (Table A5-9)
0.82 0.89 0.94 0.82 0.86 0.82 0.82 0.82 0.82
1.38 1.38 1.3U 1.38 1.3H 1. 3U 1.38 1.38 1.38
0.47 '0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47
0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02
0.77 0.77 0.77 0.77 0.77 0.77 0.77 0.77 0.77
0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22 0.22
0.69 0.69 0.69 0.69 0.69 0.69 0.69 0.69 0.69
4.37 4.44 4.49 4.37 4.41 4.37 4.37 4.37 4.37
o o
i >i
i I
c >.
< X
u
Coal drying
Other driving energy from Table A5-7
Total driving energy
Net heat required from fuel
Char fired to boiler
Char not fired in boiler
Unrecovered heat
Plant thermal efficiency
0.54 0.63 0.51
4.23 4.23 4.23
4.77 4.86 4.74
3.16 3.25 3.13
3.61 3.71 3.57
0.55 0.45 0.59
5.94 6.04 5.90
65. ;<, 64.64 65.54
Direct losses
Air cooling of plant process streams (Table A5-9)
Wet cooling (Table A5-9)
Bo t torn ash quench from boiler (Table A5-9)
Turbine condenser loys (Table A5-9)
Compressor interstage (Table A5-9)
Acid gas system (Table A5-9)
1.77 1.87 1.73
1.33 1.33 1.33
0.43 0.43 0.43
0.02 0.02 0.02
].04 1.04 1.04
0. 34 0.34 1.04
1.01 1.01 1.01
5.94 6.04 5.90
101
-------
TABLE A5-11. CHAR COMPOSITIONS IN REFERENCE
SYNTHANE PLANTS
PITTSBURGH
WYOMING
C
71.4%
63.6%
0.9
1.0
0.5
1.4
1.1
0.4
1.5
0.3
Ash
23.9
33.3
100
100
HHV (calc'd.)
10/900 Btu/lb.
9,700 Btu/lb.
102
-------
APPENDIX 6
CALCULATIONS ON THE LURGI PROCESS
BASIS OF ANALYSIS
Calculations for the Lurgi process are required for bituminous coals at:
1. Bureau, Illinois
2, St. Clair, Illinois
3. Fulton, Illinois
4. Muhlenberg, Kentucky
5, Kemmerer, Wyoming
for subbituminous coals at:
6. El Paso, New Mexico
7. Gallup, New Mexico
8. Jim Bridger Mine, Wyoming
9. Decker. Montana
10. Foster Creek Montana
11. Wesco, New Mexico
and for lignites at:
12. Knife River, North Dakota
13. Williston, North Dakota
14. Marengo, Alabama
For bituminous coals, process water streams have been calculated using
the rules given below which were taken from Fluor Engineers and Constructors ,
A detailed analysis of a Lurgi SNG plant using Navajo subbituminous coal has
been presented by El Paso . From this reference we have abstracted a set of
rules, also shown below, and used them for subbituminous coals. These rules
2 3
give the reported water streams for El Paso ' within 4 percent. When these
rules are applied to Wesco, the calculated steam feed and dirty condensate
are lower than the reported values by 22-30 percent. The water consumed
103
-------
is the same, but more steam goes into the gasifier and is recovered unchanged
than is calculated. The process water streams for El Paso and Wesco are
those reported in References 2 to 6; they were calculated by us. The use of
El Paso instead of Wesco as a model makes no difference to net water consump-
tion but yields lower inlet and outlet streams with less cost for water
treatment.
Judging from Reference 7, a lignite feed requires more steam to the
gasifier than does a subbituminous feed. Lignite rules are also given below.
Bituminous Coals
1. Steam fed to the gasifier equals 2.58 Ib per Ib of dry, ash-free
coal.
2. Of the steam fed to the gasifier, 72.3 percent passes through
unchanged. This unchanged steam plus all the moisture in the feed coal
appears as moisture in the gasifier off-gas.
3. Fourteen percent of the carbon in the coal is converted to methane
and 1.05 percent is converted to C H plus C H , which is taken here to be
24 26
entirely C H .
2 6
4. Solid and oil products are assumed to contain zero oxygen. Because
phenol is produced this is not strictly accurate, but it is a very good
approximation. All of the oxygen in total feed streams appears as HO, CO
and CO2- The H^ was calculated in Step 2. The molar ratio of CO:CO in
the off-gas is 0.49, so the weight ratio of oxygen in CO to oxygen in CO is
0.245. With this information the oxygen balance can be closed and the weights
of CO and CO determined.
5. The balance of the carbon appears in the oil and solid residue.
6. All of the sulfur in the coal is converted to H S. All of the
ammonia in the coal is converted to NH .
7. The molar ratio H^CO in the off-gas is 2.79. The weight ratio is
therefore 0.20. This gives the H in the off-gas.
8. Any remaining hydrogen appears in the oil and solid product.
This completes the gasifier rules. To calculate the gas reactions, the
off-gas composition is first retabulated in moles.
9. Enough gas is passed through a shift reactor to produce a molar
ratio H2:CO of 3.05. If the moles of hydrogen and the moles of' CO in the
104
-------
off-gas are M and M , and if the amount of shift reaction is
H CO
xH O + xCO = xCO + xH
then
M + x
- = 3'05
co
4.05x = 3.05 MCQ - MH
All of the water remaining in the gas after shift reaction is recovered as
dirty condensate.
10. A perfect acid gas removal is temporarily assumed (this is adjusted
later). All of the CO is converted to methane by the reaction:
CO + 3H = CH + HO
The water obtained from this reaction, "methanation water", is clean enough
to recycle to the boiler feed.
11. The dried product gas is assumed to contain some CO and/or N and
5
to have a heating value of 950 Btu/scf (or 3.61 x 10 Btu/mole). The heating
value of the product gas for a standard size plant is:
950 Btu/scf x 250 x 106/24 scf/hr = 9.90 x 1Q9 Btu/hr
If, for the basis of the preceding calculations which is 1,000 Ib as-received
coal, the dried product gas is found to have a heating value of HHV Btu, then
the actual plant streams equal the streams calculated multiplied by:
9.90 x 109/HHV in Ib/hr
The heating value of the gas is calculated as:
123,000 x (moles H ) + 382,000 x (moles CH ) = 668,000 x (moles/C H ) in Btu
2 4 26
105
-------
Subbituminous Coals
1. The carbon in the coal is distributed 14 percent to CH , 1.4 percent
to C H^, 15 percent to ash residue, oil, phenol and other byproducts, 40.8
2 6
percent to CO and 28.7 percent to CO. The molar ratio CO:CO = 0.7.
2. Oxygen appears in the off-gas only as HO, CO and CO . Oxygen in
the residues is ignored. The ratio feed steam/feed oxygen is 4 Ib/lb
(7.1 moles/mole) and 45 percent of the feed steam decomposes. Let:
W be steam fed; it contains 0.889 W oxygen
Hzu H2O
W be the coal moisture; it contains 0.889 W oxygen
* C
W be the coal oxygen
0.25 W is the oxygen feed
Let:
wco be the off-gas CO; it contains 0.571 W oxygen
WC02 be the off-
-------
3. All the sulfur in the coal is converted to H S. All the nitrogen in
the coal is converted to NH . Effluents other than gas contain
0.0833 Ib hydrogen/lb carbon (1 mole/mole). The balance of the hydrogen
appears as molecular hydrogen in the off-gas.
4. The gas reaction rules and the scaling to size are as Rules 9, 10
and 11 for bituminous coals.
Lignites
For lignite the rules for subbituminous coals were used, with the excep-
tion of Step 2. The ratio of steam to oxygen in the feed for lignite was
taken to be 8.5 moles/mole (4.78 Ib/Lb). The equation for the steam feed
rate becomes:
= 0.571WCO+ 0.727 W^ - WQ
PROCESS WATER
The gasifier material balances are given on Table A6-1. The gas train
balances and scale factors are given on Table A6-2. Process water and other
streams are summarized on Table A6-3, on which is shown:
Coal to gasification = Scale factor x 10 Ib/hr
Steam to gasifier = Scale factor x steam on Table A6-1 Ib/hr
Dirty condensate = Moles HO after shift x 18 x scale factor Ib/hr
Methanation water = Moles HO after methanation x 18 x scale factor Ib/hr
COOLING WATER
Lurgi plants use rectisol gas purification and other proprietary sub-
systems for which information is not published, and the plant driving energy
and efficiencies have not been calculated. Instead the overall plant effi-
2 7
ciency is taken to be 67 percent for bituminous and subbituminous coals '
g
and 65 percent for lignites . The ca
with the results shown on Table A6-3.
g
and 65 percent for lignites . The calculations then proceeded as follows,
9
1. The product gas energy is 9.9 x 10 Btu/hr by design.
107
-------
2. Byproduct energy is :
(14,500 C + 62,000 H)(scale factor)
were C and H are Ib carbon and hydrogen in "other products" on Table A6-1.
3. The plant efficiency which is given above is equal to:
(product energy + byproduct energy)/(total coal energy)
From this is calculated the total coal energy.
4. Since the coal to gasifier is known, the coal to the boiler is the
extra coal to make the correct total.
Note that for El Paso and Wesco the coal streams and unrecovered heat are
calculated as for the other sites.
The load on wet cooling at each site has been assumed to be a fraction of
the unrecovered heat which, to facilitate comparison, has been taken to be the
same as for Synthane plants on the same site or in the same area. The
fractions used are shown on worksheets in Appendix 10.
REFERENCES, APPENDIX 6
1. 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.
2. 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.
3. Milios, Paul, "Water Reuse at El Paso Company's Proposed Burnham I
Coal Gasification Plant," presented at AIChE 67th Annual Meeting,
Washington, D.C., Dec. 1-5, 1974.
4. Moe, J. M., "SNG from Coal via the LURGI Gasification Process,"
iGT Symposium on. Clean Fuels from Coal, Institute of Gas Technology,
Chicago, 111., Sept. 10-14, 1973.
5. Strasser, J. D., "General Facilities Offsite, and Utilites for Coal
Gasification Plants," IGT Symposium on Clean Fuels from Coal, Institute
of Gas Technology, Chicago, 111., Sept. 10-14, 1973.
108
-------
6. Berty, T. E., and Moe, J. M., "Environmental Aspects of the Wesco
Gasification Plant," Symposium Proceedings: Environmental Aspects
of Fuel Conversion Technology (May 1974, St. Louis, Mo.), U.S. Environ-
mental Protection Agency, EPA-650/2-74-118, 1974.
7. Batelie Columbus Laboratories, "Detailed Environmental Analysis
Concerning a Proposed Gasification Plant for Transwestern Coal Gasi-
fication Co., Pacific Coal Gasification Co., Western Gasification Co.,
and the Expansion of a Strip Mine Operation Near Burnham, New Mexico,
Owned and Operated by Utah International Inc.," Federal Power Commis-
sion, Feb. 1, 1973.
8. Michigan-Wisconsin Pipeline Co. and American Natural Gas Coal Gasifica-
tion Co., "Application for Certificates of Public Convenience and
Necessity before the Federal Power Commission," Docket CP75-27B.
109
-------
TABLE A6-1. LURGI GASIFIER MATERIAL BALANCE
Location: Bureau, 111inoi s
Coal: Bituminous
Location: St. Clair, Illinois
Coal: Bituminous
o
Basis: 1000 lb
All units: lb
Coal : MAF
Moisture
Ash
Steara
Oxygen
TOTAL IN
Gas: H2O
C"4
C2H6
NH3
V
CO
Cฐ2
H2
Other
TOTAL OUT
As Received coal
Total C H O N
765 601 41 83 11
161 17.8 143.2
74
1974 219 1755
414 414
3388 601 278 2395 11
1588 176 1412
112 84 28
8 6.4 1.3
13 2.4 11
31 1.8
338 145 193
1086 296 790
68 67.6
144 69.6 0.9 0
3388 601 278 2395 11
E Ash
29
74
29 74
29
74
29 74
Basis: 1000 lb As
All units: lb
Coal: MAF
Moisture
Ash
Steam
Oxygen
TOTAL IN
Gasi H^O
CH
4
C0H,
2 6
NH
3
H.S
2
CO
co_
2
H2
Other
TOTAL OUT
Received coal
Total C H O
776 611 42 74
113 13 100
111
2002 222 1780
420 420
3422 611 277 2374
1560 173 1387
114 86 28
8 6.4 1.6
15 2.6
39 2
340 146 194
1090 297 793
68 68
186 76 0.8 0
3422 611 277 2374
N S Ash
12 37
111
12 37 111
12
37
111
12 37 111
(continued)
-------
TABLE A6-1. Continued
Locat_io_n^ Fulton , Illinois
oal; Bltumijio
Basis : 1000 Lb A3
All units : Ib
Coal : MAT
Moisture
Ash
Steam
Oxygen
TOTAL IN
Gas; HO
2
CH
4
C H
2 6
NH
3
H S
2
CO
CO'
2
H
2
Otlier
TOTAL OUT
Received coal
Total C H O
744 588 41 73
156 17 139
100
1920 213 1707
403 403
3323 588 271 2322
1544 172 1372
109 82 27
8 6 1.5
13 2
33 2
327 140 187
1049 286 763
65 65
175 74 1.5 0
3323 583 271 2322
N S Ash
11 31
100
11 31 100
11
31
100
11 31 100
Location; Muhlenberg, Kentucky
Coal; B i t umino us
Basis- 1000 Ib A
All rniits: Ib
Coal : RAF
Moisture
Ash
Steam
Oxygen
TOTAL IN
Gas : HO
CH4
C2H6
V
CO
TO2
H2
Other
TOTAL OUT
Total C H O N
818 648 47 83 14
110 12 98
72
2110 234 1876
443 443
3553 648 293 2500 14
1636 182 1454
121 91 30
972
17 3 14
28 2
360 154 206
1155 315 840
72 72
155 81 2 0
3553 648 293 2500 14
S Ash
26
72
26 72
26
72
26 72
(continued)
-------
TABLE A6-J, , Continued
Lo-c a c i on ^ tCenine r er , Wyoming
Coal: Bitumino
Bas i S : 1000 Lb
All uni ts : Ib
Coal : HAP
Moisture
Ash
Steam
Oxygen
TOTAL IN
Gas H^O
CH
4
C,H,
2 6
NH
3
H2S
CO
co2
H
2
Other
TOTAL OUT
fl-3 Received coal
Total C H 0
880 718 50 90
28 3 25
92
2270 252 2018
476 476
3746 718 305 2609
1669 185 1484
135 101 34
10 7.5 2
15 3
11 0.6
387 166 221
1243 339 904
77 77
199 104 3 0
3746 718 305 2609
N S Ash
12 10
92
12 10 92
12
10
92
12 10 92
Location; Gallup, New Mexico
Coal: Subbituminous
Basis i 1000 Ib
All units: Ib
Coal : MAF
Moisture
Ash
Steam
Oxygen
TOTAL IN
Gas : H.O
2
CH
4
C2H6
NH
3
H2S
CO
Cฐ2
H2
Other
TOTAL OUT
As Received coal
Total C H O
798 632 47 104
151 17 134
51
1269 141 1128
317 317
2586 632 205 1683
848 94 754
119 89 30
11 9 2
13 2
4 0
422 181 241
946 253 688
69 69
154 95 8
2586 632 205 1683
N S Ash
11 4
51
11 4 51
11
4
51
11 4 51
(continued)
-------
TABLE A6-1. Continued
Basis: 1000 Ib
All units: Ib
Coal: KAF
Moisture
Ash
Steam
Oxygen
TOTAL IN
Gas : HO
CH4
C2H6
V
CO
co2
Other
TOTAL OUT
As Received coal
Total C H O
706 519 32 139
212 24 188
82
961 107 854
240 240
2201 519 163 1421
739 82 657
97 73 24
972
13 2
5 0
348 149 199
777 212 565
47 47
166 78 6 0
2201 519 163 1421
N S Ash
11 5
82
11 5 82
11
5
82
11 5 82
Location: Decker, Montana
Coal: Suhbituminous
Basis: 1000 Ib
All units: Ib
Coal: MAP
Moisture
Ash
Steam
Oxygen
TOTAL IN
Gas: H2O
CH4
C2H6
V
CO
CO.,
H2
Other
TOTAL OUT
As Received coal
Total C H O
724 572 32 109
239 27 212
37
1128 125 1003
282 - 282
2410 572 184 1606
858 95 763
107 80 27
10 8 2
7 1
5 0
383 164 219
858 234 624
52 52
130 86 7
2410 572 184 1606
N S Ash
6 5
37
6 5 37
6
5
37
6 5 37
(continued)
-------
TABLE A6-1. Continued
Locationi Foster Creek, Montana
Coal; Subbituminoua
Basis: 1000 Ib A3
All units: Ib
Coal: HAF
Moisture
Ash
Steam
Oxygen
TOTAL IN
Gas: HO
C2H6
NH3
V
CO
co2
H3
Other
TOTAL OUT
Received Coal
Total C H 0
616 457 29 118
307 34 273
77
853 95 758
213 213
2066 457 158 1362
775 86 689
85 64 21
862
9 2
5 0
306 131 175
685 187 498
41 41
152 69 6
2066 457 158 1362
N S Ash
7 5
77
7 5 77
7
5
77
7 5 77
Basis: 1000 Lb A3
All units: Ib
Coal i MAF
Moisture
Ash
Steam
Oxygen
TOTAL IN
Gas: H O
2
CH
4
C H
2 6
NH
3
H S
2
CO
co2
H
2
Other
TOTAL OUT
Received Coal
Total C H 0
589 425 28 123
350 39 311
61
861 96 765
215 215
2076 425 163 1414
885 98 787
80 60 20
761
7 1
7 0
285 122 163
638 174 464
38 38
129 63 5
2076 425 163 1414
N S Ash
6 7
61
6 7 61
6
7
61
6 7 61
(continued)
-------
TABLE A6-1. Continued
Location: Williston, North Dakota
Basis : 1000 Ib As Received Coal
Coal; Lignite
A_ll units: Ib
Coal; HAF
Moisture
Ash
Steam
Oxygen
TOTAL IN
Gas; HO
NH3
V
CO
"2
H2
Other
Total C
544 391
400
56
79J
198
1991 391
894
73 55
6 5
9
6
262 112
586 160
35
120 59
H O N S Ash
28 112 7 6
44 356
56
88 705
198
160 1371 7 6 56
99 795
18
1
2 7
0 6
150
426
35
5 56
TOTAL OUT
1991
160 1371
Location: Harenqo, Alabama
Coal: Lignite
Basis : 1000 Ib As
All units, Ib
Coal i HAF
Moisture
Ash
Steam
Oxygen
TOTAL IN
Gas j HO
CH
4
C H,.
2 6
NH
3
H S
2
CO
CO
2
H
2
Other
Received coal
Total C H O H S Ash
465 321 22 98 6 18
487 54 433
48 48
639 71 568
160 160
1799 321 147 1259 6 18 48
885 98 787
60 45 15
541
7 16
19 1 18
215 92 123
480 131 349
27 27
101 49 4 48
TOTAL OUT
1799
147
-------
TABLE A6-2. LURGI GAS TRAIN BALANCE
Loca tion: Bureau, 111inois
Coal: Bituminous
Basis : 1000 Ib As
All Units : Moles
CH4
CO
co2
H2
Product HHV, 7. 26
Scale Factor 9.9
Received Coal
Gasi f ier
Off-Gas
aa. 22
7
0.27
12.07
24.68
34
After
Shift
87.53
7
0.27
11.38
25.37
34.69
After
Clean-up
0
7
0.27
11.38
0
34.64
After
Methanation
11.38
18.38
0.27
0
0
0.50
x 106 Btu
x 109/HHV - 1364 hr"1
Location: St. Clair, Illinois
Basis: 1000 Lb A3
All Units : Moles
CH4
C2H6
CO
Cฐ2
H
Received Coal
Gasifier
Off-Gas
86.67
7.13
0.27
12.14
24.77
34
Coal :
After
Shift
85.92
7.13
0.27
11.39
25.52
34.75
Bituminous
After
Clean-up
0
7.13
0.27
11.39
0
34.75
After
Me thana tion
11.39
18.52
0.27
0
0
0.58
Location: Fulton, 111inoia
Coal: Bituminous
Basis: 1000 Ib A3 Received Coal
All Units: Moles
H20
CH4
C2H6
CO
co2
Product HHV, 7.02 x
Scale Factor " 9.9
Gasifier
Off-Gas
85.78
6.81
0.27
11.68
23.84
32.5
After After
Shift Clean-up
85.01 0
6.81 6.81
0.27 0.27
10.91 10.91
24.61 0
33.27 33.27
After
Methanation
10.91
17.72
0.27
0
0
0.54
106 Btu
x 109/HHV - 1410 hr"1
Location: Muhleruperg, Kentucky
Basis: 1000 Ib As
All units: Moles
H2ฐ
CH4
C2H6
CO
W2
H2
Received Coal
Gasifier
Off-Gas
90.89
7.56
0.30
12.86
26.25
36
Coal: Bituminous
After After
Shift Clean-up
90.09 0
7.56 7.56
0.30 0.30
12.09 12.09
25.45 0
36.80 36.80
After
Methanation
13.66
21.22
0.30
0
0
0.53
Product HHV, 7.33 x 10 Btu
Scale Factor - 9.9 x 109/HHV - 1351 hr
-1
Product HHV, 8.37 x 10 Btu
9 -1
Scale Factor - 9.9 x lo /HHV - 1183 hr
(continued)
-------
TABLE A6-2. LURGI GAS TRAIN BALANCE
Basis: 1000 Ib As
All Units: Moles
H2ฐ
CH4
C2H6
CO
co2
"2
Product HHV, 8.46 x
Scale Factor ซ 9.9
Loca t ion : Gallup,
Basis : 1000 Ib As
All Units: Holes
CH4
C2H6
CO
co2
H2
Product HHV, 7.84 x
Received Coal
Gas i f ier
Off-Gas
92.72
8.44
0.33
13.82
28.25
38.5
After
Shift
91.82
8.44
0.33
12.92
29.15
39.40
After After
Clean-up Methanation
0 12.92
8.44 21.36
0.33 0.33
12.92 0
0 0
39.40 0.64
6
10 Btu
x 109/HHV - 1170 hr"1
New Mexico
Received Coal
Gasif ier
Off-Gas
47.11
7.44
0.37
15.07
21. 5
34. 5
106 Btu
Coal:
After
Shift
44. 28
7.44
0.37
12. 24
24.33
37.33
Subbi t um i nous
After After
Cleaji-up Methanation
0 12.24
7.44 19.68
0.37 0.37
12.24 0
0 0
37.33 0.61
Scale Factor = 9.9 " 10 /HHV - 1263 hr
Location: Jim Bridger Mine, Wyoming
Coal: Subbituminous
Basis i 1000 Ib As
All Units: Moles
H2ฐ
CH4
C2H6
CO
co2
H2
Product HHV, 5.96
Scale factor 9.9
Location: Decker,
Basis: 1000 Ib As
All Units: Moles
H20
CH4
C2H6
CO
Cฐ2
H2
Received Coal
Gasifiar
Off-Gas
41.06
6.06
0.30
12.43
17.66
23.5
After
Shift
37.50
6.06
0.30
8.87
21.22
27.06
After
Clean-up
0
6.06
0.30
8.87
0
27.06
After
Methanation
8.87
14.93
0.30
0
0
0.45
x 106 Btu
x 109/KHV . 1661 hr"1
Montana
Received Coal
Gasif ier
Off-Gas
47.67
6.69
0.33
13.68
19.5
26
Coal:
After
Shift
43.79
6.69
0.33
9.80
23.38
29.88
Subbituminous
After
Clean-up
0
6.69
0.33
9.80
0
29.88
After
Methanation
9.80
16.49
0.33
0
0
0.48
6
Product HHV, 6.53 ซ 10 Btu
Scale Factor - 9.9 * 109/HHV - 1505 hr"1
(continued)
-------
TABLE A6-2. Continued
00
Location: Foster
Basis: 1000 Ib As
All Units: Holes
CH4
C2H6
CO
co2
H2
Received Coal
Gasifier After
Off-Gas Shift
43.05 39.88
5.31 5.31
0.27 0.27
10.93 7.76
15.57 18.74
20.5 23.67
: Subbi tuminous
After After
Clean-up Hethanation
0
5.31
0.27
7.76
0
23.67
7.76
13.07
0.27
0
0
0.39
Product HHV, 5.22 x 10 Btu
Scale Factor = 9.9 x 109/HHV = 1897 hr"1
Location: Knife River, North Dakota
Basis: 1000 Ib As
All Units: Holes
CH4
C2H6
CO
Cฐ2
H2
Product HHV, 4.86 ป
Scale Factor - 9.9
Received Coal
Gasifier After
Off-Gas Shift
49.17 46.19
5.00 5.00
0.23 0.23
10.18 7.20
14.5 17.48
19 21.98
: 106 Btu
x 109/HHV - 2037 hr"1
Coal:
After
Clean-up
0
5.00
0.23
7.20
0
21.98
Lignite
After
Hethanation
7.20
12.20
0.23
0
0
0.38
Location; Williston, North Dakota
Coa1; Lignite
Basis: 1000 Ib As
All Units: Holes
CH4
C2H6
CO
co2
H2
Product HHV, 4.41
Scale Factor ซ 9.9
Location ; Marengo
Basis: 1000 Ib As
All Units: Moles
H20
C2H6
CO
co2
H
Received Coal
Gasifier
Off-Gas
49.67
4.56
0.20
9.36
13.32
17.5
After
Shift
46.94
4.56
0.20
6.63
16.05
20.23
After
Clean-up
0
4.56
0.20
6.63
0
20.23
After
Hethanation
6.63
11.19
0.20
0
0
0.34
x 106 Btu
x 109/HHV - 2245 hr"1
, Alabama
Received Coal
Gasifier
Off-Gas
49.17
3.75
0.17
7.68
10.90
13.5
Coal;
After
shift
46.72
3.75
0.17
5.23
13.35
15.95
Lignite
After
Clean-up
0
3.75
0.17
5.23
0
15.95
After
Hethanation
5.23
B.98
0.17
0
0
0.26
Product HHV, 3.58 x 10 Btu
Scale Factor - 9.9 x lo /HHV - 2765 hr"1
-------
TABLE A6-3. PROCESS WATER AND OTHER STREAMS IN 250 x 10 SCF/DAY LURGI PLANTS
Units: 10 lb/hr
Coal to gasification
Coal to boiler
Steam to gasif ier
Dirty condensate
Kettianation water
9
Units: 10 Btu/hr
Product gas
Byproducts
Efficiency, %
Coal to gasifier
Coal to boiler
Unrecovered heat
Bureau ,
Illinois
1364
204
2693
2149
279
9.9
1.5
67
16 9
14.7
2.2
5.6
St. Clair,
Illinois
1351
199
2705
2089
277
9.9
1.6
67
17 1
L i . L
14.9
2.2
5.6
Fulton,
Illinois
1410
207
2707
2158
277
9.9
1.6
67
17.2
15.0
2.2
5.8
Muhlenberg ,
Kentucky
1183
269
2496
1918
291
9.9
1.5
67
17 . 1
13.9
3.2
5.6
Kenunerer ,
Wyoming
1170
220
2656
1934
272
9.9
2.0
67
17.7
14.9
2.3
5.9
El Paso,
New Mexico
1672
463
1640
1080
270
9.9
2.4
67
18 . 4
14.4
4.0
6.1
Gallup,
New Mexico
1263
355
1603
1007
278
9.9
2.4
67
13 . 3
14.3
4.0
6.0
Jijn Bridger
Wyoming
1661
519
1596
1121
265
9.9
2.5
67
18 . 5
14.1
4.4
6.1
Decker,
Montana
1505
448
1698
1186
265
9.9
2.5
67
1 A f.
lo . o
14.3
4.3
6.1
Foster Cree
Montana
1897
574
1618
1362
265
9.9
2.6
67
19 . ~)
14.3
4.3
6.2
Hesco,
New Mexico
1689
475
1990
1490
310
9.9
2.4
67
18 . 3
14.3
4.0
6.0
0) O
> x
72 Q
0 P.
50
Z
2037
589
1754
1694
264
9.9
2.1
65
18 . 4
14.3
4.1
6.5
Williston,
North Dakot
2245
678
1780
1897
268
9.9
2.6
65
19.3
14.8
4.5
6.7
Marengo,
Alabama
2765
345
1767
2325
260
9.9
2.7
65
19 . 3
14.8
4.5
6.8
-------
APPENDIX 7
COOLING WATER REQUIREMENTS
INTRODUCTION
Throughout this report the terms wet or evaporative cooling and dry or
air cooling have been used. Detailed discussion has been given in Refer-
ence 1. It is sufficient to say that a heat exchanger can be directly cooled
by a stream of air, or cooled by circulating water which is itself cooled by
evaporation and convection in a cooling tower.
In conformity with the discussion of Reference 1, all the cooling loads
in the plants have been assigned to the categories given on Table A7-1. As
has been shown , process streams are cooled to 140ฐF by dry cooling and below
this by wet cooling. The acid gas removal regenerator condenser can be
economically dry cooled at all plants when the hot potassium carbonate
process is used and 90 percent dry-10 percent wet cooled when a physical
solvent process is used . The gas purification system of choice has been
assigned to each process by the original designers. It is somewhat arbitrary
and has only a small effect on the cumulative water consumption.
The cooling of steam turbine condensers and of gas compressor interstage
coolers will depend on the cost of water and, therefore, on the site . On
Table A7-2 sites have been given a numerical classification for water cost
and availability. The numerical classification determines whether turbine
condensers are all wet cooled or whether parallel wet and dry condensers are
used, and whether gas compressor interstage coolers are all wet cooled or
whether series dry and wet coolers are used. The decision depends in part on
the economics of cooling, which is discussed below. The approximate economics
are shown graphically on Figures A7-1 to A7-5 for turbine condensers and
Figures A7-6 to A7-10 for interstage cooling.
120
-------
The numerical classification of sites is:
% Turbine Condenser % Gas Compressor
Water Cost & Cooling Load Interstage Cooling Load
Availability No.* Wet Cooled Wet Cooled
1 100 100
2 10 100
3 10 50
*No. 1 indicates plenty of water available within about 10 miles.
No. 2 indicates limited local supply or a plentiful supply 25 to 30
miles away. Number 3 indicates substantial pumping costs and the need
for a reservoir.
Also shown on Table A7-2 is the appropriate annual average evaporation
rate. This number is only very slightly dependent on site.
Calculations of cooling water evaporated have been made for each
site/process on the worksheets in a following appendix.
COOLING STEAM TURBINE CONDENSERS
On Figure A7-11 is shown a parallel dry/wet cooling system for a turbine
condenser. The following calculations are intended to determine what fraction
of the cooling load should be designed wet and what fraction should be
designed dry; also, the water consumption is to be determined. Dry cooling
has the advantage over wet cooling in that water is not used. It has the
disadvantage of a higher capital investment and a higher condenser tempera-
ture. The higher condenser temperature means a lower efficiency for the
turbine; that is, more energy as steam is consumed by the turbine for each
kw-hr of shaft work performed.
Before an economic analysis can be made, a physical analysis is necessary
To obtain the desired information the cooling system is first designed and
then its operation is analyzed, month by month, for a year. Finally the
economic analysis is made, and this depends on the cost of water.
121
-------
Turbine Characteristics
In a steam turbine drive system the steam rate required by the turbine
to produce a certain shaft power output depends on the inlet steam condition,
the condenser pressure and the turbine efficiency. Usually the higher the
inlet steam pressure and temperature, the higher will be the thermal efficiency
of the system. In the present application where the steam is partially
produced by waste heat recovery, the usual steam pressure is in the range of
715 to 915 psia, and the superheated temperature in the range of 600ฐF to
900ฐF. Also, in the present application where the steam turbine drive is
used mainly for gas compression purposes, the type of turbine drive used
usually has a maximum efficiency of about 80 percent when the condenser
pressure is in the range of 3 to 5 in. Hg absolute. The corresponding steam
saturation temperatures for the two condenser pressures are 115ฐF and 134ฐF
respectively. Above 134ฐF, efficiency falls. We have assumed that below
115ฐF, the efficiency also falls. This is a function of the exhaust losses and
may not be true for all turbines. However, usually there is no positive
advantage in cooling below 115ฐF, so the procedure adopted in this study, which
is never to cool below 115ฐF, is reasonably generally applicable when cooling
water is scarce.
The heat rates required when the condenser temperature is in the range
of 115ฐF to 134ฐF have been calculated for the various inlet steam conditions
mentioned and are plotted in Figure A7-12. The calculations were made using
an overall turbine efficiency of 80 percent including the bearing efficiency.
The results in Figure A7-12 show that the steam rates for .the four inlet
steam conditions are quite close and that they can be represented by a single
straight line going from a steam rate value of 11,700 Btu/kw-hr at the
condenser temperature of 115ฐF to a value of 12,200 Btu/kw-hr at the condenser
temperature of 134ฐF.
The increase in steam rate with condenser temperature indicates that
there is a certain fuel penalty to be considered in evaluating the cost of
various cooling systems.
The condenser cooling loads when the condenser temperature is in the
range of 115ฐF to 134ฐF have also been calculated for the four inlet steam
conditions mentioned and are plotted in Figure A7-13. The results indicate
that the condenser loads for the four inlet steam conditions are also quite
122
-------
close and that they can be represented by a single straight line, going from
a value of 8,200 Btu/kw-hr at the condenser temperature of 115ฐF to a value
of 8,700 Btu/lcw-hr at the condenser temperature of 134ฐF. This typical line
will be used for condenser load calculations when the economics of condenser
cooling systems are evaluated.
In analytical form the turbine heat rate is
QH (Btu/kw-hr) = 11,700 + 500
T - 115
= 8,674 + 26.32 T , for 115 < T < 134
C L.
(1)
and the condenser cooling load is
O (Btu/kw-hr) = 5,174 + 26.32 T , for 115 ฃ T <_134
I L^
(2)
The nomenclature is shown on Table A7-3.
Design Conditions
Design ambient conditions are given on Table A7-4 with complete monthly
average ambient conditions. The condenser design condition is a condensing
temperature of 134ฐF. This is a high design temperature chosen because the
design ambient conditions are, on the average, not exceeded more than ten
hours in a year. The design conditions for circulating cooling water are a
hot water temperature, t, , of 119ฐF which is a reasonable and usual 15ฐF
below the design condensing temperature, and cold water temperature, t , of
94ฐF. The cold water temperature means that the circulating pumps must be
sized for a 25ฐF rise which is usually found to be economical.
If x is the fraction of condenser load which is dry at design condition,
O ^ = 8,700x
"D, d
The dry condenser area, A is given by
O = U A (LMTD)
VD,d D D D
(4;
123
-------
where
LMTD =
(TC - TD,c) ' (TC - TD,h)
In
TC "
TC - TD,h
(5)
The temperature of the heated air leaving the dry condenser is found from the
empirical equation
T - T = 0.005 U (T - T )
D,h D,c D C D,c
(6)
from which
(TC - TD,c} - (TC - TD,h) = ฐ-ฐฐ5 UD(TC -
(7)
TC - TD,h = (TC - TD,c)(1 - ฐ-ฐฐ5 V
(8)
so,
LMTD =
D
0.005 UD(Tc - T J
In
T - T
C D, c
(T - T )(1-0.005 U )
C- D, c D
= 0.005
- 0.005
(9)
Values of UD are given on Table A7-5. Since the design condenser tempera-
ture
T = 134
C,d
(10)
124
-------
the design log mean temperature difference, IKTD , can be found from
D, d
Equation (9) and the area from Equations (3) and (4) .
DESIGN OF WET CONDENSER AND COOLING TOWER
To design the cooling tower, information on the efficiency of the
packing is needed. It must be remembered that our objective in designing a
tower is not to build a tower but to determine its operation at off-design
conditions. The choice of tower type and fill pattern is therefore not very
important. For this study we have used the comprehensive graphical data
given in Kelley ' s Handbook based on 18 ft of air travel and 30 ft height of
fill type H. The tower design parameter, which is given the symbol K Y/L
a
and is called "characteristic," is taken from Reference 2 for the condition
"Wet Bulb" = T
W,d
"Range" = t, - t = 25 ฐF
h c
(11)
"Approach" = t - T = 94 - T ^
c W,d W,d
T is the design air wet bulb temperature.
w, d
The equations which give the wet condenser area are
(12)
Qrl , = 8700(1 - x) = U A (LMTD)
W,d W W W,d
(13)
(LMTD)
(T - t ) - (T - t )
w,d
;i34
= 25.5
h
C h
(all design)
94) - (134 - 119)
134
94
119
(14)
-------
The equations which give the rate of circulation of cooling water are
R (Ib/kw-hr) = Qr7 ,/25 (15)
L W,a
R (gal/min)/kw) = R/(8.33)(60) = 0.002 R (16)
G -Li -*-*
Off-Design Conditions, General
Calculations were made using monthly average ambient conditions for each
month of a year beginning with the hottest and ending with the coldest. This
is more convenient than considering the months in chronological order. The
condenser temperature is first determined. If this is apparently below
115ฐF, then it is controlled at 115ฐF using the following control philosophy.
First, the heat rejection load of the cooling tower is reduced by altering
the pitch of the fans or by turning the fans off. When the ambient air
temperature is sufficiently low, the evaporative tower is shut down and the
heat load is carried by the dry cooler which controls the turbine back pressure
by altering the fan blade pitch. When the cooling tower is shut down, the
circulation of water is stopped. Water circulation is either full on or off.
Throttling the circulation pumps leads to stagnation, fouling and scaling and
is not practiced.
Determination of Condenser Temperature
Determination of the condenser temperature is a trial-and-error calculation
made as follows.
1) A condenser temperature, T , is assumed.
2) The total cooling load, Q, is calculated from Equation (2).
3) The dry log mean temperature difference is calculated from Equation
(5).
4) The dry cooling load is calculated from the equation
QD = VD(mTD)D (1?)
5) The wet cooling load is calculated from the equation
Qw = Q - QD (18)
6) The cooling water temperatures are calculated from the wet cooling
load. The "range" is given by the equation
126
-------
so,
(20)
The rate of heat transfer in the wet condenser is given by
uwVWTD)w
where
(LMTD) = (t -
W h
(22)
Algebraic manipulation of the above four equations gives
T *~ t
in
(23)
or
In
Tc-
Vw/Ri
(24)
so,
VRL
(25)
Equation (25) can be solved for t, and Equation (20) for t .
h c
7) Reference 2 is used to find whether, in fact, the cooling tower
will give the water temperatures found for the prevailing wet bulb temperature
T . Reference 2 gives the approach, t - T , when the wet bulb temperature,
w c w
T , the range, t, - t , and the tower characteristics are known. If t ,
w h c c
calculatec from the approach, is too high then the tower cannot do the job
and a higher condenser temperature must be tried.
127
-------
8) The fan and pump energy needs are calculated from the equations
Dry condenser fan energy E = 0.0149 A (26)
Cooling tower fan energy EW = 0.0089 RQ (27)
Cooling water circulation pump energy E = 0.0246 R (28)
These equations are used only when the condenser temperature is above 115 ฐF.
When the condenser temperature is controlled at 115ฐF, the equation given in
later steps should be used.
9) To calculate the water consumption, the rate of air flow through the
tower must be known. The ratio of water flow to air flow, R /R , is part of
the design of the tower (see Reference 2) and is known. Since the water
flow, R , is known, the air flow, R , is also known. Knowing the dry bulb
L A
and wet bulb temperatures the absolute humidity of the entering air, H. Ib
water/lb dry air, can be read from a standard psychometric chart. When the
dry and wet bulb temperatures are below 30ฐF, the absolute humidity of the
entering air is taken to be zero. It is also possible to calculate the
enthalpy of the entering air, i.. Enthalpies of humid air are normally
measured above 0ฐF for dry air and liquid water at 32 ฐF
iฑ = 0.24 TD + Hi[1075 + 0.45(TD - 32)] (29)
In Equation (29), 0.24 is the specific heat of dry air, 0.45 is the specific
heat of water vapor and 1075 is the latent heat of vaporization of water at
32ฐF.
Next, the condition of the air exiting the tower can be found. The
enthalpy of the exit air is
(30)
because the circulating water transfers the wet cooling load to the air.
Experience shows that the leaving air is within a few percentage points of
128
-------
saturation and it is sufficiently accurate to assume it to be saturated. In
Reference 2 is given a table of saturated air enthalpies against temperature
from which the temperature of the air leaving the tower can be read,. The
psychometric chart gives the humidity of the leaving air, H . The rate of
water evaporation is
R (H - H.) Ib/kw-hr (31)
A e i
Equation (31) applies when the tower is not bypassed. When the tower is
bypassed the modification given in Step 18 is used.
Operation with 115ฐF Condenser Temperature
When the condenser temperature is known, the calculation is as follows.
10) The total cooling load is 8,200 Btu/kw-hr.
11) The dry log mean temperature difference is given by the equation
LMTDQ = 0.005 UD(115 - TD c) / i-In(l - 0.005 U)(32)
12) The dry cooling load is given by Equation (17)
13) The wet cooling load is given by the equation
Qw = 8,200 - QD (33)
14) The hot temperature of the circulating cooling water, t , is given
by Equation (25) and the cold temperature, t , by Equation (20). The cold
temperature is the temperature of blended water entering the condenser, not
the temperature at the bottom of the cooling tower. The tower is bypassed.
15) The temperature at the bottom of the cooling tower, t , is found
from Reference 2. It is that temperature which makes both the range, t -
t , and approach, t - T , correct at the same time. When the wet bulb
temperature is very low such that it is no longer on the graphs, an arbitrary
37ฐF approach is chosen. This makes the tower bottom temperature 37ฐ higher
than the wet bulb temperature.
129
-------
16) The fraction of the flow which bypasses the tower, y, is given by
yR t + (1 - y)R t = Rt (34)
L h L r L c
y = tฐ _ tr (35)
If y ^ 1, we skip to Step 19.
17) The dry condenser fan energy is given by Equation (26) . The cooling
water circulation pump energy is given by Equation (28) . The cooling tower
fan energy is
E = 0.0089(1 - y)R,_ (36)
W G
18) The water evaporation is calculated as in Step 9, except that the
air rate is now (1 - y)R , where R is the design air rate.
19) If the ambient conditions are so cold that the cooling tower is
completely bypassed, the rate of water evaporated is zero, the cooling tower
fan energy is zero and the cooling water circulation pump energy is zero.
The only quantity to be calculated is the dry condenser fan energy. To do
this we first need to know the air temperature, T1, at which the dry condenser
will carry the whole load. This is given by
UD)|
8200 = UDAD x 0.005 U (115 - T')/ |-ln(l - 0.005 U^)| (37)
-8200 ln(l - 0.005 U )
115 - T- = ฐ_ (38)
0.005 U A
The fan factor, F, is read from the vertical scale of Figure A7-14 when the
horizontal scale point is (T^ - T ). The dry condenser fan energy is
E = 0.0149 FA (39)
130
-------
Results
The results of the month-by-month calculations are given for 0, 25, 50,
75 and 95 percent dry cooling at each of the four sites on Table A7-7 to A7-
10. Summaries are given on Table A7-11. To make the summaries, equal weight
was given to each month: for example, the fan and pump energies from Tables
A7-7 to A7-10 were totaled and divided by 12 to obtain the value entered on
Table A7-11. The fuel penalty is that part of the turbine heat rate in
excess of the minimum value, 11,700 Btu/kw-hr,
Costs
Unit costs are given on Table A7-6. The annual average costs, tabulated
on Table A7-12, were calculated according to the following examples:
2 2
Dry condenser cost (ฃ/kw-hr) = (area, ft AW) (cost, ฃ/ft ) (Vyr) (1/7000 hrs/yr)
Electrical energy (C/kw-hr) = (energy, kw-hr/kw-hr)(cost, ฃ/kw-hr)
Fuel penalty (C/kw-hr) = (fuel penalty, Btu/kw-hr)(steam, ฃ/Btu)
Please note that "total costs" (ฃ/kw-hr) refers only to those costs dependent
on the choice of cooling system. Other components of production cost are not
included.
Various water costs were assumed, and the results are shown graphically
in Figures A7-1 to A7-4 and summarized on Figure A7-5. It is clear that at
all sites there is a cost of water above which it is economical to use parallel
wet/dry condensers. It is also clear that when parallel wet/dry condensers
are used, the load on wet cooling is reduced to a small percentage of the load
with all wet cooling. Accurate generalization of actual numerical values is
not possible. Not only do the numerical values depend on the climate, as
shown on Figure A7-5, but they depend on the way the calculations were made
and, particularly, on the relative costs of wet and dry condenser surface
and the cost of cooling towers. Capital costs are always changing. The costs
used here are late 1977; wet condenser surface and cooling towers have had
recent cost increases, while dry condensers have not. This will change.
We have adopted the policy of using wet/dry cooling at many sites where
water is less than freely available, but not at all sites. If the cost of
131
-------
20C/1000 gallons shown on Figure A7-5 were totally and permanently trust-
worthy, parallel wet/dry condensers would be used everywhere, always. When
wet/dry cooling is used, we have dropped the load on wet cooling to 10 percent
of the case for all wet cooling. Figure A7-5 suggests a value as low as 2
percent, so our choice is conservative for the cost year and basis used.
Because of the way the calculations were made, the hot and cold circu-
lating water temperatures are both changed to control the system. Now, the
cooling system may have other connections such as to process coolers, and the
hot water returning to the tower may have a temperature derived from mixing
all the returning streams. However, there is no other way of making calcula-
tions. If the cooling tower is not reserved exclusively for turbine condensers,
then the calculations made are indicative but not a precise representation of
reality. Fortunately the chosen configuration, when not all wet, is 90
percent dry and only 10 percent wet. The wet condensers will only be turned
on for a few months of the year, and even then they will carry such a small
fraction of the load that control may not be required.
INTERSTAGE COOLING OF GAS COMPRESSORS
To study the effect of series dry-wet coolers on interstage gas com-
pressors, an air compressor has been chosen as the example. Air is com-
pressed from ambient temperature and 15 psia to 90 psia and 104ฐF (or cooler) ,
in which condition air enters the separation plant to be separated into
nitrogen and oxygen. Air compressors are used in all plants, and they are
the biggest compressors in the gas plants.
The compressor is shown on Figure A7-15. It is a three-stage compressor
with a compression ratio of 1.817 per stage. The temperatures T and T. =
X 1
109ฐF are design conditions. The stage outlet temperatures are calculated
from the equation
= T r(n-1)/n (40)
132
-------
where
T , T. are outlet and inlet temperatures, ฐR, (ฐR = 460 + ฐF)
r is the compression ratio
(n-l)/n = 0.371 for air
The only number which must be chosen is T the temperature between the
A
air cooler and the wet cooler. The following calculations are intended to
determine what T should be.
X
To begin, it is necessary to know the power consumed by a gas compressor.
The general equations for the horsepower needed to drive a gas compressor
3
are :
HP = WH/33,OOOe
(41)
H =!
~ X
(42)
(n-l)/n = (k-l)Ae
(43)
HP is horsepower
W is gas flow in Ib/min
H is polytrophic head (ft-lb)/lb
e is polytrophic efficiency
Z , Z are compressibility factors for suction and discharge
o Q
M is molecular weight
w
T is suction temperature, ฐR(ฐR = 460 + ฐF)
r is the compression ratio
k is ratio of specific heats
133
-------
For air, the appropriate values of the parameters are
w
e -
Z
s
Z
d
k
M
w
D/n -
16.67
0.77
1.0
1.0
1.40
29
0.371
The choice of W means that all calculations are based on 1,000 Ib/hr of
gas. Note that 1,000 Ib/hr of air is equivalent to 233 Ib/hr of oxygen.
The short equation, where P is the power in kw (= 1.341 HP), is:
P = 0.0702 T.(rฐ"371 - 1) (44)
Design
Monthly average and design ambient conditions are as previously given
for turbine condenser calculations. Hot and cold water design temperatures
are 119ฐF and 94ฐF as above, and the tower characteristics are as previously
found. For interstage cooling the tower is assumed independent of the tower
for the turbine condensers. This means a segregated cooling loop which is
acceptable practice but not always done. The two cooling loops are assumed
segregated in this study to limit thecalculation and to aid in understanding
the theory.
T is chosen and the areas of the various wet and dry coolers determined.
X
The heat transfer coefficient varies with the gas pressure as shown on Table
A7-5. The load on the cooler, Btu/hr, is
(gas rate, Ib/hr)(T. - T )c (45)
in out p
The gas rate is 1,000 Ib/hr. The specific heat is sufficiently independent
of temperature and pressure to be taken as constant. We have used
c (air) = 0.241 (46)
134
-------
so, the load
Q = 24KT. - T ) (47)
in out
The wet and dry cooler areas following each stage are calculated and
tabulated. The calculation proceeds as follows.
1) For the design ambient temperature, calculate the first stage outflow
temperature T from Equation (40) which, for this compressor, is
1,0
T = 1.248 T. (48)
out in
2) Calculate the area of the air cooler from the equations
Q_ = U A (LMTD) = 241(T -T ) (49)
JJ L) U U O A
in
where GTD is the greater of the temperature differences
(T - T ) and (T - T )
o D,h X D,d
and LTD is the lesser temperature differences. The nomenclature is given on
Figure A7-15 and Table A7-3.
The hot temperature on the ambient side of the cooler is given by
+ T
T - T = 0.005 U -2- - T , J (51)
D,h D,d D \ 2 D,d
\ /
All four temperatures are known and A can be found for each stage.
3) Calculate the area of the wet cooler from the equation
Q = U A (LMTD) = 241 (T - T.) (52)
www w X i
135
-------
where LMTD is given by an equation similar to Equation (50) in which the
w
temperature differences are
(Tx - th) and (T. - tc)
The design conditions are: T as chosen, t = 119ฐF, T = 109ฐF, t = 94ฐF.
A n J- *~
The wet area is calculated for all stages.
4) The water circulation rates for each wet cooler are calculated from
Equations (15) and (16). The total flow is the sum of the individual flows.
Off-Design Conditions
When turbine condensers were studied, there was actually a penalty for
cooling too low. In this case there is a benefit for cooling to a lower, and
still lower temperature namely, the compression energy is decreased. At
first sight the optimum strategy is not apparent: whether to control the
inlet temperature to each stage or let it go as cold as possible. However,
calculations show that maximum cooling is always preferable. An example can
be given to show this. With the temperature between dry and wet cooling
equal to 160 ฐF in Farmington, New Mexico, the maximum cooling calculations
show a cost of 65.54 f/1000 lb and a water evaporation rate of 1.929 gal/1000 Ib
(Table A7-20) . If water is turned off for months 1, 2, 3, 11 and 12, the
cost goes up by 0.65 C/1000 lb and the water consumption goes down by 0.562
gal/1000 lb (Tables A7-13 and A7-14) . This cost of water is $11. 57/thousand
gallons, which is too high.
Operation with Maximum Cooling
5) The calculation must begin at the entry to the first stage and
proceed through each piece of equipment in series. First the exit temperature
from Stage 1 is calculated.
6) Next, T is calculated by simultaneous solution of Equations (49) ,
A , 1
(50) and (51). A trial-and-error solution is used. A value is assumed for
Tv' Tn >, is calculated from Equation (51) and LMTD is calculated from
A u , n ij
Equation (50). The assumed value for T is correct if Equation (49) is true.
A
if
U A (LMTD) < 241 (T - T )
D D D O X
136
-------
then T has been chosen too low and a larger value must be tried.
A
7) Next, T . is calculated (also be trial and error) . A value for
2. , l
T . is assumed and Q calculated from Equation (52) . The hot and cold water
temperatures are then calculated from the equations
- t - T. + t
VVV ' Vw -
1 -x - fch
lnT~^^
1 C
that is.
and
j T - T - 0 /R
= UQ ^ 1 W L' (55)
W W T t
. X h
In
so,
th(e -1) = e (VQW/V - Tx (56)
where
k = if ( WVV (57)
If the cold water temperature calculated this way is colder than the value
2
given by the cooling tower curves at the prevailing wet bulb temperature and
hot water temperature, then T . has been chosen too low and a higher temper-
z , 1
ature must be tried.
8) Steps 5, 6 and 7 are then repeated for Stage 2. This will result in
a hot and cold water temperature different from those calculated in Step 7.
However, the cold water to both wet coolers must have the same temperature
because it all comes from the same cooling tower basin. The hot water temper-
ature to the tower is the temperature resulting from mixing the two streams.
137
-------
It is necessary, therefore, to determine those hot and cold water temperatures
which satisfy the calculations for both stages. In fact, only one repeat
calculation is needed using an average of the water temperatures found for
Stages 1 and 2 separately.
9) For air separation there is little benefit to having T . < 95ฐF so
cilir
the third stage water cooler is turned off when T <_ 95ฐF.
A , O
10) The calculations of all the temperatures are made month by month
beginning with the hottest month and continuing through successively cooler
months. In the colder months little benefit is obtained from the wet cooler.
The purpose of the wet cooler is to decrease the energy consumed in compression.
When (T -T.) _<_ 5ฐF, the wet cooler gives less than one percent reduction in
x i
compression energy and we considered turning off the wet coolers, circulating
water and tower. However, we found no cases where T -T. < 5ฐF.
A 1
11) From the above calculations the grand total wet load each month is known,
and so the water evaporated can now be calculated using the procedure previously
given.
12) The fan and pump energies are calculated as previously described.
13) The compression energy is calculated from Equation (41).
Results
The results are shown on Tables A7-15 to A7-18, with summaries on Table
A7-19 and costs on Table A7-20. The cost of compression energy is calculated
from steam at $1.80/10 Btu and a heat rate of 11,700 Btu/kw-hr, making
ฃ2.106/kw-hr. As with turbine condensers, please note that the "total costs"
(C/1000 lb) refer only to those costs dependent on the choice of cooling system.
Other cost components such as purchase of the compressors are omitted.
As a result of these calculations, it is clear that there is a price of
water above which the use of series dry/wet interstage cooling is the economic
choice. This price of water is about $1.50/10 gal, and dry cooling will only
be introduced into interstage cooling of air compressors when water is scarce.
Once the decision has been made to use partial dry cooling, the fraction of
the load to be carried by the dry cooler is found to vary significantly with
the cost of water. The effect of the cost of water is more gradual than was
found from the calculations on turbine condensers. Also, the fraction of
the load carried by the dry cooler depends on how the cooling system is
138
-------
operated. Finally, the calculations were made on air compressors and there
are other compressors.
For estimation on a large number of plants, we have assumed that when
water is sufficiently scarce, dry cooling is used; then dry cooling will carry
50 percent of the load of all interstage compressors in all plants in all
locations. This is the best that we can do at this time, but please recognize
that it is quite a rough approximation.
REFERENCES, APPENDIX 7
1. Water Purification Associates, "Water Conservation and Pollution Control in
Coal Conversion Processes," U.S. Environmental Protection Agency, Report
EPA 600/7-77, June 1977.
2. Kelly's Handbook of Crossflow Cooling Tower Performance, Neil W. Kelly
and Associates, Kansas City,- Missouri.
3. Neerken, R.F., "Compressor Selection for the Chemical Process Industries,"
Chemical Engineering 78-94, January 20, 1975.
139
-------
1
_ 0.5
oo
LU
Q
O
tH
I
O
0.2 0.4 0.6
WATER CONSUMPTION, GAL/KW-HR
0.8
Figure A7-1. Cost of steam turbine condenser cooling in Farmington,
New Mexico.
140
-------
0.30
0.25
ce:
in
i
-<=>-
0.20
0.15
0.10
\
\
V-
I
0.5
ct:
a
a
LU
^ป
CD
UJ
Q
O
0.2 0.4 0.6
WATER CONSUMPTION, GAL/KW-HR
0.8
Figure A7-2, Cost of steam turbine condenser cooling in Casper, Wyoming
141
-------
o:
31
I
O
O
0.30
0.25
0.20
0.15
0.10 _
0.2
0.4
0.6
0.5
>-
O
O
UJ
z.
CD
it
U~l
LU
Q
Z
O
HI
I
O
0.8
WATER CONSUMPTION, GAL/KW-HR
Figure A7-3.
Cost of steam turbine condenser cooling in Charleston,
W. Virginia.
142
-------
OO
o
O
0.3
0.25
0.2
0.15
0.1
GAL
0.2
0.4
0.6
0.5
ex.
Q
Q
UJ
CD
UJ
Q
O
("
M
O
0.8
WATER CONSUMPTION, GAL/KW-HR
Figure A7-4. Cost of steam turbine condenser cooling in Akron, Ohio.
143
-------
o
o
ซc
o
CO
o
2T
O
CsL
LU
100
80
60
40
20
CASPER,
1^_FARMINGTON
I
CHARLESTON
AKRON
10
20
30
40
WATER COST, CENTS/10 GAL
Figure A7-5.
The effect of water cost on water consumed for cooling
turbine condensers.
144
-------
66
CO
o
CD
O
CO
O
O
65
64
J_
246
WATER CONSUMPTION, GAL/1,000 LB
Figure A7-6. Cost of interstage cooling -for compressing 1,000 Ib
air at Farmington, New Mexico.
145
-------
66
CO
O
o
O
CO
o
65
64
0246
WATER CONSUMPTION, GAL/1,000 LB
8
Figure A7-7. Cost of interstage cooling for compressing 1,000 Ib air
at Casper, Wyoming.
146
-------
66
O
o
o
CO
o
o
65
64
246
WATER CONSUMPTION, GAL/1,000 LB
Figure A7-8.
Cost of interstage cooling for compressing 1,000 Ib air
at Charleston, W. Virginia.
147
-------
66
CO
o
CD
O
-fc>-
c/1
O
O
65
64
_L
246
WATER CONSUMPTION, GAL/1S000 LB
Figure A7-9. Cost of interstage cooling for compressing 1,000 Ib
air at Akron, Ohio.
148
-------
03
O
o
O
CC
o
UJ
O
UJ
o
CJ
o;
100
80
60
40
20
^- FARMINGTON
AKRON
CASPER
X\ \\
CHARLESTON -~\\ \
100
150
200
250
WATER COST, CENTS/10 GAL
Figure A7-10. The effect of water cost on water consumed for
interstage cooling when compressing 1,000 Ib air.
149
-------
Ln
O
>
STEAM
FROM
TURBINE
CONDE
k
CO OO OO CO
1
1
Tc
NSATE
1
1
DRY
WET
Tc
ซaf
l
'
EVAPORATION
A
tb RL
*" I
1- -,
BYPASS UA " "
t "* r^\ . tw \
^^ AIR RATE,
Figure A7-11. Turbine condenser cooling systems.
-------
15
ffl
fO
O
LJ
H
<
o:
STEAM
TEMP
(I) 600
(2) 700
13) 900
(4) 900
STEAM
PRESSURE
(PS!A)
715
915
7!5
915
UJ
I-
no
115 120 130 134
CONDENSER TEMPERATURE (ฐF)
140
Figure A7-12. Turbine heat rates at full load.
151
-------
15
13
CO
10
o
o
O
cc
LJ
tf)
z
LJ
Q
Z
O
o
10
STEAM
TEMP
(I) 600
(2) 700
(3) 900
900
STEAM
PRESSURE
(PSIA)
715
915
715
915
en
X
ro
o>
x
no
115 120 130 134
CONDENSER TEMPERATURE (ฐF)
140
Figure A7-13. Turbine condenser cooling requirements at full load.
152
-------
0 20 40 60 80
AMBIENT TEMPERATURE DROP(ฐF)
Figure A7-14. Fan power reduction factor for air coolers.
153
-------
AMBIENT
Tr J
15 psia
N
i
27.26 psia
T
3,o =
250ฐF
\
3
IX]
90 psia
Figure A7-15. Air compressor design conditions.
-------
TABLE A7-1. ASSIGNMENT OF COOLING LOADS
Assigned to dry cooling: 0% wet
Assigned to wet cooling: 100% wet
Gas purification regenerator condenser: 100% dry for Synthoil, Bigas
and Synthane; 90% dry, 10% wet
for SRC and Hygas
Steam turbine condensers: site dependent
Gas compressor interstage coolers: site dependent
-------
TABLE A7-2. WATER AVAILABILITY AND EVAPORATION RATE
Je f ferson
Ha rengo
I_I linoi_s
Bureau
Shelby
St. clair
White
Fulton
Saline
1ndian a
Gibson
Vigo
Ohio
GalUa
Tuscarawas
Jefferson
Penjrsy Ivania
Armstrong
Somerse t
West Virginia
Fayette
K^nawha
Marshall
Honongalia
Preston
Mingo
Water
Aval lability*
1
2
1
3
1
1
3
3
1
1
1
1
3
3
1
2
2
1
2
1
1
2
1
1
1
2
2
2
Btu/lb
Evaporated
1310
1310
1390
1390
1380
1370
1390
1370
1370
1390
1380
1370
1360
1350
1370
1370
1360
1420
1410
1400
1410
1410
1360
1360
13BO
1380
1380
1360
Wy pm ing
Gillette (WyodaJO
L^ke de Sme t-Banner-Healy
Antelope Creek Mine (Verse)
Spotted Horse Strip-Felix Bed
Jim Bridger Mine
Belle Ayr Mine
Hanna Coal Field {Rosebud 84,5)
Kemmerer
Rainbow 88 Mine
North^ Dakota
^
Slope (Harmon)
Knife River
Dickinson
Williston
Center
Bentley
Underwood
Scrajiton
Montana
Decker (Dietz)
Otter Creek (Knobloch)
East Moorhead Coal Field
Foster Creek
Pumpkin Creek
Coalridge
U.S. Steel, Chupp Mine
Colstrip
El Paso
Wesco
Gallup
Water
Availability*
3
1
3
3
2
3
1
2
1
3
2
3
1
3
3
1
3
1
3
3
2
3
3
1
2
3
3
3
Btu/Lb
Evaporated
1401
1401
1397
1401
1397
1401
1397
1397
1397
1417
1420
1420
1420
1420
1420
1420
1417
1407
1407
1407
1414
1414
1407
1417
1414
1375
1375
1375
*Classif ication: 1 *= water available, 2
3 ป water expensive to supply.
water marginally available,
(continued)
-------
TABLE A7-3. NOMENCLATURE
condenser area, ft
cooling tower circulation pump ene rgy, kw
dry condenser fan energy, kv
cooling tower fan energy, kw
dry condenser fan factor
absolute humidity of air, l_b water/lb dry air
enthaipy of air, Btu/lb dry air
log mean temp-e racure difference, ฐF
compression pouer, kw
condenser cooling load, Btu/kw-hr
condenser dry cooling load, Btu/kv-hr
turbine hea t ra te, 8 tu/kw-hr
condenser wet cooling load, Btu/kw-hr
compress ion ratio
air rate through the to-wer, Lb/hr
cooling water circulation rate, gpm/kw
cooling water circulation rate, Ib/kw-hr
5 team condensing tempe rature, CF
cold circulating water temperature, ฐF
air dry bul_b temperature, "F
air temperature at which dry condenser wi11 carry whole load,
hot circulating water temperature, ฐF
temperature at bottom of cooling tover, eF
air wet bulb temperature, "F
heat transfer coefficient, Btu/(hr){ft )(*F)
fraction of cooling load carried dry
fraction of circulating water that bypasses the cooling tower
cold or entry temperature
condensing temperature
dry
design condition
exiting, or out
hot, or exit temperature
entering, or in
out, or discharge
wet
temperature between dry and wet series coolers between compression
stages
1,2,3 compressor stages
-------
TABLE A7-4. AVERAGE AMBIENT CONDITIONS
Farmington, N.M.
Month
1 , January
2 , February
3, March
4, April
5, May
6 , June
7, July
8, August
9, September
10, October
11, November
12, December
Design
DBT*
26
33
42
49
60
70
76
73
64
51
39
27
98
WBT**
23
28
33
37
45
51
58
57
49
41
32
24
65
Casper, Wyo.
DBT
24
26
32
41
54
65
71
70
59
47
32
30
96
WBT
20
22
27
34
44
51
55
53
46
38
27
25
60
Charleston, W.V.
DBT
36
38
45
55
64
72
75
74
69
57
46
38
WBT
33
34
40
49
58
67
69
68
64
52
41
34
Akron , Ohio
DBT
27
28
37
47
59
68
72
71
65
53
40
30
WBT
25
26
35
44
54
63
66
65
60
49
38
28
87
79
83
76
*DBT = dry bulb temperature (ฐF).
**WBT = wet bulb temperature (ฐF).
158
-------
TABLE A7-5. HEAT TRANSFER COEFFICIENTS, FAN AND PUMP ENERGIES
U[Btu/(hr)(ft )(ฐF)3
Dry
Condensing steam from turbine drives : 120
Cooling a compressed gas :
10 psig
50 psig
100 psig
300 psig
>_ 500 psig
Air
10
20
30
40
50
Dry
Hydrogen
30
45
65
85
95
Air
12
20
40
60
70
Wet
170
Wet
Hydrogen
35
75
100
135
150
Dry cooler fans: kw = 0.0112 x area (U <_ 50)
= 0,0130 x area (50 >_ U > 100)
= 0.0149 x area (U >_ 100)
Cooling tower fans: kw = 0.0089 x gpm circulated
Circulating water pumps: kw = 0.0246 x gpm circulated
159
-------
TABLE A7-6. UNIT COSTS
Condensers and
heat exchanger:
Dry cooling
Wet cooling
Other:
Cooling tower
Electrical energy
Steam
Cost
Pressure
(p,psig)
2*
$22/ft
$Il.O/ft'
$12.I/ft'
$13.2/ft'
$19.2/ft':
$20/gpm circulated
2ฃ/kw-hr
$1.80/106 Btu
p < 300
300 ^ p < 450
450 ฃ p < 600
p > 600
Annual Charges
for Amortization
Plus Maintenance
17%/yr
20%/yr
15%/yr
*Based on bare tube area of finned tubes.
160
-------
TABLE A7-7. CALCULATIONS ON STEAM TURBINE CONDENSERS AT FARMINGTON, MEW MEXICO
Design Conditions: Fraction designed dry 0.
2 ' 2
Dry condenser area 0 ft /kw, wet condenser area 2.0069 ft
Cooling tower information: characteristic, KaY/L ซ= 1.24, water/gas rates 2.12,
circulation rate 348 Ib/kw-hr, 0.696 gpm/kw.
Month
10
11
12
Condenser temperature (ฐF)
Turbine heat rate (Btu/kw-hr)
Total condenser load (Btu/kw-hr)
Dry condenser load (Btu/kw-hr)
Wet condenser load (Btu/kw-hr)
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower
-3 kw-hr
Dry fan power (10 , )
-3 kw-hr
Coolg tower fan pwr (10 , , )
KW nr
-3 kw-hr
Circulating pump pwr (10
Water evaporated (Ib/kw-hr)
115
11,700
8,200
0
8,200
101
77
60
0.41
0
3.65
) 17.1
5.52
115
11,700
8,200
0
8,200
101
77
65
0.33
0
5.39
17.1
5.57
117
11,753
8,253
0
8,253
103
79
79
0
0
6.19
17.1
5.41
119
11,806
8,306
0
8,306
105
81
81
0
0
6.19
17.1
5.67
124
11,938
8,437
0
8,437
109,
85
85
0
0
6.19
17.1
6.06
126
11,990
8,490
0
8,490
111
87
87
0
0
6.19
17.1
6.45
131
12,122
8,622
0
8,622
116
91
91
0
0
6.19
17.1
6.69
129
12,069
8,569
0
8,569
114
90
90
0
0
6.19
17.1
6.601
125
11,964
8,464
0
8,464
110
86
86
0
0
6.19
17.1
6.23
120
11,832
8,332
0
8,332
106
82
82
0
0
6.19
17.1
5.78
116
11,727
8,227
0
8,227
102
78
78
0
0
6.19
17.1
5.36
115
11,700
8,200
0
8,200
101
77
61
0.40
0
3.72
17.1
5.36
(continued)
-------
TABLE A7-7 (continued)
Design Conditions: Fraction designed dry 0.25.
2 )
Dry condenser area 0.7689 ft AW, wet condenser area 1.5051 ft AW.
Cooling tower information: characteristic, KaY/L = 1.24, water/gas rates 2.12,
circulation rate 261 IbAw-hr, 0.522 gpmAw.
Month 123456789 10 11 12
Condenser temperature (ฐF) 115 115 115 115 115 119 123 122 115 115 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,700 11,806 11,911 11,885 11,700 11,700 11,700 11,700
Total condenser load (BtuAw-hr) 8,200 8,200 8,200 8,200 8,200 8,306 8,411 6,385 8,200 8,200 8,200 6,200
Dry condenser load (BtuAw-hr) 5,377 4,954 4,410 . 3,987 3,322 2,960 2,839 2,960 3,081 3,867 4,592 5,316
Wet condenser load (BtuAw-hr) 2,823 3,246 3,790 4,213 4,877 5,346 5,572 5,425 5,119 4,334 3,609 2,884
Hot water temperature (ฐF) 109 108 106 105 104 107 110 109 103 105 107 108
Cold water temperature (ฐF) 96 95 92 89 85 86 89 89 84 88 93 97
Tower bottom temperature (ฐF) 60 65 70 84 83 86 89 89 83 82 69 61
Fraction circulating water
that bypasses tower 0.78 0.70 0.33 0.24 0.10 000 0.05 0.26 0.75 0.77
Dry fan power (10~3 -kw"^r) 11.5 11.5 11.5 11.5 11.5 11.5 11.5 11.5 11.5 11.5 11.5 11.5
kw-hr
Coolg tower fan pwr (10~3 ^^) 1.02 1.39 3.11 3.53 4.16 4.64 4.64 4.64 4.41 3.44 1.16 1.C6
kw-hr
Circulating pump pwr (10~3 ^W"^r) 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8
Water evaporated (IbAw-hr) 1.96 2.23 2.45 2.84 3.46 4.36 4.70 4.16 3.70 2.94 2.61 2.01
(continued)
-------
TABLE A7-7 (continued)
Degj-gn Conditiors; Fraction designed dry 0.50.
2 2
Dry condenser area 1.5378 ft /kw, wet condenser area 1.0035 ft /kw.
Cooling tower information: characteristic, KaY/L = 1.24, water/gas rates 2.12,
circulation rate 174 Ib/kw-hr, 0.348 gpm/kw.
Month 123456789 10 11 12
Condenser temperature (ฐF)
Turbine heat rate (Btu/kw-hr)
Total condenser load (Btu/kw-hr)
Dry condenser load (Btu/kw-hr)
Wet condenser load (Btu/kw-hr)
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower
r , iซ~3 kw-hr v
Div fan power (10 )
kw hr
3 kw hr
Coolq tower fan pwr (10 , , )
3 kw-hr
3 kwhr
Circulating pump pwr (10 - j
Water evaporated (Ib/kw-hr)
115
11,700
8,200
8,200
0
__
--
_.
1.0
5.25
0
i 0
0
115
11,700
8,200
8,200
0
_
1.0
7.79
0
0
0
115
11,700
8,200
8,200
0
--
__
~
1.0
14.77
0
0
0
115
11,700
8,200
7,975
224
114
113
92
0.95
22.9
0.15
8.56
0.16
115
11,700
8,200
6,646
1,554
110
101
88
0.59
22.9
1.27
8.56
1.06
115
11,700
8,200
5,438.
2,762
105
90
85
0.75
22.9
0.77
8.56
2.18
117
11,753
8,253
4,954
3,299
106
87
87
0
22.9
3.10
8.56
2.56
115
11,700
8,200
5,075
3,125
104
86
85
0.05
22.9
2.94
8.56
2.45
115
11,700
8,200
6,163
2,037
108
96
86
0.45
22.9
1.70
8. 56
1.49
115
11,700
8,200
7,734
466
113
111
88
0.92
22.9
0.25
8.56
0.24
115
11,700
8,200
8,200
0
__
--
-_
1.0
11.57
0
0
0
115
11,700
8,200
8,200
0
--
1.0
4.81
0
0
0
(continued)
-------
en
TABLE A7-7 (continued)
Design Conditions: Fraction designed dry 0.75.
2 ?
Dry condenser area 2.3069 ft Aw, wet condenser area 0.5017 ft Aw.
Cooling tower information: characteristic, KaY/L = 1.24, water/gas rates 2.12,
circulation rate 87 IbAw-hr, 0.174 gpm/kw.
Month 12 3456789 10 11 12
Condenser temperature (ฐF) 115 115 115 115 115 115 115 115 115 115 115 115
Turbine heat rate (BtuAw-hr) 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700
Total condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200
Dry condenser load (Btu/kw-hr) 8,200
Wet condenser load (BtuAw-hr) 0
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower 1.0
-3 kw-hr
Dry fan power (10 T ; ) 4.50
kw-hr
,-., ^ ^ ,,^-3 kw-hr,
kw-hr
-3 kw-hr.
Water evaporated (Ib/kw-hr) 0
8,200 8,200 8,200 8,200 8,157
0 0 0 0 43
115
114
88
1.0 1.0 1.0 1.0 0.96
4.98 6.19 7.97 15.5 34.4
0 0 0 0 0.06
0000 4.28
0000 0.035
7,069
1,131
107
94
92
0.13
34.4
1.35
4.28
0.93
7,613 8,200 8,200 8,200
587 0 0 0
111
104
89
0.68 1.0 1.0 1.0
34.4 21.21 8.83 4.85
0.49 000
4.28 000
0.453 000
8,200
0
1.0
4.54
0
0
0
(continued)
-------
TABLE 7-7 (continued)
Design Conditions; Fraction designed dry 0.95.
2 2
Dry condenser area 2.922 ft /kw, wet condenser area 0.1003 ft
Cooling tower information: characteristic, KaY/L = 1.24, water/gas rates 2.12,
circulation rate 17.4 Lb/kw-hr, 0.0348 gpm/kw.
Month 12 3456789 10 11 12
Condenser temperature (ฐF) 115
Turbine heat rate (Btu/kw-hr) 11,700
Total condenser load (Btu/kw-hr) 8,200
Dry condenser load (Btu/kw-hr) 8,200
Wet condenser load (Btu/kw-hr) 0
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower 1.0
,,~-3 kw-hr,
Dry fan power (10 ~ : ) 5.22
kw-hr
-3 kw-hr
Coolg tower fan pwr (10 , , ) 0
kw-hr
-3 kw-hr.
Circulating pump pwr (10 ~ r ) 0
Water evaporated (Ib/kw-hr) 0
115 115 115
11,700 11,700 11,700
8,200 8,200 8,200
8,200 8,200 8,200
000
__
_
--
1.0 1.0 1.0
5.70 6.26 7.27
000
000
000
115
11,700
8,200
8,200
0
__
__
1.0
10.8
0
0
0
115
11,700
8,200
8,200
0
__
1.0
20.2
0
0
0
115 115 115 115 115 115
11., 700 11,700 11,700 11,700 11,700 11,700
8,200 8,200 8,200 8,200 8,200 8,200
8,200 8,200 8,200 8,200 8,200 8,200
000000
__
1.0 1.0 1.0 1.0 1.0 1.0
33.18 25.69 13.63 7.71 6.05 5.27
000000
000000
000000
-------
TABLE A7-8. CALCULATIONS ON STEAM TURBINE CONDENSERS AT CASPER, WYOMING
Design Conditions: Fraction designed dry 0.
2 2
Dry condenser area 0 ft /kw, wet condenser area 2.0069 ft AW.
Cooling tower information: characteristic, KaY/L = 1.17, water/gas rates 2.24,
circulation rate 348 Ib/kw-hr, 0.696 gpm/kw.
Month 1 2 3 4 5 6 7 8 9 10 11 12
Condenser temperature (ฐF)
Turbine heat rate (Btu/kw-hr)
Total condenser load (BtuAw-hr)
Dry condenser load (Btu/kw-hr)
H
g} Wet condenser load (Btu/kw-hr)
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower
rs_ c ,,,-,~ 3 kw-hr,
JJry tan power (10 , )
Pnnlrr -H-tr^-i- T-i ^ir-i- MA KW" nr.
i-ooig cower ran pwr ^J-U T~ )
}tw~*nr
Circulating pump pwr (10 )
Water evaporated (lb/kw-hr)
115
11,700
8,200
0
8,200
101
77
57
0.45
0
3.40
17.12
5.54
115
11,700
8,200
0
8,200
101
77
59
0.43
0
3.53
17.12
5.57
116
11,727
8,227
0
8,227
102
78
78
0
0
6.19
17.12
5.28
122
11,885
8,385
0
8,385
108
83
83
0
0
6.19
17.12
5.47
127
12,016
8,516
0
8,516
112
88
88
0
0
6.19
17.12
6.00
130
12,096
8,596
0
8,596
115
90
90
0
0
6.19
17.12
6.39
131
12,122
8,622
0
8,622
116
91
91
0
0
6.19
17.12
6.56
130
12,096
8,596
0
8,596
115
90
90
0
0
6.19
17.12
6.52
129
12,069
8,569
0
8,569
114
90
90
0
0
6.19
17.12
6.22
122
11,885
8,385
0
8,385
108
83
83
0
0
6.19
17.12
5.78
116
11,727
8,227
0
8,227
102
78
78
0
0
6.19
17.12
5.28
115
11,700
8,200
0
8,200
101
77
62
0.38
0
3.84
17.12
5.4S
(continued)
-------
TABLE A7-8 (continued)
Design Conditions: Fraction designed dry 0.25.
Dry condenser area 0.728 ft /kw, wet condenser area 1.5051 ft /kw.
Cooling tower information: characteristic, KaY/L = 1.17, water/gas rates 2.24,
circulation rate 261 Ib/kw-hr, 0.522 gpm/kw.
Month 1 2 3 4 5 6 7 8 9 10 'll 12
Condenser temperature (ฐF) 115 115 115 115 115 118 122 121 115 115 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,700 11,780 11,885 11,859 11,700 11,700 11,700 11,700
Total condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,200 8,200 8,279 8.,385 8,358 8,200 8,200 8,200 8,200
Dry condenser load (Btu/kw-hr) 5,206 5,091 4,747 4,233 3,203 3,032- 2,917 2,917 3,203 3,890 4,748 4,862
Wet condenser load (Btu/kw-hr) 2,995 3,109 3,452 3,967 4,997 5,248 5,468 5,441 4,997 4,311 3,452 3,338
Hot water temperature (ฐF)
Cold water temperature (SF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower
., -3 kw-hr.
Dry tan power (10 )
-3 kw-hr,
Cooig tower fan pwr ilO )
K W"ฐ H IT
Circulating pump pwr (10*3 ฃ^) 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8
KW il2T
Water evaporated (Ib/kw-hr) 2.07 2.14 2.40 2.71 3.52 3.91 4.20 4.06 3,56 2.91 2.40 2.33
(continued)
108
97
57
0.78
10.8
1.02
108
96
59
0.75
10.8
1.16
107
94
64
0.70
10.8
1.39
106
91
71
0.57
10.8
2.00
104
84
84
0
10.8
4.65
106
86
86
0
10.8
4.65
109
88
88
0
10.8
4.65
108
88
88
0
10.8
4.65
104
84
84
0
10.8
4. 65
105
89
84
0.24
10.8
3.53
107
94
64
0. 70
10.8
1.39
107
95
62
0,73
10.8
1.25
-------
H
CTi
CD
TABLE A7-8 (continued)
Design Conditions; Fraction designed dry 0.50.
Dry condenser area 1.4568 ftVkw, wet condenser area 1.0035 ft2Aw.
Cooling tower information: characteristic, KaY/L = 1.17, water/gas rates 2.24,
circulation rate 174 Ib/kw-hr, 0.348 gpm/kw.
Month 12 3456789 10 11 12
Condenser temperature (ซF) 115 115 115 115 115 115 115 115 115 115 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700
Total condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200
Dry condenser load (BtuAw-hr) 8,200 8,200 8,200 8,200 6,982 5,723 5,036 5,151 6,410 7,784 8,200 8,200
Wet condenser load (Btu/kw-hr) 0
Hot water temperature (ฐF)
Cold water temperature (ฐF) -
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower 1.0
r^ .c _ . . /i r\~ ^ Kw*~nrx r A ^
Dry ran power ilu - ; ; 3.42
kw-hr
-3 kw-hr
Coolg tower fan pwr (10 ) 0
3 kw hr
Circulating pump pwr (10 r r ) 0
}cwrijr
Water evaporated (Ib /kw-hr) 0
000 1,218
HI
104
87
1.0 1.0 1.0 0.71
6.07 8.79 17.97 21.7
000 0.90
000 8.56
0 0 0 0.87
2,477
106
92
86
0.30
21.7
2.17
8.56
1.86
3,164
104
86
86
0
21.7
3.10
8.56
2.40
3,049
104
87
86
0.06
21.7
2.91
8.56
2.36
1,790
109
99
87
0.55
21.7
1.39
8.56
1.29
416 0
114
111
90
0.91 1.0
21.7 8.79
0.29 0
8.56 0
0.009 0
0
--
1.0
7.73
0
0
0
(continued)
-------
TABLE A7-8 (continued)
Derj.gn Conditions; Fraction designed dry 0.75.
2 2
Dry condenser area 2.185 ft /kw, wet condenser area 0.5017 ft /Tew.
Cooling tower information: characteristic, KaY/L = 1.17, water/gas rates 2.24,
circulation rate 87 Ib/kw-hr, 0.174 gpm/kw.
Month 12 3456789 10 11 12
Condenser temperature (ฐF) 115
Turbine heat rate (BtuAw~hr) 11,700
Total condenser load (Btu/kw-hr) 8,200
Dry condenser load (BtuAw~hr) 8,200
cri Wet condenser load (Btu/kw-hr) 0
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower 1.0
n -ir ^ L i - 1 - - T M n~ Kw-nr. ^,
ury ran power liu , , ) 4aJU
c kw-hr
-3 kw-hr
Coolg tower ran pwr (10 . . ) 0
^ e kw-hr
n~3 kw-hr.
Circulating puirip pwr (10 . ) 0
Water evaporated (Ib /kw-hr) 0
115 115
11,700 11,700
8,200 8,200
8,200 8,200
0 0
__
--
1,0 1.0
4.43 4.85
0 0
0 0
0 0
115 115 115
11,700 11,700 11,700
8,200 8,200 8,200
8,200 8,200 8,200
000
__
1.0 1.0 1.0
6.32 11.69 27.05
000
000
000
115
11;700
8,200
7,554
646
111
103
89
0.64
32.5
0.56
4.28
0.48
115 115
11,700 11,700
8,200 8,200
7,726 6,200
474 0
112
106
89
0.74 1.0
32.5 16.38
0.40 0
4.28 0
0.36 0
115 115 115
11,700 11,700 11,700
8,200 8,200 8,200
8,200 8,200 8,200
000
__
__
1.0 1.0 1.0
7.72 4.85 4.66
000
000
000
(continued)
-------
T/VBLE A7-8 (continued)
Design Conditions: Fraction designed dry 0.95.
Dry condenser area 2.7680 ft /kw, wet condenser area 0.1003 ft /kw.
Cooling tower information: characteristic, KaY/L = 1.17, water/gas rates 2.24,
circulation rate 17.4 IbAw-hr, 0.0348
Month 123456789 10 11 12
Condenser temperature (ฐF) 115 115 115 115 115 115 115 115 115 115 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700
Total condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200
Dry condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200
h-1
-J Wet condenser load (BtuAw-hr) 000000000000
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF) -- --
Fraction circulating water
that bypasses tower 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0
Dry fan power (10~3 ^~) 4.95 4.99 5.32 6.06 8.66 15.71 24.29 22.11 10.81 6.89 5.32 4.65
Kw jiir
Coolg tower fan pwr (10~3 ^~-) 000000000000
kw-hr
Circulating pump pwr (10~3 !"\^") 000000000000
Water evaporated (lb/kw-hr) 000000000000
-------
TABLE A7-9. CALCULATIONS ON STEAM TURBINE CONDENSERS AT CHARLESTON, WEST VIRGINIA
Conditions : Fraction designed dry 0.
2 2
Dry condenser area 0 ft /kw, wet condenser area 2.0069 ft /kw=
Cooling tower information: characteristic, KaY/L = 1.44, water/gas rates 1.45,
circulation rate 348 Ib/kw-hr, 0.6^6 gpra/kw.
Month 1 2 3 4 5 6 7 8 9 10 11 12
Condenser temperature (ฐF) 115 115 115 117 122 126 128 127 125 120 115 115
Turbine heat rate (BtuAw-hr) 11,700 11,700 11,700 11,753 11,885 11,990 12,042 12,016 11,964 11,832 11,700 11,700
Total condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,253 8,385 8,490 8,542 8,516 8,464 8,332 8,200 8,200
Dry condenser load (Btu/kw-hr)
Wet condenser load (Btu/kw-hr)
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower
-3 kw-hr
Dry fan power (10 , , )
J r kw-hr
-3 kw-hr.
Coolo tower fan pwr (10 ; j
r kw-hr
-3 kw-hr,
Circulating pump pwr (10 ~ T J
Water evaporated (Ib/kw-hr)
0
8,200
101
77
74
0.11
0
5.51
17.12
5.13
0
8,200
101
77
74
0.11
0
5.51
17.12
5.17
0
8,200
101
77
76
0.04
0
5.95
17.12
5.32
0
8,253
103
79
79
0
0
6.19
17.12
5.66
0
8,385
108
83
83
0
0
6.19
17.12
5.98
0
8,490
111
87
87
0
0
6.19
17.12
6.24
0
8,542
113
89
89
0
0
6.19
17.12
6.36
0
8,516
112
88
88
0
0
6.19
17.12
6.02
0
8,464
110
86
86
0
0
6.19
17.12
5.98
0
8,332
106
82
82
0
0
6.19
17.12
5.71
0
8,200
101
77
77
0
0
6.19
17.12
5.33
0
8,200
101
77
74
0.11
0
5.51
17.12
5.17
(continued)
-------
TABLE A7-9 (continued)
Design Conditions: Fraction designed dry 0.25.
Dry condenser area 0.5889 ft AW, wet condenser area 1.5051 ft2Aw.
Cooling tower information: characteristic, KaY/L = 1.44, water/gas rates 1.45,
circulation rate 261 IbAw-hr, 0.522 gpmAw.
Month 123456789 10 11 12
Condenser temperature (ฐF) 115 115 115 115 118 124 126 125 122 115 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,780 11,938 11,990 11,964 11,885 11,700 11,700 11,700
Total condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,200 8,279 8,437 8,490 8,464 8,385 8,200 8,200 8,200
Dry condenser load (Btu/kw-hr)
Wet condenser load (BtuAw-hr)
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower
3 kw hr
Dry fan power (10 )
kw-hr
-3 kw-hr.
Coolg tower fan pwr (10 ~ r )
kw-nr
i . . ,,-3 kw-hr.
Water evaporated (lbAw~hr)
3,655
4,545
105
87
77
0.36
8.77
2.97
12.8
2.87
3,563
4,637
104
87
76
0.39
8.77
2.83
12.8
2.98
3,239
4,961
103
85
77
0.46
8.77
2.51
12.8
3.31
2,776
5,424
103
62
79
0.13
8.77
4.04
12.8
3.77
2,498
5,781
105
83
83
0
8.77
4.65
12.8
4.12
2,406
6,031
110
87
87
0
8.77
4.65
12.6
4.45
2,360
6,130
112
68
88
0
8.77
4.65
12.8
4.50
2,360
6,104
111
88
88
0
8.77
4.65
12.8
4.47
2,453
5,932
108
86
86
0
6.77
4.65
12.8
4.30
2,683
5,517
102
81
79
0.09
8.77
4.23
12.8
3.75
3,193
5,007
103
84
78
0.24
8.77
3.53
12.8
3.28
3,563
4,637
104
87
76
0.39
8.77
2.83
12.8
2.98
(continued)
-------
TABLE A7-9 (continued)
Design Conditions; Fraction designed dry 0.50.
2 2
Dry condenser area 1.177 ft fKu, wet condenser area 1.0035 ft AW.
Cooling tower information: characteristic, KaY/L = 1.44, water/gas rates 1.45,
circulation rate 174 Ib/kw-hr, 0.348 gpm/kw.
Month 1 2 3 4 5 6 7 8 9 10 11 12
Condenser temperature (ฐF) 115 115 115 115 115 122 124 123 119 115 115 115
Turbine heat rate (BtuAw-hr) 11,700 11,700 11,700 11,700 11,700 11,885 11,938 11,911 11,806 11,700 11,700 11,700
Total condenser load (BtuAw-hr) 8,200 8,200 8,200 8,200 8,200 8,385 8,437 8,411 8,306 8,200 8,200 8,200
Dry condenser load (Btu/kw-hr) 7,306 7,121 6,474 5,549 4,716 4,624 4,532 4,532 4,624 5,364 6,381 7,121
Wet condenser load (Btu/kw-hr) 894 1,079 1,726 2,651 3,484 3,761 3,905 3,879 3,682 2,836 1,819 1,079
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower 0.85 0.81 0.65 0.42 0.05 0000 0.33 0.62 0.81
-1 ku-hr
Dry fan power (10 , '-) 17.54 17.54 17.54 17.54 17.54 17.54 17.54 17.54 17.54 17.54 17.54 17.54
1 * kw~hr
Coolg tower fan pwr do"3 ~^) 0.46 0.59 1.08 1.80 2.94 3.10 3.10 3.10 3.10 2.08 1.18 0.59
KW** nr
_ > vw_hr
Circulating pump pwr (10 ฃ) 8.56 8.56 8.56 8.56 8.56 8.56 8.56 a. 56 8.56 8.56 8.56 8.56
KW*" Ai
Water evaporated (IbAw-hr) 0.57 0.70 1.22 1.84 2.52 2.76 2.76 2.76 2.69 1.97 1.20 0.70
(continued)
112
107
79
111
105
80
109
99
80
106
91
80
103
83
82
109
87
87
111
88
88
110
87
87
106
85
85
105
89
81
109
98
80
111
105
80
-------
TABLE A7-9 (continued)
Design Conditions: Fraction designed dry 0.75.
Dry condenser area 1.7668 ft /kw, wet condenser area 0.5017 ft2/kw.
Cooling tower information: characteristic, KaY/L = 1.44, water/gas rates 1.45,
circulation rate 87 lb/kw-hr, 0.174 gpm/kw.
Month 123456789 10 11 12
Condenser temperature (ฐF) 115 115 115 115 115 118 122 121 116 115 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,700 11,780 11,885 11,859 11,727 11,700 11,700 11,700
Total condenser load (BtuAw-hr) 8,200 8,200 8,200 8,200 8,200 8,306 8,385 8,358 8,227 8,200 8,200 8,200
Dry condenser load (BtuAw-hr) 8,200 8,200 8,200 8,200 7,080 6,525 6,525 6,525 6,525 8,052 8,200 8,200
Wet condenser load (Btu/kw-hr) 0000 1,120 1,781 1,860 1,833 1,702 148 0 0
Hot water temperature (ฐF) ~ -- -- 107 107 109 108 104 114
Cold water temperature (ฐF) -- -- 94 86 88 87 85 112
Tower bottom temperature (ฐF) ~ 83 86 88 87 85 84
Fraction circulating water
that bypasses tower 1.0 1.0 1.0 1.0 0.46 0000 0.93 1.0 1.0
Dry fan power (10~3 ~~-) 6.66 7.11 10.79 24.48 26.33 26.33 26.33 26.33 26.33 26.33 11.58 7.11
/tw nr
Coolg tower fan pwr (10~3 ^~-) 0000 0.84 1.55 1.55 1.55 1.55 0.11 0 0
/cw nr
Circulating pump pwr (10~3 |^W~^r) 0 0 0 0 4.28 4.28 4.28 4.28 4.28 4.28 0 0
KW nr
Water evaporated (IbAw-hr) 0000 0.77 1.30 1.38 1.36 1.24 0.13 0 0
(continued)
-------
-J
tn
TABLE A7-9 (continued)
Design Condit-' ons : Fraction designed dry 0.95.
2- 2
Dry condenser area 2.238 ft /kw, wet condenser area 0.1003 ft /kw.
Cooling tower information: characteristic, KaY/L = 1.44, water/gas rates 1.45,
circulation rate 17.4 Ib/kw-hr, 0.0348 gpm/kw.
Month 123456789 10 11 12
Condenser temperature (ฐF)
Turbine heat rate (BtuAw~hr)
Total condenser load (Btu/kw-hr)
Dry condenser load (Btu/kw-hr)
Wet condenser load (Btu/kw-hr)
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower
-3 kw-hr
Dry fan power (10 , . )
KW nr
-3 kw-hr
CoolQ tower fan pwr (10 : )
kw-hr
-3 kw-hr
Circulating pump pwr (10 ~ ~
kw-nr
Water evaporated (Ib/kw-hr)
115
11,700
8,200
8,200
0
__
__
1.0
5.33
0
5 0
0
115 115
11,700 11,700
8,200 8,200
8,200 8,200
0 0
__
__
1.0 1.0
5.67 7.00
0 0
0 0
0 0
115 115
11,700 11,700
8,200 8,200
8,200 8,200
0 0
__
1.0 1.0
12.17 24.01
0 0
0 0
0 0
117
11,753
8,253
7,913
340
105
86
86
0
33.3
0.31
0.86
0.34
121
11,859
8,358
8,089
269
112
96
96
0
33.3
0.31
0.86
0.20
120
11,832
8,332
8,089
243
112
98
98
0
33.3
0.31
0.86
0.18
115 115
11,700 11,700
8,200 8,200
8,089 8,200
111 0
111
105
87
0.75 1.0
33.3 13.67
0.07 0
0.86 0
0.08 0
115 115
11,700 11,700
8,200 8,200
8,200 8,200
0 0
__
--
1.0 1.0
7.34 5.67
0 0
0 0
0 0
-------
CF>
TABLE A7-10. CALCULATIONS ON STEAM TURBINE CONDENSERS AT AKRON, OHIO
Design Conditions: Fraction designed dry 0.
Dry condenser area 0 ft /kw, wet condenser area 2.0069 ft /kw.
Cooling tower information: characteristic, KaY/L = 1.45, water/gas rates 1.41,
circulation rate 348 Ib/kw-hr, 0.696 gpm/kw.
Month 123456789 10 11 12
Condenser temperature (ฐF) 115 115 115 115 119 124 126 125 122 117 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,806 11,938 11,990 11,964 11,885 11,753 11,700 11,700
Total condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,200 8,306 8,437 8,490 8,464 8,385 8,253 8,200 8,200
Dry condenser load (Btu/kw-hr) 000000000000
Wet condenser load (BtuAw-hr) 8,200 8,200 8,200 8,200 8,306 8,437 8,490 8,464 8,385 8,253 8,200 8,200
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower
-3 kw-hr
Dry fan power (10 )
-3 kw-hr.
Coolg tower ran pwr (10 )
_ ,-, ซ-3 kw-hr,
101
77
62
0.38
0
3.84
17 19
101
77
63
0.37
0
3.90
17 19
101
77
75
0.08
0
5.69
17 17
101
77
77
0
0
6.19
17 19
105
81
81
0
0
6.19
17 19
109
85
85
0
0
6.19
17 19
111
87
87
0
0
6.19
17 19
110
86
86
0
0
6.19
17 19
108
83
83
0
0
6.19
17 19
103
79
79
0
0
6.19
17 19
101
77
74
0. 11
0
5.51
17.1?
101
77
65
0.33
0
4.15
17.12
Water evaporated (IbAw-hr) 5.12 5.09 5.12 5.33 5.81 5.81 6.00 6.09 5.93 5.57 5.19 5.08
(continued)
-------
TABLE A7-10 (continued)
Design Conditions: Fraction designed dry 0.25.
2 2
Dry condenser area 0.543 ft /kw, wet condenser area 1.5051 ft /kw.
Cooling tower information: characteristic, KaY/L = 1.45, water/gas rates 1.41,
circulation rate 261 Ib/kw-hr, 0.522 gpm/kw.
Month 1 2 3 4 5 6 7 8 9 10 11 12
Condenser temperature (ฐF) 115 115 115 115 115 122 125 124 120 115 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,700 11,885 11,964 11,938 11,832 11,700 11,700 11,700
Total condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,200 8,200 8,385 8,464 8,437 8,332 8,200 8,200 8,200
Dry condenser load (Btu/kw-hr)
Wet condenser load (Btu/kw-hr)
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower
-3 kw-hr
Dry fan power (10 , , )
J kw-hr
-3 kw-hr
Coolg tower fan pwr (10 )
kw-hr
~ 3 kw hr
Circulating pump pwr (10 )
kw nr
Water evaporated (Ib /kw-hr)
3,754
4,446
105
88
62
0.60
8.09
1.86
12, 8
2.83
3,712
4,488
105
87
63
0.57
8.09
2.00
12.8
2.03
3,328
4,873
104
85
76
0.39
8.09
2.84
12.8
3.10
2,901
5,299
103
83
77
0.23
8.09
3.58
12.8
3.71
2,389
5,811
102
79
79
0
8.09
4.65
12.8
4.14
2,304
6,080
108
85
85
0
8.09
4.65
12.8
4.39
2,261
6,203
111
87
87
0
8.09
4.65
12. 8
4.52
2,261
6,176
110
86
86
0
8.09
4.65
12.8
4.50
2,346
5,985
106
83
83
0
8.09
4.65
12.8
4.21
2,645
5,555
102
81
78
0. 13
8.09
4.05
12.8
4.90
3,200
5,001
103
84
75
0.32
8.09
3. 16
12.8
3.18
3,626
4,574
104
87
65
0.56
8.09
2.05
12.8
2.31
(continued)
-------
03
TABLE A7-10 (continued)
Design Conditions: Fraction designed dry 0.50.
Dry condenser area 1.0855 ft /kw, wet condenser area 1.0035 ft AW.
Cooling tower information: characteristic, KaY/L = 1.45, water/gas rates 1.41,
circulation rate 174 lb/kw-hr, 0.348 gpm/kw.
Month 1' 2 3 4 5 6 7 8 9 10 11 12
Condenser temperature (ฐF)
Turbine heat rate (Btu/kw-hr)
Total condenser load (BtuAw~hr)
Dry condenser load (Btu/kw~hr)
Wet condenser load (Btu/kw-hr)
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF)
Fraction circulating water
that bypasses tower
T-, ^ n ^~3 kw-hr ,
Dry fan power (10 1 , J
kw hr
,-,^~3 kw-hr ^
Coolg tower fan pwr (10 , )
, in~3 kw-hr.
Circulating pump pwr (10 : ; )
kw-hr
Water evaporated (lb/kw-hr)
115
11,700
8,200
7,506
694
113
109
62
0.92
16.17
0.25
8.56
0.45
115
11,700
8,200
7,420
779
112
108
63
0.92
16.17
0.25
8.56
0.46
115
11,700
8,200
6,653
1,547
110
101
78
0.72
16.17
0.87
8.56
0.98
115
11,700
8,200
5,800
2,400
107
93
79
0.50
16.17
1.55
8.56
1.55
115
11,700
8,200
4,776
3,424
103
84
81
0.14
16.17
2.67
8.56
2.39
120
11,832
8,332
4,435
3,897
107
84
84
0
16.17
3.10
8.56
2.81
124
11,938
8,437
4,435
4,002
110
87
87
0
16.17
3.10
8.56
2.92
123
11,911
8,411
4,435
3,976
109
86
86
0
16.17
3.10
8.56
2.88
118
11,780
8,279
4,520
3,759
105
83
83
0
16.17
3.10
8.56
2.68
115
11,700
8,200
5,288
2,912
105
88
80
0.32
16.17
2.11
8.56
2.00
115
11,700
8,200
6,397
1,803
109
99
78
0.68
16.17
0.99
8.56
1.16
115
11,700
8,200
7,250
950
112
107
65
0.89
16.17
0.34
8.56
0.63
(continued)
-------
TABLE A7-10 (continued)
Design Conditions: Fraction designed dry 0.75.
Dry condenser area 1,628 ft /kw, wet condenser area 0.5017 ft /kw.
Cooling tower information: characteristic, KaY/L = 1.45, water/gas rates 1.41,
circulation rate 87 Ib/kw-hr, 0.174 gpm/kw.
Month 123456789 10 11 12
Condenser temperature (ฐF) 115 115 115 115 115 118 122 121 115 115 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,700 11,780 11,885 11,859 11,700 11,700 11,700 11,700
Total condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,200 8,200 8,279 8,385 8,358 8,200 8,200 8,200 8,200
Dry condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,200 7,163 6,396 6,396 6,396 6,396 7,931 8,200 8,200
Wet condenser load (BtuAw-hr) 0000 1,037 1,883 1,989 1,962 1,804 270 0 0
Hot water temperature (ฐF) 108 105 108 107 103 113
Cold water temperature (ฐF) -- -- 96 83 85 85 82 110
Tower bottom temperature (ฐF) 82 83 85 85 82 82
Fraction circulating water
that bypasses tower 1.0 1.0 1.0 1.0 0.54 0000 0.90 1.0 1.0
Dry fan power (10~3 kw'hr) 4.90 5.12 8.25 17.39 24.3 24.3 24.3 24.3 24.3 24.3 9.95 5.60
1 kw-hr
Coolg tower fan pwr (10~3 ^W~hr) 0000 0.71 1.55 1.55 1.55 1.55 0.16 0 0
kw-nr
Circulating pump pwr (10~ r^~) 0000 4.28 4.2.8 4.28 4.26 4.28 4.28 0 0
Water e'/aporated (lb,/kw-hr) 0000 0.76 1.36 1.45 1.42 1.29 0.19 0 0
(continued)
-------
TABLE A7-10 (continued)
Design Conditions: Fraction designed dry 0.95.
Dry condenser area 2.062 ft AW, wet condenser area 0.1003 ft2Aw.
Cooling tower information: characteristic, KaY/L = 1.45, water/gas rates 1.41,
circulation rate 17.4 Ib/kw-hr, 0.0348
Month 123456789 10 11 12
Condenser temperature (ฐF) 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700
Total condenser load (Btu/kw-hr) 8,200 8,200
Dry condenser load (Btu/kw-hr) 8,200 8,200
co Wet condenser load (Btu/kw-hr) 0 0
o
Hot water temperature (ฐF)
Cold water temperature (ฐF)
Tower bottom temperature (ฐF) -
Fraction circulating water
that bypasses tower 1.0 1.0
_ -> ku-hr
n---r f - - - T T - ^- Mn i A Ac \ en
JJry fan power (iu , , ) 4.4D 4.3^
-3 kw-hr
Coolg tower fan pwr (10 ~ r~~) 0 0
,,,,-3 kw-hr,
Circulating pump pwr (10 ) 0 0
Water evaporated (IbAw-hr) 0 0
115 115 115 117
11,700 11,700 11,700 11,753
8,200 8,200 8,200 8,277
8,200 8,200 8,200 7,939
0 0 0 338
106
88
88
1.0 1.0 1.0 0
5.62 8.66 20.03 30.7
000 0.31
0 0 0 0.86
000 0.23
122
11,885
8,385
8,101
284
112
96
96
0
30.7
0.31
0.86
0.21
121
11,859
8,358
8,101
257
112
97
97
0
30.7
0.31
0.86
0.19
115 115 115
11,700 11,700 11,700
8,200 8,200 8,200
8,101 8,200 8,200
99 0 0
112
106
85
0.78 1.0 1.0
6.75 12.60 6.27
0.07 0 0
0.86 0 0
0.07 0 0
115
11,700
8,200
3,200
0
--
1.0
4.67
0
0
0
-------
TABLE A7-11. SUMMARY OF WET/DRY CONDENSER COOLING CALCULATIONS
Farmington, New Mexico
Fraction designed dry 0.95 0.75 0.50 0.25 0
Dry condenser area ft.2/ku 2.92 2.31 1.54 0.77 0
Wet condenser area ft AW 0.100 0.50 1.00 1.51 2.01
Circulation rate gpmAw 0.0348 0.174 0.348 0.52 0.696
Avg fuel penalty BtuAw-hr 0 0 4.417 41.833 158.42
Avg fan ฃ pucip energy kw-hrAw-hr 0.012 0.016 0.023 0.027 0.023
Avg water consumption galAw-hr 0* 0.014 0.101 0.374 0.707
Casper, Wyoming
Fraction designed dry 0.95 0.75 0.50 0.25 0
Dry condenser area ft2 AW 2.77 2.19 1.46 0.728 0
Wet condenser area ft2Aw 0.100 0.50 1.00 1.51 2.01
Circulation rate gpmAw 0.0348 0.174 0.348 0.522 0.696
Avg fuel penalty BtuAw-hr 0 00 35.33 193.58
Avg fan 6 pump energy kw-hrAw-hr 0.010 0.014 0.021 0.027 0.023
Avg water consumption galAw-hr 0* 0.008 0.088 0.362 0.701
Charleston., West Virginia
Fraction designed dry 0.95 0.75 0.50 0.25 0
Dry condenser area ft AW 2.24 1.77 1.18 0.59 0
Wet condenser area ft2AW 0.10 0.50 1.00 1.51 2.01
Circulation rate gpmAw 0.0348 0.174 0.348 0.522 0.696
Avg fuel penalty BtuAw-hr 28.58 37.58 61.67 88.08 131.83
Avg fan C pump energy kw-hrAw-hr 0.018 0.022 0.028 0.025 0.023
Avg water consumption galAw-hr 0.008 0.062 0.215 0.448 0.681
Akron, Ohio
Fraction designed dry 0.95 0.75 0.50 0.25 0
Dry condenser area ft Aw 2.06 1.63 1.09 0.54 0
Wet condenser area ft AW 0.10 0.50 1.00 1.51 2.01
Circulation rate gpmAw 0.0348 0.174 0.348 0.522 0.696
Avg fuel penalty BtuAw-hr 33.08 35.33 55.08 68.25 94.67
Avg fan 6 pump energy kw-hrAw-hr 0.014 0.019 0.027 0.024 0.023
Avg water consumption galAw-hr 0.007 0.065 0.209 0.438 0.66
*Less than 0.001.
181
-------
TABLE A7-12. ANNUAL AVERAGE COSTS FOR WET/DRY CONDENSER COOLING
Farmington, New Mexico
Fraction designed dry
Dry condenser cost C/Vw-hr
Wet condenser cost
Electric energy C
Fuel penalty t/kv-
Cooling tower
Total C/kw-hr
Avg water consumption gal/kw-hr
Fraction designed dry
Dry condenser cost C/k^-hr
Wet condenser cost C/kv-hr
Electric energy t/kw-hr
Fuel penalty
-------
TABLE A7-13. SUMMARY OF WET/DRY COMPRESSOR INTERSTAGE
COOLING FOR AIR COMPRESSORS AT FARMINGTON,
N.M., WITH WET COOLER OFF FOR MONTHS 1, 2,
3, 11, AND 12
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, ฐF 160
2
Dry cooler area, ft /1000 Ib/hr 40.059
Wet cooler area, ft2/1000 Ib/hr 83.853
Circulation Rate, gpm/1000 Ib/hr 3.046
Avg, fan & pump energy, kw-hr/1000 Ib 0.509
Compression energy, kw-hr/1000 Ib 28.140
Water consumed, gal/1000 Ib 1.367
183
-------
TABLE A7-14. ANNUAL AVERAGE COST FOR WET/DRY
COMPRESSOR INTERSTAGE COOLING FOR
AIR COMPRESSOR AT FARMINGTON, N.M,
WITH WET COOLER OFF FOR MONTHS 1,
2, 3, 11, AND 12
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, ฐF 160
Dry cooler cost, C/1000 Ib 2.140
Wet cooler cost, C/1000 Ib 2.636
Tower cost, C/1000 Ib 0.131
Fan and pump energy, C/1000 Ib 1.018
Compression energy cost, C/1000 Ib 59.263
Total, C/1000 Ib compressed 65.188
Water consumed, gal/1000 Ib 1.367
184
-------
TABLE A7-15. CALCULATIONS ON INTERSTAGE COOLING OF AN AIR COMPRESSOR HANDLING 1000 LB AIR/HR AT FARMINGTON, N.M.
CO
Ln
Desi
gn intermediate temperature T ซ" 140ฐF
q_n_ ft2/1000 Ib
ft2/1000 Ib
AD,1 D 29.306 Aw/1 =
AD|2 ~ 16.147 AWj2 -
AD'3 = 13.027 t
Total: 58.480
Month
T,
1,0
Tx,l
T2,i
T
2,0
T
X,2
T, .
3,1
T,
3,0
T
X,3
Tair
t (avg)
c
th (avg)
QW1
QW2
QW3
Total Qw
il air fan energy
-------
TABLE A7-15. (Fartnington, N.M.) Continued
Design intermediate temperature T - 160'Fป Fraction dry load - 0.638
CD
CTi
Design ft /1000 Ib
AD,1 " 19.688
ADi2 - 11.26
An'-i = 9.111
Total: 40.059
Month
Tl,o
T
T2 i
T2,o
T
X,2
T .
T
3 ,o
T
X,3
air
t (avg)
c
th (avg)
QW1
CW2
QW3
Total Qw
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
x
ft2/1000 Ib
Aw,l
AW,2 "
AW,3 '
1
146.
80
62
191
93
68
199
97
67
59
70
4338
6025
7230
17593
0.449
0.027
0.075
26.743
1.147
39.61
23.767
20.476
83.853
2
5 155.
88
68
199
101
75
208
104
73
64
75
4820
6266
7471
18557
0.449
0.027
0.075
27.091
1.302
lb/1000 Ib gpm/1000
RL,1 " 491.64 R
RL,2 " 491.64 R
RT.rl - 539.84 R
1523.12
3 4
3 166.4 175.2
98 106
75 78
208 211
110 115
80 84
214 219
112 118
78 82
72| 72
'
86 86
5543 6748
7230 7471
8194 8676
20967 22895
0.449 0.449
0.027 0.027
0.075 0.075
27.457 27.701
1.613 1.880
C,l " ฐ-
G,2 ฐ 0.
G 3 " 1-
3.
5
189.0
118
87
223
127
91
228
126
87
79
96
7471
8676
9399
25546
0.449
0.027
0.075
28.171
2.242
Ib
983 Qw,l
983 Qw,2
080 Qw(3
046
6
201.4
129
94
231
136
96
234
137
93
84
102
8435
9640
10604
28679
0.449
0.027
0.075
28.554
2.639
" 12,291 Cooling Tower Characteriutic
- 12,291 KaY/L - 1.24
13'496 Water/Gas Rate in Tower
38,078 R,/I
Li
7
208.9
136
98
236
141
101
240
143
98
88
107
9158
9833
10648
29839
0.449
0.027
0.075
28.815
2.760
8
205.2
132
96
234
139
99
238
140
96
86
105
8676
9640
10604
28920
0.449
0.027
0.075
28.693
2.674
VA - 2.12
9
194.0
122
90
226
130
93
230
132
90
81
98
7712
8917
10122
26751
0.449
0.027
0.075
28.327
2.372
10
178.0
108
82
216
118
88
224
122
85
76
90
6266
7230
8917
22413
0.449
0.027
0.075
27.875
1.837
11
162.8
95
73
205
107
78
211
109
77
66
80
5302
6989
7712
20003
0.449
0.027
0.075
27.335
1.475
12
147.8
81
63
193
95
69
200
98
68
60
70
4338
6266
7230
17834
0.449
0.027
0.075
26.795
1.207
(continued)
-------
TABLE A7-15. (Farmington, H.M.) Continued
Intermediate temr.
ft2/1000 Ib
ADr i - 12.743 f
AQ'2 - 7.779 f
An' T - 6.297 t
'
Total: 26.819
Month
T,
1,0
T
X, 1
T2,i
T
2 ,o
T
X.2
T
T
3,0
T
X,3
T ,
air
t ( avg )
c
t (avg)
''til
'\a
^W3
'al ^H
iir fan energy
ir/1000 Ib)
:an energy
ir/1000 Ib)
ition pump energy
ir/1000 Ib)
i si on energy
ir/1000 Ib)
.onsumed
'1000 Ib)
w,l
6.091 RL<2 - 684.44 PQ] 2 - 1.369 Qy _2
1.647 R/i - 732.64 Rr\ - 1.465 Qw'-,
91.123
1
146.5
98
63
193
116
73
205
122
71
59
73
8435
10363
12291
31089
0.300
0.037
0.103
26.847
2.106
2
155.3
106
67
198
122
77
210
128
75
66
82
9399
10845
12773
33017
0.300
0.037
0.103
27.109
2.416
r
2101.52
3 4
166.4 175.2
116 124
70 82
211 216
133 139
84 87
219 223
137 143
82 84
72 74
87 91
9158 10122
11809 12532
13255 14219
34222 36873
0.300 0.300
0.037 0.037
0.103 0.103
27.579 27.823
2.654 3.070
'
4.203
5
189.0
137
90
226
149
94
231
152
91
.81
100
11327
13255
14701
39283
0.300
0.037
0.103
28.275
3.463
6
201.4
148
96
234
158
98
236
159
94
85
105
12532
14460
15665
42657
0.300
0.037
0.103
28.623
3.891
- 17,11
- 17.11
- 18,31
1 Cool
1 Ka'//
Wate
52,538 P-. /P.
Lt
i
208.9
155
100
239
164
102
241
165
99
88
110
13255
14942
15906
44103
0.300
0.037
0.103
28.867
4.165
8
205,2
152
98
236
161
101
240
163
97
87
108
13014
14460
15906
43380
0.300
0.037
0.103
28.763
4.046
ing Tower CharocteriBtic
L - 1.24
r/Gas P^te in Tower
A - 2'12
9
194.0
142
92
229
153
96
234
156
92
83
101
12050
13737
15424
41211
0.300
0.037
0.103
28.414
3.665
10
178.0
127
87
223
144
90
226
145
86
73
89
9640
13014
14219
36873
0.300
0.037
0.103
27.997
3.035
11
162.8
113
77
210
131
84
219
136
82
71
86
8676
11327
13014
33017
0.300
0.037
0.103
27. 509
2.511
12
147.8
99
63
193
116
73
205
123
72
59
73
8676
10363
12291
31330
0.300
0.037
0.103
26.665
2.142
(continued)
-------
TABLE A7-15. (Farmington, N.M.) Continued
Design intermediate temperature T all wet
CO
CO
Design ft /1000 lb
AD,1 " ฐ
AD,2 ฐ ฐ
AD,3 " ฐ
Total: 0
Month
T,
1,0
T
T .
2,1
T
2,o
TX,2
T3,i
T
3,0
T
X,3
T .
air
t (avg)
c
t (avg)
QW1
QW2
QW3
Total Q
Total air fan energy
(kw-hr/1000 lb)
Tower fan energy
(kw-hr/1000 lb)
Circulation pump energy
(kw-hr/1000 lb)
Compression energy
(kw-hr/1000 lb)
Water consumed
ft2/!
Aw,i
AW,2 '
AW,3 '
1
146.
147
72
204
204
84
219
219
82
66
85
18075
28920
33017
80012
0
0.066
0.183
27.196
5.837
x.
000 lb
51.365 F
30.820 F
24.375 F
106.560
2
5 155.3
155
77
210
210
89
225
225
87
71
91
18798
29161
33258
81217
0
0.066
0.183
27.492
6.216
lb/1000
1L,1 " 1.
1L,2 l:
1L,3 ' 1
lb gpm/1000 lb
224.28 R- i - 2.449 Qw,l
224.28 R j - 2.449 fy 2
272.48 R , - 2.545 ft, -,
C
3721.04
3
166.4
166
83
218
218
95
233
233
93
77
97
20003
29643
33740
83386
0
0.066
0.183
27.857
6.616
4
175.2
175
86
221
221
98
236
236
95
79
100
21449
29643
33981
85073
0
0.066
0.183
28.084
7.101
jf -*
7.443
5
189.0
189
93
230
230
102
241
241
99
84
106
23136
30848
34222
88206
0
0.066
0.183
28.467
7.796
6
201.4
201
97
235
235
104
244
244
101
86
109
25064
31571
34463
91098
0
0.066
0.183
28.745
8.323
30,607 Cooling Tower Characteristic
- 30,607 KaY/L - 1.24
" 31,812 Water/Ga3 Rate in Tower
93,026 RL/F
7
208.9
209
102
241
241
108
249
249
103
90
114
25787
32053
35186
93026
0
0.066
0.183
29.006
8.639
8
205.2
205
100
239
239
107
248
248
103
89
113
25305
31812
34945
92062
0
0.066
0.183
28.902
8.471
Lft - 2.12
9
194.0
194
95
233
233
103
243
243
100
85
108
23859
31330
34463
89652
0
0.066
0.183
28.589
7.902
10
178.0
178
90
226
226
101
240
240
98
83
103
21208
30125
34222
85555
0
0.066
0.183
28.240
7.206
11
162.8
163
81
215
215
94
231
231
92
75
95
19762
29161
33499
82422
0
0.066
0.183
27.753
6.532
12
147.8
148
73
205
205
85
220
220
83
67
86
18075
28920
33017
80012
0
0.066
0.183
27.248
5.942
(gal/1000 lb)
-------
TABLE A7-16. CALCULATIONS ON INTERSTAGE COOLING OF AN AIR COMPRESSOR HANDLING 1000 LBS AIR/KR AT CASPER, WYOMING
Design intermediate temperature T - 140ฐF
CD
Design ฃt2/1000 Ib
ft2/1000 Ib lb/1000 Ib gpm/1000
AD,1 ' 28.156 AW(1 -
AD 2 - 14.334 A
AP/T ซ 11.572 A
Total-. 54.052
Month
T
1,0
Tx,l
T2,i
T2,o
TX,2
T3,i
T.
3,0
T
X,3
T .
air
t (avg)
c
th (avg)
Q
Q
Q
Total Q
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
W,2 '
W,3 "
1
34.914 RL
20.948 RL
19.506 R,
75.368
2
144.0 146.5
62
55
183
75
62
191
77
77
54
61
1687
3133
0
4820
0.605
0.011
0.029
Compression energy 26.482
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
0.304
64
57
185
77
64
194
80
80
56
63
1687
3133
0
4820
0.605
0.011
0.029
1 - 298
2 - 298
,3 " 347
944
3
154.0
71
64
194
84
70
201
86
86
60
68
1687
3374
0
.84 R ! - 0.
.84 R j " 0.
.04 R
.72
4
165.2
80
70
201
92
77
210
95
76
67
77
2410
3615
4579
5061 10604
0.605
0.011
0.029
0.605
0.017
0.046
26.586 26.917 27.300
0.314
0.354
0.810
Ib
599 Qw,l - 7471
598 Qyj ^
, - 0.694 Qu ,
1.
5
890
6
181.5 195.2
95
81
215
105
87
223
108
85
76
89
3374
4338
5543
13255
0.605
0.017
0.046
27.892
1.134
106
89
225
116
95
233
119
93
82
98
4097
5061
6266
15424
0.605
0.017
0.046
28.362
1.392
, - 7471
| 8676
23,618
7
202.7
113
93
230
122
99
238
124
96
85
102
4820
5543
6748
17111
0.605
0.017
0.046
28.606
1.580
Cooling Tower Characteristic
KaY/Z, - 1.17
Water/Gas Rate in Tower
R /R - 2.24
L A
8 9
201.4 187.7
112 100
92 83
229 218
121 110
98 89
237 225
123 112
95 87
84 76
101 92
4820 4097
5543 5061
6748 6025
17111 15183
0.605 0.605
0.017 0.017
0.046 0.046
28.554 28.049
1.570 1.327
10
172.7
87
75
208
98
82
216
'101
81
70
83
2892
3856
4820
11568
0.605
0.017
0.046
27.579
0.927
11
154.0
71
64
194
84
70
201
86
86
60
68
1687
3374
0
5061
0.605
0.011
0.029
26.917
0.354
12
151.5
69
61
190
81
68
199
84
84
59
68
1928
3133
0
5061
0.605
0.011
0.029
26.795
0.349
(continued)
-------
TABLE A7-16. (Casper, Wyoming) Continued
ID
O
Design intermediate temperature T 160ฐF
Design ft2/1000 Ib
AD,1 " 18.890
AD/2 " 11.037
An -, - 9.396
Totals 39.323
Month
T
1,0
Tx,l
T2,i
T
2,0
T
X,2
T
T,
3,0
T
X,3
T .
air
t (avg)
c
th (avg)
Qwl
Qw2
Q
Total Qw
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
ft /1000 Ib lb/1000 Ib gpm/1000 Ib
AW,1 39.612 RL,,! " 491.64 RG/I - 0.983 Ow,l
AW,2 " 23.767 RL,2 " 491.64 Rf.i2 - 0.983 Qw,2
AW,3 "
1
144.
80
61
190
93
67
198
93
64
57
68
4579
6266
6989
17834
0.440
0.027
0.075
26.67
1.151
12,291 Cooling Tower Characteristic
- 12,291 KaY/L - 1.17
20.476 RL.3 - 539.84 R,,., " 1.080 Ow.3 ' 13,496 ,_,,,-.., 0 = ^ Tn.r-
83.855
2
0 146.5
82
63
193
95
69
200
95
66
59
70
4579
6266
6989
17834
0.440
0.027
0.075
26.78
1.216
1523.12 3.046
3
154.0
89
69
200
102
75
208
102
72
65
1
76
4820
6507
7230
18557
0.440
0.027
0.075
27.09
1.314
4
165.2
99
76
209
111
82
216
110
79
71
84
5543
6989
7471
20003
0.440
0.027
0.075
27.49
1.535
5
181.5
113
85
220
123
89
225
122
86
77
93
6748
8194
8676
23618
0.440
0.027
0.075
28.00
2.000
6
195.2
125
93
230
134
96
234
130
91
84
101
7712
9158
9399
26269
0.440
0.027
0.075
28.45
2.343
38,078 RL/Rfl "2.24
7
202.7
132
96
234
139
100
239
138
96
86
105
8676
9399
10122
28197
0.440
0.027
0.075
28.68
2.571
8
201.4
131
95
233
138
99
238
137
95
86
104
8676
9399
10122
28197
0.440
0.027
0.075
28.62
2.563
9
187.7
119
86
221
126
89
225
125
86
77
93
7953
8917
9399
26269
0.440
0.027
0.075
28.10
2.367
10
172.7
105
80
214
116
85
220
116
82
74
88
6025
7471
8194
21690
0.440
0.027
0.075
27.72
1.755
11
134.0
89
69
200
102
75
208
102
72
65
76
4820
6507
7230
18557
0.440
0.027
0.075
27.09
1.314
12
151.5
86
66
196
99
72
204
99
69
62
74
4820
6507
7230
18557
0.440
0.027
0.075
26.95
1.224
(cbntinued)
-------
Design ft2/1000 Ib
AD(1 ซ 12.254 P.
AD'2 - 6.255 P
An'-, = 5.068 P
U r J
Total: 23.577
Month
T
1,0
T .
T
2,i
T
2,0
T
X,2
T3,i
T,
3,0
T
X,3
T .
air
t (avg)
c
th (avg)
QW1
Qw2
CW3
Total Qw
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
ft2/ioo
>W,1 * ^
LW 2 " 2
iw'3 " 2
Jt
0 Ib lb/1000 Ib gpm/1000 Ib
3.485 RL,i - 684.44 R, ( i - 1.369 Qvi,l
6.091 RL(2 - 684.44 RQ, 2 " 1-369 Qy^
1.647 Rj.'-, ป 732.64 R, ' , ** 1.465 Qj/,
91.123
1
144.0
97
65
195
128
75
208
136
73
61
76
7712
12773
15183
35668
0.264
0.037
0.103
26.882
2.489
2
146.5
100
67
198
131
76
209
137
74
62
78
7953
13255
15183
36391
0.264
0.037
0.103
26.969
2.590
2101.52
3
154.0
106
77
210
140
85
220
146
83
68
83
6989
13255
15183
35427
0.264
0.037
0.103
27.405
2.658
4
165.2
116
80
214
146
91
228
155
90
75
92
8676
13255
15665
37596
0.264
0.037
0.103
27.718
2.951
*
4.203
5
181.5
132
88
224
158
97
235
164
94
81
100
10604
14701
16870
42175
0.264
0.037
0.103
28.188
3.593
6
195.2
144
95
233
167
102
241
172
99
86
'106
11809
15665
17593
45067
0.264
0.037
0.103
28.589
4.010
" 17,111 Cooling Tower Characteristic
. - 17,111 KaY/L - 1.17
I L Water/Gas Rate in Tower
52,538 R /R - 2.24
7 B
202.7 201.4
151 150
98 97
236 235
171 170
104 103
244 243
176 175
101 100
88 87
109 108
12773 12773
16147 16147
18075 18075
46995 46995
0.264 0.264
0.037 0.037
0.103 0.103
28.780 28.728
4.336 4.302
9
187.7
137
90
226
161
97
235
166
94
81
101
11327
15424
17352
44103
0.264
0,037
0.103
28.310
3.829
10
172.7
124
84
219
146
92
229
158
91
78
95
9640
13014
16147
38801
0.264
0,037
0,103
27.910
3.176
11
154.0
106
77
210
140
85
220
146
83
68
83
6989
13255
15183
35427
0.264
0.037
0.103
27.405
2.658
12
151.5
104
71
203
135
80
214
142
78
66
82
7953
13255
15424
36632
0.264
0.037
0.103
27.178
2.703
(continued)
-------
TABLE A7-16. (Cajper, Wyoming) Continued
Design intermediate temperature T all wet
Design ft /1000 Ib
AD,1 0
AD,2 - 0
AD,3 m ฐ
Total: 0
Month
T
1,0
Tx,i
T2,i
T_
2,O
? ,
X, 2
T
3 ,i
T,
3,0
T
X,3
T .
air
t (avg)
fc). (avg)
ฐW1
QW2
CW3
Total Qw
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
ft2/ioc
AW,1 " !
AW,2 " :
AW,3 ฐ ;
It
1
144.0
144
69
200
200
78
211
211
77
61
81
18075
29402
32294
79771
0
0.065
0.180
27.004
5.890
A
)0 Ib lb/1000 Ib gpm/1000 Ib
51.134 RL(1 - 1205.0 R i - 2.410 (?W(1
)0.681 RL(2 " 1205.0 R 2 - 2.410 Q^j
24.292 RT'T - 1253.2 Rฐ', - 2.506 &/ ,
36.107
2
146.5
147
73
205
205
83
218
218
82
66
86
17834
29402
32776
80012
0
0.065
0.180
27.196
5.949
3663.2 7.326
3
154.0
154
78
211
211
89
225
225
88
72
91
18316
29402
33017
80735
0
0.065
0.180
27.492
6.223
4
165.2
165
86
221
221
98
236
236
96
79
100
19039
29643
33740
82422
0
0.065
0.180
27.944
6.577
5
181.5
182
91
228
228
102
241'
241
100
83
105
21931
30366
33981
86278
0
0.065
0.180
28.327
7.362
6
195.2
195
98
236
236
106
246
246
102
88
111
23377
31330
34704
89411
0
0.065
0.180
28.710
7.951
- 30,125 Cooling Tower Characteristic
, - 30,125 KaY/L - 1.17
1 " ( Water/Gas Rate in Tower
91,580 R /R. " 2.24
7
202.7
203
100
239
239
108
249
249
104
90
113
24823
31571
34945
91339
0
0.065
0.180
28.885
8.285
L
8
201.4
201
99
238
238
107
248
248
103
89
112
24582
31571
34945
91098
0
0.065
0.180
28.832
8.245
A
9
187.7
188
95
233
233
106
246
246
102
87
109
22413
30607
34704
87724
0
0.065
0.180
28.554
7.657
10
172.7
173
88
224
224
99
238
238
97
81
102
20485
30125
33981
84591
0
0.065
0.180
28.101
7.028
11
154.0
154
78
211
211
89
225
225
88
72
91
18316
29402
33017
80735
0
0.065
0.180
27.492
6.223
12
151.5
152
76
209
209
85
220
220
84
69
88
18316
29884
32776
80976
0
0.065
0.180
27.352
6.184
(gal/1000 Ib)
-------
TABLE A7-17. CALCULATIONS ON INTERSTAGE COOLING OF AN AIR COMPRESSOR HANDLING 1000 LBS/HR AT CHARLESTON, W.VA.
Design intermediate temperature T 140ฐF
Design ft2/1000 Ib
AD(1 - 23.206
AD 2 - 11.811
A ', - 9.579
Total: 44.596
Month
T
1,0
Tx i
T
2,i
T
2,0
T
X,2
T
3,i
T
3,0
T
X,3
T .
air
tc (avg)
th (avg)
Qwl
QW2
QW3
Total Qw
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
A
ft2/1000 Ib
AW,1 "
AW,2 "
AW,3 ฐ
1
34.914
20.948
19.506
75.368
2
159.0 161.
84
69
200
100
78
211
104
76
65
79
3615
5302
6748
15665
0.499
P. 017
86
70
201
102
80
214
107
78
66
81
3856
5302
6989
16147
0.499
0.017
lb/1000 Ib gpm/1000
RL;1 - 298
RL 2 - 298
RL 3 - 347
944
3
5 170.2
94
76
209
109
85
220
113
82
70
87
4338
5784
7471
.84 R
.84 R
.04 R
.72
4
182.7
105
84
219
119
91
228
122
88
75
95
5061
6748
8194
17593 20003
0.499
0.017
0.499
0.017
6,1 - ฐ-
62 - 0.
03 ' ฐ-
U( j
1.
5
Ib
598 Qytl
598 Qw' 2
694 a,'
*H , J
890
6
194.0 203.9
115
92
229
128
98
236
131
94
82
103
5543
7230
8917
21690
0.499
0.017
123
98
236
136
102
241
138
100
86
108
6025
8194
9158
23377
0.499
0.017
- 7471
- 7471
. 8676
23,618
7
207.7
127
100
239
139
106
246
142
102
89
113
6507
7953
9640
24100
0.499
0.017
Cooling Tower Characteristic
KaY/L - 1.44
Water/Gas Rate in Tower
RL/RA - 1.45
8 9
206.4 200.2
125 120
99 95
238 233
138 133
105 102
245 241
141 136
101 98
88 85
112 107
6266 6025
7953 7471
9640 9158
23859 22654
0.499 0.499
0.017 0.017
10
185.2
107
86
221
121
93
230
124
90
78
97
5061
6748
8194
20003
0.499
0.017
11
171.5
95
77
210
110
86
221
114
84
71
88
4338
5784
7230
17352
0.499
0.017
12
161.5
86
70
201
102
80
214
107
78
66
81
3856
5302
6989
16147
0.499
0.017
(kw-hr/1000 Ib)
Circulation pump energy 0.046
(kw-hr/1000 Ib)
Compression energy 27.213
(kw-hr/1000 Ib)
Water consumed 1.103
(gal/1000 Ib)
0.046 0.046 0.046 0.046 0.046 0.046 0.046 0.046 0.046 0.046 0.046
27.300 27.614 28.031 28.449 28.763 28.919 28.867 28.658. 28.136 27.666 27.300
1.134 1.267 1.666 1.869 2.073 2.151 2.135 1.987 1.650 1.330 1.134
(continued)
-------
TABLE A7-17. (Charleston, W. Va.) Continued
Design intermediate temperature T.. " 160T
Design ft2/1000 Ib
AD,1 ' 15.307
AD/'2 - 7.818
Ap , = 6.337
'
Total: 29.462
Month
T,
1,0
Tx,l
T2,i
T
2,0
T
X,2
T3,i
T
3,0
T
X,3
T
air
t (avg)
c
th (avg)
Q
CW
0
VW3
Total 0
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
ft2/H
AH,1 "
AW,2 "
AW,3 "
1
159.
102
72
204
126
82
216
133
81
66
84
7230
10604
12532
30366
0.330
0.027
0.075
27.335
2.180
A
000 Ib lb/1000 Ib gpm/1000 Ib
39.612 RL/1 - 491.64 RG| ]_ - 0.983 Qw,l
23.767 RL(2 - 491.64 RG( 2 - 0.983 Ow,2
20.476 RT._, ซ 539.84 Rr. , - 1.080 Qu i
83.855
2
0 161.5
105
74
206
128
84
219
135
82
68
86
7471
10604
12773
30848
0.330
0.027
0.075
27.439
2.232
1523.12
3
170.2
112
78
211
134
88
224
141
86
71,
I
91
8194
11086
13255
32535
0.330
0.027
0.075
27.701
2.522
4
182.7
124
86
220
144
93
230
149
90
77
98
9158
12291
14219
35668
0.330
0.027
0.075
28.101
2.938
3.046
5
194.0
134
94
231
154
101
290
158
96
84
107
9640
12773
14942
37355
0.330
0.027
0.075
28.536
3.203
6
203.9
143
99
238
161
105
245
165
101
87
112
10604
13496
15424
39524
0.330
0.027
0.075
28.832
3.493
" 12,291 Cooling Tower Characteristic
- 12,291 KaY/L "1.44
" 13f496 Water/Gas Rate in Tower
38.078 RL/P
7
207.7
146
101
240
164
107
248
168
102
89
114
10645
13737
19280
43862
0.330
0.027
0.075
28.954
3.909
8
206.4
145
100
239
163
106
246
166
102
88
113
10845
13737
15424
40006
0.330
0.027
0.075
28.902
3.569
* ' 1-45
9
200.2
139
96
234
158
104
244
163
100
85
109
10363
13014
15183
38560
0.330
0.027
0.075
28.710
3.064
10
185.2
126
88
224
147
96
234
152
93
79
101
9158
12291
14219
35668
0.330
0.027
0.075
28.223
2.963
11 12
171.5 161.5
114 105
79 74
213 206
136 128
90 84
226 219
143 135
88 82
72 68
92 86
8435 7471
11086 10604
13255 12773
32776 30848
0.330 0.330
0.027 0.027
0.075 0.075
27.770 27.439
2.522 2.232
(continued)
-------
kO
Ul
TABLE A7-17. (Charleston, W. Va.) Continued
Design intermediate temperature T - 180ฐF
ft2/1000 Ib ft2/1000 Ib
AD,1 ' 9.381 AW(1 -
AD,2 " 4-788 Aw 2 "
AD'3 - 3.880 Aw'(3 -
Total: 18.049
Month 1
43.485
26.091
21.647
91.123
2
TX Q 159.0 161.
TX 1 12ฐ
T2!i 75
T2,o 208
TX,2 154
T3 i 86
T3!o m
TX,3 163
T . 84
air
t (avg) 68
t (avg) 88
Q 10845
VW1
Q 16388
Q 19039
:al Q 46272
lir fan energy 0.202
vr/1000 Ib)
:an energy 0.037
ir/1000 Ib)
ition pump energy 0.103
ir/1000 Ib)
ision energy 27.457
ir/1000 Ib)
:onsumed 3.393
123
77
210
156
87
223
165
85
70
89
11086
16629
19280
46995
0.202
0.037
0.103
27.544
3.480
lb/1000
Ib gpm/1000
RL,1 " 684.44 RG
RL,2 " 684.44 RG
RL'3 - 732.64 RG
'
2101.52
3
5 170.2
130
81
215
161
91
228
170
89
73
89
11809
16870
19521
48200
0.202
0.037
0.103
27.805
3.741
4
182.7
143
87
223
170
96
234
177
93
77
100
13496
17834
20244
51574
0.202
0.037
0.103
28.171
4.280
,1 ' 1-
,2 ' i-
,3 " !
4.
5
Ib
369 Qw(1
369 Qw 2
465 {^'3
203
6
194.0 203.9
153
94
231
178
101
240
184
97
83
107
14219
18557
20967
53743
0.202
0.037
0.103
28.536
4.645
162
100
239
186
106
246
191
102
88
113
14942
19280
21449
55671
0.202
0.037
0.103
28.867
4.872
" 17,111 Cooling Tower Characteristic
17,111 KaY/L 1.44
18,316 water/Gas Rate in Tower
52,538 RL/RA " 1-45
7
207.7
166
102
241
189
108
249
194
103
89
115
15424
19521
21931
56876
0.202
0.037
0.103
28.989
5.080
8
206.4
164
101
240
188
107
248
193
102
89
114
15183
19521
21931
56635
0.202
0.037
0.103
28.936
5.063
9
200.2
159
98
236
183
105
245
189
100
87
111
14701
18798
21449
54948
0.202
0.037
0.103
28.763
4.837
10
185.2
145
89
225
172
98
236
179
94
80
103
13496
17834
20485
51815
0.202
0.037
0.103
28.275
4.315
11
171.5
132
82
216
162
92
229
171
90
74
95
12050
16870
19521
48441
0.202
0.037
0.103
27.857
3.723
12
161.5
123
77
210
156
87
223
165
85
70
89
11086
16629
19280
46995
0.202
0.037
0.103
27.544
3.480
(gal/1000 Ib)
(continued)
-------
TABLE A7-17. (Charleston, H. Va.) Continued
Design intermediate temperature T ซ all wet
Design ft /1000 Ib
ADjl - 0 J
AD,2 ฐ ฐ J
AD,3 = ฐ '
Total: 0
Month
T,
1,0
T
T-, .
2,1
T
2,0
TX 2
T
3,i
T
3,0
T
X,3
T
air
t (avg)
c
t^ (avg)
QW1
QW2
QW3
Total Qw
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
ft2/ioc
ป,w/1 - 4
\H'2 - 2
S/3 ฐ 2
A
10 Ib lb/1000 Ib gpn/1000 Ib
9.812 RL,1 ' 1099.96 RG( ^ - 2.198 Qy,l
:9.887 RL'2 = 1098.96 RQ' 2 - 2.198 BW' 2
18.579 RT', - 1147.16 Rr.' , - 2.294 ft/,
108.278
1
159.0
159
77
210
210
88
224
224
82
69
91
19762
29402
34222
83386
0
0.060
0.165
27.527
6.204
2
161.5
162
78
211
211
89
225
225
83
70
93
20244
29402
34222
83868
0
0.060
0.165
27.596
6.287
'
3345.08
3
170.2
170
84
219
219
94
231
231
87
75
98
20726
30125
34704
85555
0
0.060
0.165
27.910
6.730
4
182.7
183
89
225
225
97
235
235
90
78
102
22654
30848
34945
88447
0
0.060
0.165
28.223
7.339
6.690
5
194.0
194
95
233
233
103
243
243
94
84
109
23859
31330
35909
91098
0
0.060
0.165
28.589
7.782
6
203.9
204
100
239
239
107
248
248
99
88
114
25064
31812
35909
92785
0
0.060
0.165
28.885
8.170
- 27,474 Cooling Tower Characteristic
- 27,474 KaY/L - 1.44
l Water/Gas Rate in Tower
83,627 RL/R
7
207.7
208
102
241
241
108
249
249
100
89
115
25546
32053
35909
93508
0
0.060
0.165
28.989
8.364
8
206.4
206
101
240
240
107
248
248
99
88
114
25305
32053
35909
93267
0
0.060
0.165
28.937
8.336
A'1'45
9
200.2
200
98
236
236
105
245
245
97
86
112
24582
31571
35668
91821
0
0.060
0.165
28.763
8.087
10
185.2
185
92
229
229
100
239
239
92
81
105
22413
31089
35427
88929
0
0.060
0.165
28.362
7.339
11
171.5
172
85
220
220
95
233
233
88
76
100
20967
30125
34945
86037
0
0.060
0.165
27.962
6.785
12
161.5
162
78
211
211
89
225
225
83
70
93
20244
29402
34222
83868
0
0.060
0.165
27.596
6.287
-------
TABLE A7-18. CALCULATIONS ON INTERSTAGE COOLING OF AN AIR COMPRESSOR HANDLING 1000 LBS AIR/ AT AKRON, OHIO
Design intermediate temperature T
140ฐF
Design ft2/1000 Ib
AD|1 - 21.231
AD|2 10.854
AH'T = 8.763
L* , J
Totali 40.848
Month
T
I/O
T
T
2,i
T
2,o
T
X, 2
T
T
3,0
T -,
X,3
T
air
t (avg)
c
th (avg)
QW1
QH2
QW3
Total Qw
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
ft2/10i
A^j j_ ra ,
AW,2 " :
AW,3
30 Ib
34.914
20.948
L9.506
75.368
1
147.8
78
61
190
96
71
203
101
69
56
73
4097
6025
7712
17834
0.457
0.017
Circulation pump energy 0.046
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
26.795
1.038
2
149.0
79
63
193
98
73
205
103
72
58
74
3856
6025
7471
17352
0.457
0.017
0.046
26.882
1.030
lb/1000
RL,l 2
RL,2 - 2
RL,3 " 3
Ib gpm/1000
98.84 RG,i - 0.
98.84 RG'2 - 0.
47.04 Rrt', - 0.
944.72
3
160.3
89
72
204
107
82
216
113
81
67
84
4097
6025
7712
17834
0.457
0.017
0.046
27.352
1.231
4
172.7
100
80
214
117
89
225
122
87
73
92
4820
6748
8435
20003
0.457
0.017
0.046
27.788
1.544
1.
5
187.7
113
89
225
129
97
235
133
94
79
102
5784
7712
9399
22895
0.457
0.017
0.046
28.293
1.914
Ib
598 S?w,l - 7471
598 Qwj2 " 7471
694 Cv/3 - 8676
f
890 23,618
6 7
198.9 203.9
123 128
96 100
234 239
138 142
103 107
243 248
142 146
99 102
84 88
109 114
6507 6748
8435 8435
10363 10604
25305 25787
0.457 0.457
0.017 0.017
0.046 0.046
28.676 28.885
2.172 2.276
Cooling Tow
KaY/L -1.4
Water/Gas P
ปer Characteristic
5
late in Tower
RL/RA - 1.41
8
202.7
127
99
238
141
106
246
145
101
87
113
6748
8435
10604
25787
0.457
0.017
0.046
28.832
2.252
9
195.2
120
94
231
135
101
240
139
98
83
107
6266
8194
9881
24341
0.457
0.017
0.046
28.258
2.083
10
180.2
107
85
220
123
93
230
128
90
76
97
5302
7230
9158
21690
0.457
0.017
0.046
28.049
1.745
11
164.0
92
74
206
110
84
219
116
82
68
86
4338
6266
8194
18798
0.457
0.017
0.046
27.788
1.375
12
151.5
81
64
194
99
74
206
104
73
60
75
4097
6025
7471
17593
0.457
0.017
0.046
26.952
0.997
(continued)
-------
TABLE A7-18. (Akron, Ohio) Continued
Design intermediate temperature T_. ป 160ฐF
TO
Design ft2/1000 lb ft2/1000 lb lb/1000 lb gpm/1000 lb
AD,1 ' 13.813 Aw>1 - 39.612 RL,1 - 491.64 RO,! 0.983 Cw,l " 12,291 Cooling Tower Characteristic
AD,2 " 7.085 AW(2 = 23.767 RL/2 - 491.64 RG,2 " 0.983 Qw,2 " 12,291 KaY/L - 1.45
AD(1 - 5.718 Aw ., - 20.476 RT..-, " 539.84 RG'. , - 1.080 Qw.l - 13,496 ,.,__,,. ,.. 4 nv,.
Total: 26.616
Month
T,
1,0
T
T2 i
T
2,o
TX,2
T
3,i
T
3,o
T
X,3
T .
air
t (avg)
th (avg)
Q
Qw2
QW3
Total Q
Total air fan energy
(kw-hr/1000 lb)
Tower fan energy
(kw-hr/1000 lb)
Circulation pump energy
(kw-hr/1000 -lb)
Compression energy
(kw-hr/1000 lb)
Water consumed
(gal/1000 lb)
83.855
1
147.8
96
64
194
122
74
206
129
72
57
76
7712
11568
13737
33017
0.298
0.027
0.075
26.900
1.971
2
149.0
97
65
195
123
76
209
131
74
59
78
7712
11327
13737
32776
0.298
0.027
0.075
26.969
1.997
1523.12
3
160.3
107
76
209
135
87
223
143
85
70
89
7471
11568
13978
33017
0.298
0.027
0.075
27.509
2.360
4
172.7
119
82
216
143
92
229
151
89
74
95
8917
12291
14942
36150
0.298
0.027
0.075
27.875
2.853
3.046
5
187.7
133
91
228
155
99
238
161
96
80
104
10122
13496
15665
39283
0.298
0.027
0.075
28.362
3.281
6
198.9
143
97
235
163
104
244
168
100
85
111
11086
14219
16388
41693
0.298
0.027
0.075
28.710
3.618
38,078 RI/RA " 1'41
7
203.9
147
100
239
167
107
248
173
103
88
114
11327
14460
16870
42657
0.298
0.027
0.075
28.885
3.774
8
202.7
146 '
99
238
166
106
246
171
102
87
113
11327
14460
16629
42416
0.298
0.027
0.075
28.832
3.761
9
195.2
139
95
233
161
103
243
167
99
84
109
10604
13978
16388
40970
0.298
0.027
0.075
28.606
3.501
10
180.2
126
87
223
150
96
234
156
93
78
101
9399
13014
15183
37596
0.298
0.027
0.075
28.136
3.060
11 12
164.0 151.5
111 100
77 68
210 199
137 126
88 79
224 213
145 135
85 77
70 62
91 81
8194 7712
11809 11327
14460 13978
34463 33017
0.298 0.298
0.027 0.027
0.075 0.075
27.596 27.109
2.542 1.971
(continued)
-------
TABLE A7-18. (Akron, Ohio) Continued
Design intermediate temperature T ป 180ฐF
2 2
Design ft /1000 Ib ft /1000 Ib lb/1000 Ib gpm/1000 Ib
AD,1 " 8.159 Aw/1 - 43.485 RL,i - 684.44 RG/I - 1.369 ฃ>H,1
AD,2 * 4.182 AH(2 " 26.091 RL/2 684.44 RG< 2 " 1.369 Ow,2
AD'3 - 3.374 Au'|-, - 21.647 RT.'-, - 732.64 RG' i - 1.465 ft/-,
Total: 15.715
Month
T
1,0
T
T2 i
T
2,o
T
X,2
T
T
3,0
T
X,3
T ,
air
t (avg)
th (avg)
QW1
Qw2
Q
Total Q
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
91.123
1 2
147.8
114
66
196
149
77
210
159
75
59
80
11569
17352
20244
49164
0.176
0.037
0.103
26.987
3.042
149.0
115
67
198
150
78
211
160
76
60
80
11568
17352
20244
49164
0.176
0.037
0.103
27.039
3.095
2101.52
3 4
160.3
126
78
211
162
89
225
172
87
70
92
11568
17593
20485
49646
0.176
0.037
0.103
27.718
3.578
172.7
138
84
219
171
94
231
179
91
75
97
13014
18557
21208
52779
0.176
0.037
0.103
27.944
4.079
4.203
5 6
187.7
152
92
229
181
100
239
189
97
81
105
14460
19521
22172
56153
0.176
0.037
0.103
28.397
4.706
198.9
162
98
236
189
105
245
195
101
86
112
15424
20244
22654
58322
0.176
0.037
0.103
28.745
5.064
- 17,111 Cooling Tower Characteristic
! - 17,111 KaY/L - 1.45
1 ' Water/Gas Rate in Tower
52,538 RL/RA - 1-41
7 8 9 10 11 12
203.9
167
101
240
193
108
249
199
104
88
115
15906
20485
22895
59286
0.176
0.037
0.103
28.919
5,260
202.7
166
100
239
192
107
248
198
102
87
114
15906
20485
23136
59527
0.176
0.037
0.103
28.867
5.296
195.2
159
96
234
186
104
244
194
100
85
110
15183
19762
22654
57599
0.176
0.037
0.103
28.641
S.081
180.2 164.0
144 129
88 79
224 213
176 164
97 89
235 225
184 173
94 87
78 70
102 93
13496 12050
19039 18075
21690 20726
54225 50851
0.176 0.176
0.037 0.037
0.103 0.103
28.171 27.648
4.348 3.793
151.5
118
69
200
152
80
214
162
78
62
83
11809
17352
20244
49405
0.176
0.037
0.103
27.143
3.060
(continued)
-------
TABLE A7-18. (Akron, Ohio) Continued
Design intermediate^tempeiatura^ T all wet
NJ
o
o
.gn ft /1000 Ib
AD/1 - 0
AD,2 " ฐ
AD,3 ฐ ฐ
Total: 0
Month
T,
1,0
Tx,i
T2,i
T
2,o
T
X,2
T
3,i
T
3,0
T
X,3
T
air
t (avg)
th (avg)
QW1
QW2
QW3
Total Qw
il air fan energy
cw-hr/1000 Ib)
:r fan energy
cw-hr/1000 Ib)
:ulation pomp energy
cw-hr/1000 Ib)
>ression energy
cw-hr/1000 Ib)
>r consumed
ft /10
ftw,l -
AW,2 "
AW,3 ฐ
00 Ib lb/1000 Ib gpm/1000 Ib
49.178 RL(i - 1050.76 RG(1 ป 2.102 QWJ
29.507 RL(2 1050.76 RG'2 - 2.102 Ow(-
28.308 RT. , - 1098.96 R^' , - 2.198 Qu ,
106.993
1
147.8
148
68
199
199
79
213
213
72
59
82
19280
28920
33981
82181
0
0.057
0.157
27.056
5.232
2
149.0
149
69
200
200
81
215
215
75
61
84
19280
28679
33740
81699
0
0.057
0.157
27.126
5.395
3200.48
3
160.3
160
79
213
213
91
228
228
85
71
1
94
19521
29402
34463
83386
0
0.057
0.157
27.631
6.186
4
172.7
173
85
220
220
96
234
234
88
75
100
21208
29884
35186
86278
0
0.057
0.157
27.997
6.840
6.402
5
187.7
188
93
230
230
101
240
240
93
81
107
22895
31089
35427
89411
0
0.057
0.157
28.432
7.493
6
198.9
199
98
236
236
105
245
245
96
85
112
24341
31571
35909
91821
0
0.057
0.157
28.745
7.957
26,269 Cooling Tower Characteristic
1 - 26,269 KaY/L - 1.45
, - 27,474 Water/Gas Rate in Tower
80,012 RL/RA ' i-41
7
203.9
204
101
240
240
108
249
249
98
88
115
24823
31812
36391
93026
0
0.057
0.157
28.919
8.801
8
202.7
203
100
239
239
107
248
248
97
87
114
24823
31812
36391
93026
0
0.057
0.157
28.867
8.311
9
195.2
195
97
235
235
104
244
244
95
85
110
23618
31571
35909
91098
0
0.057
0.157
28.658
7.820
10
180.2
180
89
225
225
99
238
238
90
78
103
21931
30607
35668
88206
0
0.057
0.157
28.223
7.221
11
164.0
164
80
214
214
91
228
228
85
71
95
20244
29643
34463
84350
0
0.057
0.157
27.701
6.376
12
151.5
152
71
203
203
83
218
218
77
63
86
19521
28920
33981
82422
0
0.057
0.157
27.231
5.177
(gal/1000 Ib)
-------
TABLE A7-19. SUMMARY OF WET/DRY COMPRESSOR INTERSTAGE COOLING FOR AIR COMPRESSOR
Fannlngton, New Mexico
Basis: 1000 Ib air compress ed/hx
Design intermediate temperature, "F
Dry cooler area, ft /1000 Ib/hr
Wat cooler area, ft2/1000 Ib/hr
Circulation rate, gpm/1000 Ib/hr
Avg . fan ฃ pujnp energy, kw-hr/1000 Ib
Compression energy, kw-hr/1000 Ib
Water consumed, gal/1000 Ib
M
O
1 i
Casper
Basis: 1000 Ib/air compressed/hr
Design intermediate temperature, "F
Dry cooler area, ft /1000 Ib
Wet cooler area, ft /1000 Ib
Circulation rate, gpn/1000 Ib/hr
Avg. fan ฃ pump energy, kw-hr/1000 Ib
Compression energy, kw-hr/1000 Ib
Water consumed, gal/1000 Ib
140
58.480
75.368
1.890
0.704
27.618
0.851
, Wyoming
140
54 .052
75.368
1. 890
0.658
27.503
0.868
160
40.059
83.853
3.046
0.551
27.796
1.929
160
39.323
83.855
3.046
0.542
27.640
1.779
180
26.819
91.123
4.203
0.440
27.889
3.097
180
23.577
91.123
4.203
0.404
27.839
3.275
all wet
0
106.560
7.443
0.249
28.132
7.215
all wet
0
106.107
7.326
0.245
27.991
6.965
Charlestonj__West Virginia
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, ฐF
Dry cooler area, ft /1000 Ib/hr
2
Wet cooler area, ft /1000 Ib/hr
Circulation rate, gpm/1000 Ib/hr
Avg. fan & pump energy, kw-hr/1000 lt>
Compression energy, kw-hr/1000 Ib
Water consumed, gal/1000 Ib
AJcron
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, ฐF
Dry cooler area, ft /1000 Ib/hr
2
Wet cooler area, ft /1000 Ib/hr
Circulation rate, gpm/1000 Lb/hr
Avg. fan & pump energy, kw-hr/1000 Ib
Compression energy, kw-hr/1000 Ib
Water consumed, gal/1000 Ib
140
44.596
75.368
1.890
0.562
28.076
1.625
, Ohio
140
40.848
75.368
1.890
0.520
27.879
1.638
160
29.462
83.855
3.046
0.432
28.162
2.902
160
26.616
83.855
3.046
0.400
27.957
2.891
180 all wet
18.049 0
91.123 108.278
4.203 6.690
0.342 0.225
28.229 28.278
4.242 7.309
180 all wet
15.715 0
91.123 106.993
4.203 6.402
0.316 0.214
28.018 28.049
4.200 6.651
-------
TABLE A7-20. ANNUAL AVERAGE COST FOR WET/DRY COMPRESSOR INTERSTAGE
COOLING FOR AIR COMPRSSOR
Farmington. New Mexico
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, ฐF
Dry cooler cost, 4/1000 Ib
Wet cooler cost, 4/1000 Ib
Tower cost, 4/1000 Ib
Fan and pump energy, 4/1000 Ib
Compression energy cost, 4/1000 Ib
Total, 4/1000 Ib compressed
Water consumed, gal/1000 Ib
Casper ,
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, "F
Dry cooler cost, 4/1000 Ib
Wet cooler cost, 4/1000 Ib
Tower cost, 4/1000 Ib
Fan and pump energy, 4/1000 Ib
Compression energy cost, 4/1000 Ib
Total, 4/1000 Ib compressed
Water consumed, gal/1000 Ib
Charleston ,
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, ฐF
Dry cooler cost, 4/1000 Ib
Wet cooler cost, 4/1000 Ib
Tower cost, 4/1000 Ib
Fan and pump energy, 4/1000 Ib
Compression energy cost, 4/1000 Ib
Total, 4/1000 Ib compressed
Water consumed, gal/1000 Ib
Akron
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, *F
Dry cooler cost, 4/1000 Ib
Wet cooler cost, 4/1000 Ib
Tower cost, 4/1000 Ib
Fan and pump energy, 4/1000 Ib
Compression energy cost, 4/1000 Ib
Total, 4/1000 Ib compressed
Water consumed, gal/1000 Ib
140
3.123
2.367
0.081
1.408
58.164
65.142
0.851
, Wyoming
140
2.886
2.367
0.081
1.316
57.921
64.571
0.86B
160
2.139
2.633
0.131
1.102
58.538
64.543
1.929
160
2.100
2.633
0.131
1.084
58.210
64.157
1.779
180
1.432
2.861
0.180
0.88
58.734
64.088
3.097
180
1.259
2.861
0.180
0.808
58.629
63.738
3.275
all wet
0
3.346
0.319
0.498
59.246
63.409
7.215
all wet
0
3.332
0.314
0.490
58.949
63.085
6.965
West Virginia
140
2.381
2.367
0.081
1.124
59.128
65.081
1.625
, Ohio
140
2.181
2.367
0.081
1.040
58.713
64.382
1.638
160
1.573
2.633
0.131
0.864
59.309
64.510
2.902
160
1.421
2.633
0.131
0.800
58.877
63.'862
2.891
180
0.964
2.861
0.180
0.684
59.450
64.140
4.242
180
0.839
2.861
0. 180
0.632
59.006
63.519
4.200
all wet
0
3.400
0.287
0.450
59.553
63.690
7.309
all wet
0
3.349
0.275
0.428
59.071
63. 123
6.651
202
-------
APPENDIX 8
BOILERS, ASH DISPOSAL AND FLUE GAS DESULFURIZATION
In the four SNG processes, coal or char is burnt to raise steam in a
boiler. The furnaces are assumed to be 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 10
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 gasifiers 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. The heat from quenching
furnace bottom ash is normally lost by convection from the ash bins. The
evaporation load is small and ignored, as is any evaporation caused by radi-
ant heat transfer through the furnace ash throat to the bottom ash collection
hopper.
Where a solid fuel (coal or char) boiler is used, flue gas desulfuri-
zation by a wet lime/limestone scrub is used. The water consumed in this
scrubber is calculated from the equations :
Ib makeup water evaporated per Ib coal or char fired
= 12'8(lf + if* + 10-5(f - 3ง} - W- 9h
Ib water in sludge per Ib coal or char fired = 13.8s
Ib wet sludge per Ib coal or char fired = 19.7s
203
-------
where c, s, h, x and w are the weight fractions of carbon, sulfur, hydrogen,
oxygen and water in the fuel as fired. The wet sludge is 30 percent solids
and 70 percent water.
The various sludge and ash numbers have been calculated for each
site/process on the worksheets in Appendix 10.
REFERENCE, APPENDIX 8
1. Goldstein, D.J. and Yung, D., Water Purification Associates, "Water
Conservation and Pollution Control in Coal Conversion Processes,"
U.S. Environmental Protection Agency, Report EPA-600/7-77, June 1977.
204
-------
APPENDIX 9
ADDITIONAL WATER NEEDS
Needs for water not defined in the preceding appendices on process
water, ash disposal and flue gas desulfurization, and on cooling are:
Dust control
Sanitary, potable and service water
Evaporation from storage ponds
Revegetation
DUST CONTROL
Water sprayed for dust control in the mine, on the road from the mine
to the plant, and in the plant depends on the rate of handling of coal and
on the length of the mine roads. Considered first is dust control on the
mine roads.
The length of unpaved haul roads and mine bench areas depends on the
mine productivity as measured by the amount of coal recoverable per unit
area of stripped land. In the present study the following mine yields are
used:
Location 10 Ib/acres
Beulah, North Dakota 50,000
Gillette, Wyoming ' 180,000
4
Navajo, New Mexico 74,000
Colstrip, Montana 80,000
205
-------
For want of other information, these yields are taken to be representative
of all mines in the state. In the assumed mine model, the mining of
100 acres per year would require 2 miles of 45 ft wide unpaved haul roads
to serve as spurs to conveyor belts that would feed the coal to the plant.
Such a belt line operation is described in Reference 1. The bench area
acreage that would have to be wetted down is approximately equal to four
times the daily acreage that is mined. The sum of the two unpaved areas
determines the area where dust control must be practiced. This area is
5,320 ft /(acre mined/yr).
The simplest means of holding down fugitive dust is to wet down the
mine area and haul roads. It is assumed that the roads and mine area can be
kept in a wetted condition through an annual deposition of water equal to
the net annual evaporation rate. Any rainfall is taken to be an additional
safety factor. The annual pond evaporation rates for the areas examined
are:
Location inches/year
Beulah, North Dakota 45
Gillette, Wyoming 54
Navajo, New Mexico 61
Colstrip, Montana 49
The lay-down rate can be calculated from the relation:
lay-down rate = disturbed area x evaporation rate
That is, for 10 Ib coal mined:
lay-down rate, Ib = (10 Ib coal) x (acres mined/103 Ib coal)
x (5230 ft wetted/(acre mined/yr) ) x (1 ft/12 inches)
x (wetting rate, inches/yr) x (62.4 Ib water/ft
3,
206
-------
This equation gives:
Location
Beulah, North Dakota
Gillette, Wyoming
Navajo, New Mexico
Colstrip, Montana
Water for Road, Mine &
Embankment Dust Control
(Ib water/10 Ib coal)
24.5
8.2
22.4
16.7
For most of the processes the coal mining rate is equal to the coal
utilization rate, as given in the various process description sections.
However, because the Lurgi gasifiers cannot accept fines, the coal mining
rate for Lurgi is equal to 1.2 times the utilization rate. The fines are
assumed to be sold.
East of the Mississippi, dust control of this type is assumed not to be
required. However,- when the coal is mined underground a variable amount of
water is consumed in the mine. An average value of 50 Ib water/10 Ib coal
is used in this study. Water sprayed for dust control underground is taken
to be of a better quality than water sprayed for dust control above ground
because of the confined area and the possible harm to people.
In addition to the water sprayed on roads, water must be sprayed on the
coal itself. In all coal preparation plants, dust is generated in the
stages of loading and unloading, breaking, conveying, crushing, general
screening and storage. The water required to hold down this dust will be
considered next.
The ways of preventing dust from becoming airborne are through the
application of water sprays or of nontoxic chemicals and the use of dry or
wet dust collectors with partial or total enclosure. It is assumed that the
principal dust generating sources will be enclosed and that, where feasible,
air will be circulated and dry bag dust collection employed. Whenever coal
pulverization is necessary, it will be done under conditions of total enclos-
ure with no fugitive dust or hold-down water requirements. In inactive
storage the use of water for holding down dust can be minimized by the use of
nontoxic chemicals.
207
-------
Despite the design precautions indicated, in large-scale plants with
many transfer points, transfer belts, surge bins, storage silos and active
storage sites, it is necessary to employ water sprays to wet down the coal.
This is also generally necessary with breaking and primary crushing operations
4
An examination of the Wesco Lurgi plant design and the TOSCO oil shale plant
of coal handled and crushed is a reasonably conservative estimate. This
applies to the mine area.
Within the boundaries of any of the plants, water will also be needed
for dust control. Somewhat less water would be required in the plants than
in the mines, since many of the operations tend to be enclosed. On this
basis a good assumption is a consumptive use of one-half that applicable to
the mine areas, specifically, !_ Ib of water for every 100 Ibs of coal
handled and transferred. This is a little less water than that deduced from
the data of Reference 3.
The total water for dust control is shown on Table A9-1.
SANITARY, POTABLE AND SERVICE WATER
This requirement depends on the number of people employed in the mine
and plant. The number of people employed differs from site to site and
process to process, but the variations are, in fact, small so a single number
will suffice for all process/site combinations. About 650 people are
employed in the plants and about 270 more in the mines ' ' ' ' . Each
person uses about 32 gal/man-shift. The total consumption of sanitary and
potable water is therefore:
920 people x 32 gal/man-shift x 5 shifts/week x 1 week/168 hrs
x 8.33 Ib/gal = 7300 Ib/hr
This is all recovered as sewage.
The service water usage in the mine and plant such as for equipment
washing, maintenance, pump seals, etc., along with the fire water usage
through evaporation loss, is a difficult quantity to estimate. However, an
analysis of a number of mine designs indicates that this usage is essentially
nonrecoverable and can be related to the usage of sanitary and potable water.
208
-------
The estimated ratio for service to sanitary usage for a proposed
10 x 10 ton/yr surface mine near Gillette, Wyoming is about 1.6 . This
P
same figure for the proposed Kaiparowits underground mine is about 1.3,
based on estimated sanitary water usage. The two values are sufficiently
close that the average service water usage for the mine has been taken to be
1.5 times the sanitary water usage. Moreover, all of the water is taken to
be consumed, since recovery in the mine work areas would prove quite difficult
In the plant the service water requirement is probably higher and is taken
to be two times the sanitary and potable needs with about 65 percent recovered
as sewage.
The total water requirements are shown on Table A9-1.
RE VEGETATION
As part of any reclamation of mined land in arid and semi-arid regions,
there exists a potential requirement for supplemental irrigation water
associated with the establishment of soil stabilizing plant cover on mine
spoils. It is concluded that coal mined areas with greater than 10 inches
of mean annual precipitation can be reclaimed without supplemental irriga-
9
tion . Where there is less than 10 inches of annual rainfall, partially
reshaped coal mine spoils can be successfully revegetated with supplemental
irrigation of about 10 inches during the first growing season, with no
further requirement during subsequent growing seasons . Only at the Navajo,
New Mexico site is irrigation for revegetation required. The water require-
ment can be calculated from the following formula:
Revegetation water, Ib/hr = (Ib coal/hr) x (acres mined/74 x 10 Ib coal)
2
x (10 inches water) x (43,560 ft /acre)
x (1 ft/12 inches) x (62.4 lb/ft3)
Revegetation water in New Mexico is:
30.6 Ib water/103 Ib coal
209
-------
EVAPORATION
All plants require a reservoir from which evaporation will occur. Net
evaporation rates (pond evaporation minus precipitation) are:
Net Evaporation
(inches/hr)
North Dakota 30
Wyoming 40
New Mexico 53
Montana 35
East of the Mississippi, precipitation usually exceeds evaporation.
The rate of loss of water by evaporation in Ib/hr is:
(reservoir capacity, in ) (evaporation rate, in/yr)
x 3
reservoir depth, in (27.7 in /lb)(8550 hr/yr)
Take the reservoir depth to be 30 ft = 360 inches and the reservoir capacity
to be about 2 weeks, or 4 percent of the annual water consumption. If Q is
the water consumption in Ib/hr, the reservoir capacity is:
(0.04 x Q x 8550) lb x 27.7 in3/lb = 9473 Q in3
The evaporation rate is:
0.000111 Q (evaporation rate, in/yr) Ib/hr
Evaporation rates are also entered on Table A9-1.
REFERENCES, APPENDIX 9
1. Wyoming Coal Gas Co. and Rochelle Coal Co., "Applicant's Environmental
Assessment for a Proposed Gasification Project in Campbell and Converse
Counties, Wyoming," prepared by SERNCO, October 1974.
210
-------
2. Geological Survey, "Proposed Plan of Mining and ReclamationCordero
Mine, Sun Oil Co., Coal Lease W-8385, Campbell County, Wyoming," Final
Environmental Statement No. 76-22, U.S. Dept. of the Interior, April 30,
1976.
3. North Dakota Gasification Project for ANG Coal Gasification Co.,
"Environmental Impact Report in Connection with Joint Application of
Michigan Wisconsin Pipe Line Co. and ANG Coal Gasification Co. for a
Certificate of Public Convenience and Necessity, Woodward-Clyde
Consultants," Fed. Power Commission Docket No. CP75-278, Vol. Ill,
March 1975.
4. Batelle Columbus Laboratories, "Detailed Environmental Analysis Concern-
ing a Proposed Gasification Plant for Transwestern Coal Gasification Co.
Pacific Coal Gasification Co., Western Gasification and the Expansion
of a Strip Mine Operation near Burnham, New Mexico, Owned and Operated
by Utah International Inc.," Fed. Power Commission, February 1, 1973.
5. Gold, H., et al, "Water Requirements for Steam-Electric Power Generation
and Synthetic Fuel Plants in the Western United States," EPA Report
600/7-77-037, February 1977.
6. Colony Development Operation, "An Environmental Impact Analysis for a
Shale Oil Complex at Parachute Creek, Colorado, Part 1Plant Complex
and Service Corridor," Atlantic Richfield Co., Denver, Colo., 1974.
7. Atlantic Richfield Co., "Preliminary Environmental Impact Assessment
for the Proposed Black Thunder Coal Mine, Campbell County, Wyoming" and
"Revised Mining and Reclamation Plan for the Proposed Black Thunder
Coal Mine," 1974; also, "Black Thunder Mine, 10 Million Ton Per Year
Water Supply" (personal communication, Hugh W. Evans), Denver, Colo.,
March 6, 1975.
8. Bureau of Land Management, "Final Environmental Impact Statement Pro-
posed Kaiparowits Project," Chapter I, FES-76-12, U.S. Dept. of the
Interior, March 3, 1976.
9. National Academy of Sciences, Rehabilitation Potential of Western Coal
Lands, pp. 32-33, Ballinger Publishing, Cambridge, Mass., 1974.
10. Aldon, F.E., "Techniques for Establishing Native Plants on Coal Mine
Spoils in New Mexico," in Proc. Third Symposium on Surface Mining and
Reclamation, Vol. I, pp. 28-28, National Coal Assoc., Washington,
D.C., 1975.
211
-------
Dust Control:
TABLE A9-1. OTHER WATER NEEDS
Water Required
Sites Ib/lb Coal Handled*
North Dakota 0.055
Wyoming 0.038
New Mexico 0.052
Montana 0.047
East & Central:
Surface Mining 0.03
Underground Mining 0.08
Service, Sanitary and Potable Water:
Water Required Sewage Recovered
Sites 103 Ib/hr 1Q3 Ib/hr
All sites, all plants 21 14
Revegetation Water:
Water Required
Sites Ib/lb Coal Handled*
New Mexico only 0.0306
Evaporation:
Evaporation Losses as
Sites % of Water Consumed
North Dakota 0.33
Wyoming 0.44
New Mexico 0.59
Montana 0.39
Eastern S Central States 0.0
*For Lurgi plants, coal handled equals 1.2 times coal consumed.
212
-------
APPENDIX 10
WORK SHEETS FOR NET WATER CONSUMED AND WET SOLID RESIDUALS GENERATED
A three-page work sheet is presented for each plant/site combination.
On the first page is listed the coal quantities from the process appendix
and flue gas desulfurization information (where needed) as well as water for
ash handling from Appendix 8. On the second page the water and water streams
are listed; process water streams from the process appendix, other streams
from Appendix 9, and the grand total raw water input and treatment sludges
from Appendix 11. On the third page the conversion efficiency, heat loss
and the water evaported for cooling are given, calculated from the information
in the process appendices and Appendix 7. The work sheets are enclosed in the
following order:
Solvent Refined Coal
Synthoil
Hygas
Bigas
Synthane
Lurgi
For each process a cover sheet is given showing where each of the quantities
found in the work sheet comes from.
213
-------
WORK SHEET I WATER QUANTITY CALCULATIONS FOR
SRC PROCESS
PRODUCT SIZE: 10,000 ton/day
ENERGY: Table AJL-7, Stream 3
SOLVENT REFINED COAL
Coal Analysis (wt % as-received)
Moisture
C
H
O
N
S
Ash
HHV Calculated
(103 Btu/lb)
COAL FEED
to dissolver:
Tables 3-18,3-19
100
Table Al-3
Table Al-7, Stream 5
to gasifier: Table Al-4, Stream 17
Table Al-8, Stream 17
ASH HANDLING
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
Appendix 8
(continued)
-------
(continued)
(continued)
PROCESS WATER
a. Steam and boiler feed water required Table Al-4, Stream 11 s 14 + 10,000 Ib/hr
b. Dirty condensate from dissolving section Table Al-3, Stream 5 + 10,000 Ib/hr
c. .Medium quality condensate from gasifier Table Al-4, Stream 13
d. Medium quality condensate after shift Table Al-4, Stream 15
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
Table Al-10
Table Al-10 (Total output energy)
Table Al-10
OTHER WATER NEEDS
Conversion efficiency
Table Al-10
a = Dust control
b. Service,, sanitary & potable water:
Required
Sewage recovered
c. Ravegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANTi
TREATMENT SLUDGES
a. Lime softening
b. Jon exchange
c. BiotreatiDent
Appendix 9
Appendix 11
10 Ib/hr
solids water ฃ sludge
Disposition of Unrecovered Heaji
Appendix 11
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr_ % wet^
Table Al-11
Table Al-11
Table Al-11
Table Al-11
Table Al-11
Table Al-11
Table Al-11
10 Ib water
Btu/lb evap evap/hr
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SRC PROCESS
Marengo, Alabama
(continued)
cn
SITE: Marengo, Alabama
Ground water 6 Surface water
Coal Analysis (wt ป as-received)
Moisture
C
H
O
N
S
Ash
HHV Calculated
(103 Btu/lb)
PRODUCT SIZE: 10,000 ton/day
9
ENERGY: 12.92 X 10 Btu/hr
48.7
32.1
0.6
100
5.34
COAL FEED
to dissolver:
FGD WATER
3231 10 Ib/hr
17.3 109 Btu/hr
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
-0.11 Ib/lb coal
0.25 Lb/Ib coal
to gasifier:
500
2.67
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
_10 Ib/hr
9
10 Btu/hr
_10 Ib/hr
103 Ib/hr
10 Ib/hr
103 Ib/hr
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate from dissolving section
c. Medium quality condensate from gasifier
d. Medium quality condensate after shift
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary c potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
153
112
1,354
TREATMENT SLUDGES ( Note: Ground water and Surface water are the same)
103 Ib/hr
solids water t, sludge
0.3 1.7
a. Lime softening
b. Ion exchange
c. Biotreatment
27
(continued)
-------
Harengo, Alabama SRC
(continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SRC PROCESS
En e r gy_JTp ta_ls_
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
r9
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr
19.9
59.4 %
% wet Btu/lb evap
0 1,310
1,310
1,310
1,310
1,310
10 Ib water
evap/hr
786
1,303
SITE: Bureau, Illinois
Coal Analysis (wt % as-received)
Moisture
C
H
O
N
s
Ash
PRODUCT SIZE: 10,000 ton/day
ENERGY: 13.16 X 1Q9 Btu/hr
7.4
HHV Calculated
(103 Btu/lb)
COAL FEED
to dissolver: 1,725 J03 lb/hr
FGD WATER
Vaporized
With sludge
TOTAL:
FGD sludge
ASH HANDLING
18.6 109 Btu/hr
ฐ-56 Ib/lb coal
O-40 Ib/lb coal
produced, wet
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
to gasifier:
103 lb/hr
129
69.4
198
0
0
0
77 -ฐ 103 lb/hr
ฐ-B3 109 Btu/hr
0 103 lb/hr
0 103 lb/hr
0 103 lb/hr
0 103 lb/hr
(continued)
-------
Bureau, Illinois
(continued)
Bureau, Illinois SRC
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensote from dissolving section
c. hedium quality condensate from gasifier
d. Medium quality condensate after shift
81
85
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 BtuAir
15.0
to
M
CO
OTHER HATER NEEDS
a, Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c, Biotreatment
1,747
10 Ib/hr
solids water & sludge
1.5 7.0
17
Conversion efficiency
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr % wet
1.86 0
0.27
100
10
100
Btu/lb evap
1,390
1,390
1,390
1,390
1,390
1,390
10 Ib water
612
1,404
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SRC PROCESS
White, Illinois SRC
{continued}
SITE: White, Illinois
Coal Analysis (wt ^ as-received)
Moisture
C
H
O
N
S
Ash
COAL FEED
to dissolver:
HHV Calculated
(103 Btu/Lb)
1,557 10 Ib/hr
18.8 10 Btu/hr
FGD WATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
PRODUCT SIZE: 10,000 ton/day
9
ENERGY: 13.16 X 10 Btu/hr
7.1
to gasifier:
0.73 lb/lb coal
0. 39 lb/lb coal
16.0 10 J Ib/hr
0.19 IO9 Btu/hr
_10 Ib/hr
IO3 Ib/hr
_10 Ib/hr
IO3 Ib/hr
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
10 Ib/hr
142
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate from dissolving section
c. Medium quality condensate from gasifier
d. Medium quality condensate after shift
OTHER HATER NEEDS
a. Dust control
b. Service, sanitary C. potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
ซ Lime softening
b. Ion exchange
c. Biotreatraent
10 Ib/hr
228
10 Ib/hr
126
1,617
(continued)
-------
white, Illinois SRC
(continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SRC PROCESS
M
NJ
O
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
10 Btu/hi
19.Q
15.6
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr * wet
1.49 0
0.62
0.24
. 0.69
0.21
100
100
Btu/lb evap
1,370
1,370
1,370
1,370
1,370
1,370
10 Ib water
evap/hr
453
175
,504
153
1,265
SITE: Fulton, Illinois
Coal Analysis (wt * as-received)
Moisture
C
H
O
N
S
Ash
HHV Calculated
COAL FEED
PRODUCT SIZE: 10,000 ton/day
9
ENERGY: 13.16 x 10 Btu/hr
3.1
(10 Etu/lb) 10.65
to dissolver: I-76*1 1Q3 Ib/hr to gasifier: 60-ฐ 1Q3 Ib/hr
1S-B 10 Btu/hr
FGD WATER
Vaporized ฐ-56
With sludge ฐ-49
TOTAL:
FGD sludge produced, wet
ASH HANDLING
coal
coal
_ฐ_6_i_10 Btu/hr
_5 10 3 It/hr
.3
10
0 10 Ib/hr
0 10 Ib/hr
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
98.2
261
(continued)
-------
Fulton, Illinois SRC
(continued)
Fulton, Illinois SRC
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate from dissolving section
c. Medium quality condensate from gasifier
d. Medium quality condensate after shift
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10" Btu/hr
19. 4
NJ
ro
OTHER WATER KEEPS
a. Dust control
b. Service, sanitary ฃ potaile water:
Required
Sewage recovered
c. Revegstation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
Conversion efficiency
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr % wet Btu/Ib evap
1.B9 0 1,390
0.25
0.85
0. 28
0.80
0. 25
100
1,390
1,390
1,390
1,390
1,390
10 Lb water
evap/hr
a. Lame softening
b. Ion exchange
c. Biotreatment
d. Electrodialysis
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SRC PROCESS
Saline, Illinois SRC
(continued)
SITE: Saline, Illinois
PRODUCT SIZE: 10,000 ton/day
to
to
to
9
ENERGY: 13.16 X 10 Btu/nr
Coal Analysis (wt \ as-received)
Moisture 6.8
C 67.9
H 4.5
0 6.8
N 1.4
S 3.1
Ash 9.5
100
HHV Calculated
(103 Btu/lb) 12.26
COAL FEED
to dissolver: 1,527 io3 Ib/hr to gasifier: 50-5
18.7 109 Btu/hr 0.62
FGD WATER
Vaporized 0.76 lb/lb coal 0
With sludge 0.43 u,/lb coal ฐ
TOTAL: 0
FGD sludge produced, wet 0
ASH HANDLING
IO3 Ib/hr
Bottom ash: dry 150
water 80.7
sludge 231
Fly ash: dry ฐ
water ฐ
aludqe ฐ
10 3 Ib/hr
9
10 Btu/hr
IO3 Ib/hr
IO3 Ib/hr
10 3 Ib/hr
IO3 Ib/hr
PROCESS HATER
a. Steam and boiler feed water required
b. Dirty condensate from dissolving section
c. Medium quality condensate from gasifier
d. Medium quality condensate after shift
OTHER WATER KEEPS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
272
1,020
0.06
(continued)
-------
Saline, Illinois SRC
(continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SRC PROCESS
ro
M
LO
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Stu/hr
1.63
10 Btu/hr
19.3
10 Ib water
wet Btu/lb evap evap/hr
1,370
1,370
1,370
1,370
1,370
1,370
SITE: Rainbow It8, Wyoming
Coal Analysis (wt t as-received)
Moisture
C
H
O
N
S
Ash
COAL FEED
to dissolver: 1,569 10 Ib/hr
18.2 109 Btu/hr
FGD WATCH
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.6B ib/lb coal
0.12 Ib/Lb coal
PRODUCT SIZE: 10,000 ton/day
ENERGY: 13.16 X 1Q9 Btu/hr
HHV Calculated
(103 Btu/Lb) 11.65
to gasifier:
Bottom ash: dry
water
eludge
Fly ash: dry
water
sludge
10 Lb/hr
89.5
3.0 10 Ib/hr
1.03 10 Btu/hr
_10 Ib/hr
103 Lb/hr
_10 IJb/hr
103 Ib/hr
(continued)
-------
Rainbow 38, Wyoming SRC
(continued)
Rainbow 98, Wyoming SRC
(continued)
PROCESS WATER
a. Steajn and boiler feed water required
b. Dirty condensate from dissolving section
c. Medium quality condensate from gasifier
d. Medium quality condensate after shift
,312
Energy Totals
Feed
Product And byproduct
Unrecovered heat
10 Btu/hr
19.3
15.1
OTHER WATER HEEDS
Conversion efficiency
78.8
M
to
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Pevegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
63
a. Lime softening
b. Ion exchange
c. Biotreatment
Dispogition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
109 Btu/hr
1.72
0.32
O.S6
% wet
0
0
100
Btu/lb evap
1,397
1,397
1,397
103 Ib water
evap/hr
0
0
401
Acid gas removal
regenerator condenser 0 32
Total turbine condensers 0 87
Total gas corrtpressor
interstage cooling 0- 29
TOTAL:
100
1,397
1,397
1,397
1,255
0.18
0.90
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SRC PROCESS
Gillette, Wyoming SRC
(continued)
SITE: Gillette, Wyoming
Coal Analysis (wt % as-received)
Hois ture
COAL FEED
to dissolver:
FGD WATER
C
H
0
N
S
Ash
HHV Calculated
(103 Btu/Ub)
2,264 103 Ib/hr
17.9 10 Btu/hr
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.24 Ib/lb coal
0.10 Ib/lb coal
PRODUCT SIZE: 10.000 ton/day
9
ENERGY: 12-92 * 10 Btu/hr
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
to gasifier:
10 Ib/hr
1-15 10 BtuAir
_10 Ib/hr
103 Ib/hr
_10 Ib/hr
103 Ib/hr
289
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate from dissolving section
c. Medium quality condensate from gasifier
d. Medium quality condensate after shift
CITHER WATER NEEDS
a. Dust control
b. Service, sanitary & potaljle water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAH WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatroent
10 Ib/hr
308
97
10 Ib/hr
92
10 Ib/hr
solids water ฃ sludge
1.0 5.0
IB
(con ti_nued)
-------
Gillette, Wyoming
(continued)
WORK SHEET: WATER QUANTITY CAJjCULATIONS FOR
SRC PROCESS
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
j,j Disposition of Unrecovered Heat
cr>
109 Btu/hr ป wet
Direct loss 2.60 0
Designed dry 0.46 0
Designed wet 0.56 100
Acid gas removal
regenerator condenser 0.34 10
Total turbine condensers 0.93 10
Total gas compressor
interstage cooling 0.31 50
TOTAL: 5.20
10 Btu/hr
19.1
13.9
5.2
72.8 ป
Btu/lb evap
1,401
1,401
1,401
1,401
1,401
1,401
103 Ib water
evap/hr
0
0
400
24
66
111
601
SITE: Antelope Creek, Wyoming
Coal Analysis (vt % as-received)
Moisture
C
H
O
N
S
Ash
COAL FEED
to dissolver:
HHV Calculated
(103 Btu/lb)
3
1,971
Ib/hr
I7-7 10 Btu/hr
FGD WATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.35 Ib/lb coal
0.07 Ib/lb coal
PRODUCT SIZE: 10,000 ton/day
ENERGY: 12.92 X 10 Btu/hr
52.6
3.6
to gasifier:
10 Ib/hr
1.26 10 Btu/hr
_10 Ib/hr
103 Ib/hr
_10 Ib/hr
103 Ib/hr
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
10 Ib/hr
95.0
51.2
(continued)
-------
Antelope Creek, Wyoming SRC (continued)
Antelope, Wyoming SRC (continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate from dissolving section
c. Medium quality condensate from gasifier
d. Medium quality condensate after shift
10 Ib/hr
323
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
19.0
to
NJ
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recove red
c. Reve-getation water
d. Evaporation from 5torage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
d. Electrodialysis
10 Ib/hr
81
10 Ib/hr
solids water 6 sludge
1.3
Conversion efficiency
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr
2.21
0.36
10 Lb water
Btu/lb evap evap/hr
1, 397 0
1,397 0
1,397
1,397
1,397
1,397
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SRC PROCESS
Dickinson, North Dakota SRC (continued)
K)
03
SITC: Dickinson, North Dakota
Coal Analysis (wt t as-received)
Moisture
C
H
O
N
S
Ash
HHV Calculated
(103 Btu/lb)
COAL FEED
to dissolver:
2,758 10" Ib/hr
17.4 109 Btu/hr
FCD WATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.23 lb/lb coal
0.07 Lb/lb coal
PRODUCT SIZE: 10.000 ton/day
ENERGY: 12.92 x 10 Btu/hr
41.2
2.7
11.0
0.5
6.31
to gasifier:
10J Ib/hr
J..94 10' Btu/hr
_10J Ib/hr
103 Lb/hr
_10J Ib/hr
_103 Ib/hr
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
107
307
PROCESS HATER
a. Steam and boiler feed water required
b. Dirty condensate from dissolving section
c. Medium quality condensate from gasifier
d. Medium quality condensate after shift
OTHER HATER NEEDS
a. Dust control
b. Service, sanitary fi potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW HATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatroent
10" Ib/hr
167
solids water t sludge
0.37
(continued)
-------
Dickinson, North Dakota SRC (continued)
WORK. SHEET i WATER QUANTITY CALCULATIONS FOR
SRC PROCESS
SITE: Bentley, North Dakota
PRODUCT SIZE: 10,000 ton/day
9
ENERGY: 12.92 X 10 Btu/hr
Energy Totals
10 Btu/hr
Feed 19.3
Product and byproduct 12.8
Unrecovered heat 6.5
Disposition of Unrecovered Heat
103 Ib water
10 Btu/hr % wet Btu/Lb evap evap^hr
Direct loss 3.25 0 1,420 0
Designed dry 0.63 0 1,420 0
Designed wet 0.64 100 1,420 451
Acid gas removal
regenerator condenser 0.49 10 1,420 35
Total turbine condensers 1.14 10 1,420 80
Total gas compressor
interstage cooling 0.40 50 1,420 141
TOTAL- 6-55 707
Coal Analysis (wt * as-received)
Moisture 36.4
C 41.6
H 3.1
0 H-3
N 0-6
S 1-2
Ash 5.8
100
HHV Calculated
(103 Btu/Lb) 7-1'1
COAL FEED
to dissolver: 2,493 103 Lb/hr to gasifier: 225 lo3 Lb/hr
17.8 lo9 Btu/hr 1.61io9 Btu/hr
FGD WATER
Vaporized 0.13 Lb/Lb coal 0 io3 Lb/hr
With sludge 0.17 lb/lb coal 0 io3 Lb/hr
TOTAI,: 0 10 lb/hr
FGD sludge produced, wet 0 lo Lb/hr
ASH HANDLING
IO3 Lb/hr
Bottom ash: dry 150
water 84 t 9
sludge 243
Fly ash: dry ฐ
water ฐ
sludge ฐ
(continued)
-------
Bentley, Nortti Dakota SRC (continued)
Bentley, North DaXota SRC (continued)
PROCESS WATER
a. Steam and boiler feed water required
b- Dirty condensate from dissolving section
c. Medium quality condensate from gasifier
d. Medium quality condensate after shift
113
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
19.4
N;
to
o
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary S potable wateri
Required
Sewage recovered
c. Rfivegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
B. Lime softening
b. Ion exchange
c- Biotreatment
21
947
0.8
sjludge
Conversion efficiency
Pi spos j.tion_j3fUn,re cove red Heat
10 J3tu/hr. t wet B t u/ Ib e_v ap
10 1ฑ> water
e^vap/hr
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
2.
0.
0.
0.
1.
0
86
55
73
39
05
.36
0
100
10
10
50
L
lj
l,
lj
i^
i
,420
,420
,420
,420
,420
,420
0
0
514
27
74
127
5.94
1.7
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SRC PROCESS
Underwood, North Dakota SRC (continued)
NJ
U)
SITE: Underwood, North Dakota
Coal Analysis (wt % as-received)
Moisture
C
H
0
>1
S
Ash
HHV Calculated
(103 Btu/lb)
COAL FEED
to dissolver: 2,429 10 Ib/hr
17.3 109 Btu/hr
FGD WATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.14 lb/]_b coal
0.07 Ib/lb coal
PRODUCT SIZE: 10,000 ton/day
ENERGY: 12.92 x 10 9 Btu/hr
35.4
42.7
12.2
0.6
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
to gasifier: 272 10 Ib/hr
1.94 io9 Btu/hr
_10 Ib/hr
_103 Ib/hr
_103 Ib/hr
103 Ib/hr
10 Lb/hr
151
81.4
233
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate from dissolving section
c. Medium quality condensate from gasifier
d. Medium quality condensate after shift
OTHER WATER KEEPS
a. Dust control
b. Service, sanitary S potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
10 IL/hr
383
10 Ib/hr
147
10 Ib/hr
solids^ water & sludge
(continued)
-------
Underwood, North Dikota
(continued)
WORK SHEET: WATER QUANTITY CAJjCULATIONS FOR
SRC PROCESS
Energy
Feed
Product and byproduct
Un re cove red heat
Conversion efficiency
Disposition of JJnrecovered Hej^
10 Btu/hr
19.3
13.3
- 6.0
10 Ib water
M
OJ
M
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
TOTAL:
10 Btu/hr
2.83
0.59
0.58
0.44
1.13
0.40
5.96
% wet
0
0
100
10
100
100
Btu/lb evap
1,420
1,420
1,420
1,420
1,420
1,420
evap/>ir
0
0
408
31
796
282
1,517
SITE: Otter Creek, Montana
Coal Analysis {vt % as-received)
Moisture
C
H
O
COAL FEED
to dissolvert
S
Ash
HKV Calculated
(103 Btu/lb)
2,062 10"
10 Btu/hr
TCP WATER
Vaporized
with sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.29 lta/lt> coal
0.08 lb/lb coal
PRODUCT SIZEi 10,000 ton/day
9
ENERGY: 12.92 X 10 Btu/hr
29.4
100
to gasifier:
Bottom ash : dry
water
sludge
Fly ash: dry
water
sludge
181
lo Ib/hr
2.37 IQ Btu/hr
_10 Ib/hr
_103 Ib/hr
_103 Ib/hr
103 Ib/hr
(continued)
-------
Otter Creek, Montana SRC (continued)
Otter Creek, Montana
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b . Dirty condensa te f rom dissolving section
c. Medium quality condensate from gasifier
d . Medium qua 1i ty condensate after shift
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
19.4
NJ
GJ
LO
OTItER WATER KEEPS
a . Dus t control
b. Service, sanitary & potable water:
PJS q ui r e d
Sewage recovered
c. Revpgetation water
d . E~vapora tion from s to rage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Li me softening
b. Ion exchange
c. Biotrea Lmen t
d Electrodialysis
10 Ib/hr
110
10 Lb/hr
3 o1i d 3 water fi sludge
Conversion efficiency
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
To Lai turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr * wet
2.51 0
"70.1
10 It water
Btu/lb evap evap/hr
1,407 0
1,407 0
1, 407
1,407
-------
WORK SHEET: HATER QUANTITY CALCULATIONS FOR
SRC PROCESS
Pumpkin Creek, Montana
(continued)
SITE: Punpkin Creek, Montana
Coa 1 ^AnaJy5is fwt. ป as-reegj^vgdj
PRODUCT SIZE: io,000 ton/day
ENERGY; 12.92 x 10.9 Btu/hr
COAL FEED
to diesolver:
FGD WATER
Vaporized
With sludge
Moisture 30.7
C 44.6
H 3.1
0 12.5
N 0.7
E 0.5
Ash 7.9
100
HHV Calculated
(103 Btu/lb) 7.46
2,325 103 Ib/hr to gasifier:
17.3 109 Btu/hr
0.21 Ib/lb coal
0.07 Ib/lb coal
TOTAL:
FGD sludge produced, wet
ASH HANDLING
10 3 Ib/hr
Bottom ash: dry 205
water 110
sludge 315
Fly ash: dry ฐ
water ฐ
sludge ฐ
270 103 Ib/hr
g
2.01 10 Btu/hr
0 103 Ib/hr
0 10 3 Ib/hr
0 103 Ib/hr
0 103 Ib/hr
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate from dissolving section
c. Medium quality condensote from gasifier
d. Medium quality condensate after shift
OTHER WATER NEEDS
a. Dust control
b. Service, eanitary 6 potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
C. Biotreatment
10 llj/hr
396
0,36
(continued)
-------
Pumpkin Creek, Montana
(continued)
WORK SHEETi WATCR QUANTITY CALCULATIONS FOR
SRC PROCESS
SITE i coalridge, Montana
NJ
LU
Ui
Energy Totals
Feed
Product and byproduct
Unrpcove red heat
Conversion efficiency
Pi sposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Tota 1 turbine condensers
Tot a. 1 gas compressor
Interstage cooling
10 Btu^/hr
19.4
leat
9
10 Btu/hr
2. 70
0. 58
0. 67
0.45
1. 14
ป wet
0
0
100
10
10
Btu/Lb evap
1 ,414
1,414
1, 414
1,414
1,414
10 Ib water
evap/hr
0
0
474
32
81
HHV Calculated
(103 Btu/Lb)
COAL FEED
to dissolver: 2.946 10 Ib/hr
16.5 109 Btu/hr
FGD WATER
Vapori red
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
- 0.01 Ib/lb coal
0.06 Lb/lb coal
PRODUCT SIZE: 10,000 ton/day
ENERGY: 12.92 x 109 Btu/hr
Coal Analysis (ut ป as-received)
Mois tu re
C
H
O
N
S
Ash
IP
35
2.
13.
0
0.
7.
J
. 2
.4
.5
.6
. 4
. 5
to gasifier: 620 10 Ib/hr
3.47 10 Btu/hr
_10 Lb/hr
103 Lb/hr
10 Ib/hr
Bo t torn ash : dry
water
sludge
Fly ash: dry
water
sludge
(continued)
-------
Coa 1 r 1 dge, Hontana s RC
(continued)
Coalridge, Montana
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate from dissolving section
c. Medium quality condensate from gasifier
d. Medium quality condensate after shift
10 lb/hr
521
330
251
ENERGY
Energy^ Totals^
Feed
Product and byproduct
Unrecovered heซt
10 Btu/hr
20.0
11.8
OTHER WATER KEEPS
a. Dust control
b. Service, sanitary 6 potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
10 lh/hr.
167
14
1,081
Conversion efficiency
Disposition of JJnrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
59.1 \
8.17
10 tt> water
10 Btu/hr
3.60
0.95
0.85
0.65
1.55
ป wet
0
0
100
10
10
Btu/lb evap
1,407
1,407
1,407
1,407
1,407
evap/hr
0
0
604
45
110
1,407
965
0.53
2.7
-------
WOPX SHEET: WATER QUANTITY CALCULATIONS FOR
SRC PROCESS
Colstrip, Montana SRC
(continued)
IV)
UJ
--J
SITE: Colstrip, Montana
Coai Analysis (wt % as-received)
Mois ture
COAL FEED
to d is solver:
C
H
0
N
S
Ash
HHV Calculated
(103 Btu/lb)
1,979 103 lb/hr
g
17.6 10 Btu/hr
FCD HATEP
Vapori zed
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0-37 Lb/lb coal
0.06 Ib/lb coal
PRODUCT SIZE: 10,000 ton/day
ENERGY: 12.92 X 10.9 Btu/hr
Bottom ash: dry
water
3ludge
Fly ash: dry
water
sludge
to gasifier: _1BO 10 lb/hr
1.60 109 Btu/hr
_10 Lb/hr
_103 lb/hr
_103 lb/hr
103 lb/hr
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate from dissolving section
c. Medium quality condensate from gasifier
d. Medium quality condensate after shift
OTHER WATER HEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
10 lb/hr
364
55
114
10 lb/hr
101
10 Ib/hr
solids water fe sludge
0.1
0.6
22
(continued)
-------
Colstrip, Montana
(continued)
Energy Totals
Peed
Product and byproduct
Unrecovered heat
10 Btu/hr
19.2
Conversion efficiency
to
UJ
CO
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Lb water
10 Btu/hr
2.27
0.45
0.62
0.40
1.03
ป wet
0
0
100
10
10
Btu/lh evap
1,414 .
1,414
1,414
1,414
1,414
evap/hr
0
0
438
28
73
1,414
255
794
-------
WORK SHEET: WATER QUANTITY CALCUlJiTIOKS FOR
SYNTHOIL PROCESS
PRODUCT SIZE: 50,000 bbl/day
ENERGY: 12.7 X 1Q9 Btu/hr
Coal Analysis (wt ป as-received)
Moisture
C
H
O
N
S
Ash
Tables 3-18, 3-19
HHV Calculated
(103 Btu/lb)
COAI. FEED
to reactor: Table A2-1, Stream 2
Table A2-6
to gasifier: Table A2-2, stream 3
Table A2-6
ASH HANDLING
Bottom ash: dry
water
sludge
Appendix 8
(continued)
-------
(continued)
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. ฃ>uench water required
c. Dirty condensete
d. Medium quality condejisate from
hydrogen production
Table A2-2, Streams 21 C 16
Table A2-2, Stream 14
Table A2-2, Stream 13
Table A2-2, Stream 15
Energy j*ptals
e. Clean condensate from hydrogen production Table A2-2, Stream 17
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
10 Btu/hr
Table A2-6
Table A2-6
Table A2-6
Table A2-6
O
OTHER WATER MEEDS
a. Dust control
b. Service, sanitary ฃ potable water:
Required
Sewage recovered
c. Re vegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER IKPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotrehtment
Disposition of Unrecovered jleat
Appendix 9
Appendix 11
10 lb/hr
solids water & sludge
Appendix 11
10 Ib water
10 Btu/hr * wet
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
TOTALs
Table
Table
Table
Table
Table
Table
Table
A2-7
A2-7
A2-7 ^
0>
A2-7 ^
A2-7 i.
A2-7
A2-7
Btu/lb evap evap/hr
a- P
t-1 Q
lt> C
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
EYNTHOIL PROCESS
Jefferson, Alabama
(continued)
SITE: Jefferson, Alabama
PRODUCT SIZE: 50,000 bbl/day
ENERGY: 12.7 X 1Q9 Btu/hr
PROCESS WATER
Coal Analysis (wt % as-received)
Moisture
C
H
O
S
Ash
HHV Calculated
(103 Btu/Lb)
COAL FEED
to reactor: ^
ASH HANDLING
_10
q
10 Btu/hr
71.0
12.79
Bottom ash: dry
water
sludge
to gasifier:
21B 10 Ib/hr
2-79 109 Btu/hr
a. Steam and boiler feed water required
b. Quench water required
c. Dirty condensate
d. Medium quality condensate from
hydrogen production
e. Clean condenaate from hydrogen production
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAJTO TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
59
2,237
10 Ib/hr
solids water ฃ sludge
(continued)
-------
Jefferson, Alabama
(continued)
Ejiergy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
17.9
Conversion efficiency
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas rejsoval
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr * wet
1.192
0. 12
0.87
0 27
10" U> water.
Btu/lb evap evap/Tir
1,310
1, 310
1,310
1,310
1,310
1,310
763
664
206
1,633
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SVNTHOIL PROCESS
SITE: Gibson, Indiana
PRODUCT SIZE: 50,000 bbl/day
9
ENERGY: 12.7 x 10 Btu/hr
Coal Analysis (wt % as-received)
Moisture
C
H
O
N
S
Ash
HHU Calculated
100
(10 Btu/lb) 12.20
to reactor:
1,221 10 Ib/hr to gasifier: 234 1Q Ib/hr
14.9 109 Btu/hr 2.85 1Q9 Btu/hr
ASH HANDLING
Bottom ash: dry
water
sludge
10 Ib/hr
93.1
50.2
143
(continued)
-------
Gibson, Indiana
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Quench water required
c, Dirty condensate
d. Medium quality condensate from
hydrogen production
e. Clean condensate from hydrogen production
10 Ib/hr
215
71
95
S9
OTHER WATER KEEPS
a . Dust control
b . Service , sa_ni tary ฃ potable water :
Required
Sewage recovered
c. Revegetation water
d . Evaporation from storage ponds
GRAND TOTAL RAW WATER IWPUT TO PLANT:
21
2,028
TREATMENT SLUDGES
a . L-ime sof tening
b. Ion exchange
c . B lot. re a tment
10 Ih/hr
solids water & sludge
0.57
Gibson, Indiana
(continued)
Energy^ Tgta 13
Feed
Product and byproduct
Un re cove red heat
10 Btu/Tir
17.7
Conversion efficiency
76.8
Disposition of Unrecove^red Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
!09
1
0
0
0
0
Btu/hr
.335
.15
.96
.50
.90
% wet
0
0
100
0
100
Btu/lb evap
1,370
1,310
1,370
1,370
1,370
103 lb water
evap/hr
0
0
701
0
657
Total gas compressor
interstage cooling
1,370
1,562
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
STrJTHOIL PROCESS
Warrick, Indiana
(continued)
S1TE: Warrick, Indiana PRODUCT SIZE: 50,000 bill/day
ENERGY : 12 7 s 109 Bm/>,r PROCESS WATER
Coal Analysis (wt ^ as-received) a. Steam and boiler feed water required
^ 6_ ,j_ Medium quality condensate from
O 94 hydrogen production
M i 2 e. Clean condensate from hydrogen production
E 2.4
Ash 8.3
100 OTHER HATER NEEDS
HHV Calculated
(103 Btu/lb) 11.65 Dust control
b. Service, sanitary 6 potable water:
COAL FEED Required
to reactor: 1,286 103 Ib/hr to gasifier: 246 lo3 Ib/hr Sewage recovered
15.0 109 Btu/hr 2.87 lo9 Btu/hr c- Revegetation water
d. Evaporation from storage ponds
ASH HANDLING GRAND TOTAL RAW WATER INPUT TO PLANT:
103 Ib/hr
Bottom ash: dry 127.1
water 68.4 TREATMENT SLUDGES
sludge 195.6
a. Lime softening
b. Ion exchange
c. Biotreatment
103 Ib/hr
211
289 '
99
103
57
103 Ib/hr
46
21
14
0
0
2,126
103 Ib/hr
solids water 6 sludge
13
0.02 0.08
(continued)
-------
Warr ck, Indiana
(continued)
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
17.6
13.fa
Conversion efficiency
Dispos i tion of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Ac id gas removal
regenerator condenser
Total tU-rbine condensers
Total gas compressor
interstage cooling
10 Ib water
10 Btu/hr
1.348
0.15
1.04
% wet
0
0
100
Btu/li evap
1,370
1, 370
1,370
evap/hr
0
0
759
1,370
1,370
1,370
657
1,620
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SYNTHOIL PROCESS
SITE: Harlan, Kentucky
PRODUCT SIZE: 50,000 bbl/day
ENERGY: 12.7 x 1Q9 Btu/hr
Coal Analysis (wt % as-received?
Moisture
C
H
O
N
S
Ash
HHV Calculated
(103 Btu/lb)
77.8
100
COAL FEED
to reactor:
1,071 jo lij/hr to gjLsifier: 203 10 Ib/hr
14.9 1Q9 Btu/hr 2-B2 109 BtuAr
ASH HANDLING
Bottom ash: dry
water
sludge
74.5
(continued)
-------
Ha rlan,
(continued)
PROCESS WATER
a. Steam ajid boiler feed water required
b . Qu e n ch water required
c. Dirty condensate
d. Medium quality condensate from
hydrogen production
e. Clean condensate from hydrogen production
274
59
OTHER WATER KEEPS
a . Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Re vegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
1,406
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
10 Ib/hr
solids water 6 3ludge
0.01
15
Harlan, Kentucky
(continued)
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
17.7
4.1
Conversion efficiency
78.1
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
To ta 1 gas comp res sor
interstage cooling
10 Btu/hr % wet Btu/lb evap
10 Ib water
1.
0.
0.
0
0
0
3
.179
.13
.93
.50
.87
.27
.88
0
0
100
0
10
50
1,
1,
1,
1,
1,
1,
350
350
350
350
350
350
0
0
689
0
64
100
853
-------
WORK SHEET: HATER QUANTITY CALCULATIONS FOR
SYNTHOIL PROCESS
SITE; Pike, Kentucky
PRODUCT SIZE: 50,000 bbl/day
ENERGY; 12.7 X 1Q9 Btu/hr
Coal Analysis (wt t as-received)
Moisture
C
H
0
N
S
Ash
HHV Calculated
(103 Btu/lb)
79.6
5.1
5.3
100
COAL FEED
to reactor:
1,047 10 Lb/hr
9
14.9 10 Btu/hr
to gasifier:
196 10 Lb/hr
9
2.62 10 Btu/hr
ASH HANDLING
Bottom ash: dry
water
sludge
Pike, Kentucky
(continued)
PROCESS HATER
a. Steam and boiler feed water required
b. Quench water required
c. Dirty condensate
d. Medium quality condensate from
hydrogen production
e. Clean condensate from hydrogen production
10 Ib/hr
229
OTHER HATER NEEDS
a. Dust control
b. Service, sanitary 6 potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT;
1,359
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatfflent
10 Ib/hr
so .lid s water
(continued)
-------
Pike .^Kentucky
(continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SYNTHOIL PROCESS
CD
Energy Totals
Feed
Product a_nd byproduct
Unrecovered heat
Conversion efficiency
10 Btu/hr
17.8
78,4 \
Disposition of Unrecovered
Direct loss
Designed dry
Designed wet
Acid gas rejsoval
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
Heat
9
10 Btu/hr \ wet
1.156 0
0.91 100
0.50 0
O.B6 10
0.27 100
Btu/Ib evap
1,360
1,360
1,360
1,360
1,360
1,360
103 Ib water
evap/hr
0
0
669
0
63
199
3.83
931
Tuscarawas, Ohio
.(Ground water and
surface water)
Coal Analysis [wt % as-received}
Moisture
C
H
0
N
S
Ash
KHV Calculated
(103 Btu/li)
to reactor:
ASH HANDLING
1.170 ip-1 li/hr
15.1 109 Btu/hr
PRODUCT SIZE: 50,000 bbl/day
9
ENERGY: 12.7 X 10 Btu/hr
B.I
5.6
Bottom ash: dry
water
sludge
to gasifier: 220 103
2-B4 10 Btu/Hr
(continued)
-------
Tuscarawas, Ohio
(continued)
Tuscarawaa, Ohio
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b . OTJench water r*xjui red
c. Dirty condensate
d . Medium quali ty condens ate from
hydrogen production
e. Cl i;an condensate from hydrogen production
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
10 Btu/hr
17,9
OTHER WATER NEEDS
a. Dust control
b. St-ivice, e ani tary & potable water ;
Requii ed
Sewage recovered
c. FU;vegetation water
d. Evapora 11on from s torage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TRKATKHNT SLJJIX^ES
1,493
S u r ftic e Water
103 ib/hr
solids water & sludge
0.8 4. 3
14
Dispjpsition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Ib water
10
1
0
1
0
0
0
4
Btu/hr
. 242
. 14
.10
.50
.88
.27
.13
4 wet
0
0
100
0
10
100
Btu/lb evap
1.410
1.410
1,410
1,410
1,410
1,410
evap/hr
0
0
780
0
62
191
1,033
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SYNTHOIL PROCESS
Jefferson, Ohio
(continued)
SITE: Jefferson, Ohio
Coal Analysis (wt a as-received)
Moisture
C
H
0
N
S
Ash
Ln
O
COAL FEED
to reactor:
ASH HANDLING
HHV Calculated
(103 Btu/lb)
1, 172,10
9
15.4 10 Btu/hr
PRODUCT SIZE: 50,000 bbl/day
ENERGY: 12.7 x 10 Btu/hr
5.3
10.1
to gasifier:
214 10 Lb/hr
9
2.BO 10 Btu/hr
PROCESS HATER
a. Steam and boiler feed water required
b. Drench water required
c. Dirty condensate
d. Medium quality condensate from
hydrogen production
e. Clean condensate from hydrogen production
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
10 Ib/hr
225
2,069
Bottom ash: dry
water
sludge
215.3
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
10 Ib/hr
solids water S sludge
(continued)
-------
i, Phi?..
(continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SYNTHOIL PROCESS
SITE: Somerset, Pennsylvania
1-0
Ln
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
10 Btu/hr
18.2
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr \ wet
1.232 0
Btu/lฑ) evap
1,400
1,400
1,400
1,400
1,400
10 Ib water
evap/hr
614
1,600
COAL FEED
to reactor:
ASH HANDLING
PRODUCT SIZE: 50,000 bbl/day
ENERGY: 12.7 x 1Q9 Btu/hr
Coal Analysis (wt % as-received)
Moisture 1.8
C 74.0
H 4.0
0 3.1
N 1.4
S 3.1
Ash 13-6
100
HHV Calculated
(10 Btu/lb) 13-c
,_10 Ib/hr to gasifier: 213 10 Ib/hr
,7 10 Btu/hr
Bottom ash: dry
water
sludge
2.79 10 Btu/hr
10 Ib/hr
182.1
(continued)
-------
Somerset, Pennsylvania
(continued)
Somerset, Pennsylvania ^(continued)
PROCESS WATER
a. Steam arid boi 1 er feed water required
b. Quench water required
c. Dirty condensate
d. Medium quality condensate from
hydrogen production
e. Clean condensate from hydrogen production
59
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
10 Btu/hr
17.5
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary t potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b, Ion exchange
c, Biotreatment
Disposition of Unrecovered Heat
1,581
10 Lb/hr
solids^ water & sludge
16
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr ป wet
1.159
0.13
0.27
0
10 Ib water_
Btu/lb evap evap/hr
1,410 0_
1,410 0_
1,410 730
1,410
1,410
1,410
61
9B2
0.002
-------
WORK SHEET: HATER QUANTITY CALCULATIONS FOR
SYNTH01L PROCESS
Minqo, West Virginia
(continued)
SITE: Mingo, West Virginia
Coal Analysis (xt \ as-received)
t\J
LD
COAL FEED
HHV Calculated
(103 Btu/Lb)
1,04B 10 Ib/hr
g
15.0 10 Btu/hr
PRODUCT SIZE: 50,000 bbl/day
g
ENERGY: 12.7 X 10 Btu/hr
Moisture
C
H
O
N
S
Ash
2.
79.
5.
5.
1
0
4
2
5
2
9
.4
.9
.9
to gasifier:
196 10 Lb/hr
g
2.80 10 Btu/hr
PROCESS WATER
a. Steam and boiler feed water required
b. O^iench water required
c. Dirty condensate
d. Medium quality condensate from
hydrogen production
e. Clean condensate from hydrogen production
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary G potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAH HATER INPUT TO PLANT:
10 Ib/hr
228
10 Ib/hr
37
1,352
Bottom ash: dry
water
sludge
TREATMENT SLUDGES
a. T.I me softening
b. Ion exchange
c. Biotreatment
10 Ib/hr
solids water 6 sludge
(continued)
-------
_V' i rgini a
(continued)
WORK SHEET: WATER QUANTITY CMjCULATIONS FOR
SYNTHOIL PROCESS
Er^e rgy To t a 1 s
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposit^ion of Unrecovered Heat
10 Btu/hr
17.8
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 lb water
10 Btu/hr % wet Btu/lb evap evap/hr
_L
0
0
0
0
0.
.152
.13
.91
.49
.86
.27
0
0
100
0
10
100
1,360 _
1,360 _
1,360
1,360
1,360
1,360
0
0
669
0
63
199
931
SITE: Lake de Smet, Wyonung
Coal Analysis (wt ป as-received)
Moisture
C
H
O
H
S
Ash
HHV Calculated
(103 Btu/lb)
to reactor:
ASH HANDLING
PRODUCT SIZE: 50,000 bbl/day
ENERGY: 12.7 X 1Q9 Btu/hr
0.7
1.0
9.7
100
14.1 10 Btu/hr
Bottom ash: dry
water
sludge
to gasifier: 413 10 Ib/hr
3.39 109 Btu/hr
(continued)
-------
Lake de Smet.
(continued)
Lake de Smet , Wyoming
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Quench water required
c. Dirty condensate
d . Hediura quality con dens ate from
hydrogen production
e . Clean condensate from hydrogen production
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
10 Btu/hr
17.5
OTHER WATER
NJ
Ln
LTI
a . Dust control
b . Service , sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAX RAW HATER INPUT TO PiLANT :
TREATMENT SLUDGES
a. La_me softening
b. Ion exchange
c, Biotreatment
10 Ib/hr
82
1,805
IO Ib/hr
solids water ฃ sludge
13
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
io9
1
0
0
0
1
0
4
Btu/hr
.876
.26
.81
.56
.01
.31
.83
ป wet
0
0
100
0
100
100
Btu/lb evap
1,401
1,401
1,401
1,401
1,401
1,401
10 Ib water
evap/hr
0
0
578
0
721
221
1,520
1.7
-------
WORK SHEET; WATER QUANTITY CALCULATIONS FOR
Jim Bridger, Wyoming
(continued}
SITE; jiB Bridger, Wyoming PRODUCT SIZE; 50/OOO bbl/day
EHERCY- 1" - x 109 Btu-hx PROCESS WATER
Coal Analysis (wt * as r c " ed) a" Steam and Boiler feed water required
ur.tc*.,ป. i-r i b- Ouench water required
_ _, _ c. Dirty condensate
H 3.2 d. Medium quality condensate frco
. , _ hydrogen production
. . e. Clean condensate frcan hydrogen production
S 0.5
Ash 8.2
1QO OTHER WATER NEEDS
to
01 (in3 Ht-u/lhl 8 50 * Dast colrtro1
b. Service, sanitary & potable water:
COM, FEED Required
to reactor: 1,605 J03 Xb/Ju: to gasifier: ซ9 103 lh/hr SeM9e recovered
13.6 io9 Btu/hr 3.81 109 BtuAur c" Vegetation v^ter
d. Evaporation froa storage ponds
__u Uftl~T,u- GRAKD TOTAL RAH WATER INPUT TO PLAHT:
10 3 Ib/hr
Bottoa ash: dry 168,4
vater 90.7 TREMME8T SWDGES
sludge 259
a. Jiitse softanlsg
b. Xon exchange
1O3 ltป/hr
213
351
201
234
43
103 Ib/hr
78
21
14
0
5
1,205
1O3 Ib/hr
solids water ฃ sludge
14
c. Biotxeatsent
0.32
1.6
(continued)
-------
Jim Bridqer, Wyoming
(continued)
WORK SHEET i WATER QUANTITY CALCULATIONS FOR
SVNTHOIL PROCESS
SITEi Gallup, New Mexico
Ul
-J
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr
1.76
0.87
0.31
4.75
100
10 Btu/hr
17.5
12.7
72.B \
10 Ib water
Btu/lb evap evap/hr
1,397 0_
1,397 0
1,397
1, 397
1,397
1,397
623
PRODUCT SIZE: 50,000 bbl/day
ENERGYi 12.7 x 109 Btu/hr
Coal Analysis (wt * ds-recelved)
Moisture 15-1
C 63.2
H 4.7
O 10.4
N 1.1
S ฐ-4
Ash 5.1
100
HHV Calculated
(103 Btu/lb) 11.30
COAL FEED
to reactor: 1,316 1Q3 Ib/hr
14.9 109 Btu/hr
ASH HANDLING
Bottom ash: dry
water
sludge
to gasifien 258 10 Ib/hr
2.92 1Q9 Btu/hr
(continued)
-------
Gallup, Hew Mexico
(continued)
Gall up, New Mexico
(continued)
PROCESS WATER
a. Steam arid boiler feed water required
b. Quench water required
c . Di r ty condensate
d. Medium quality condensate from
hydrogen production
e. Clean condensate from hydrogen production
10 Ib/hr
197
53
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
10 Btu/hr
17. B
4.3
K)
Ln
CO
OTHER WATER ffEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW HATER IKPUT TO PLANT:
TREATMENT SLUDGES
a. L-Lme softening
b. Ion exchange
c. Biotreatment
d. Electrodialysis
21
8
1,313
10 Ib/hr
solids water &jsludge
0.19
Disposition of Unrecoyered
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
TOTAL:
10" Ib water
10 Btu/hr
1.458
0.17
0.95
0.51
0.92
0.29
4.3
\ wet
0
0
100
0
10
50
Btu/lb evap
1,375
1,375
1,375
1,375
1,375
1,375
evap/hr
0
0
691
0
67
105
663
-------
WORK SHEET i WATER QUANTITY CALCULATIONS FOP
HYGAS PROCESS
SITE:
PRODUCT SIZE: 250 X 10 SCF/day
ENERGY: Table A3-11 (Product gas)
Coal Analysis (wt
ed)
to
Ln
Moisture
C
H
O
N
S
Ash
HHV Calculated
(103 Btu/lb)
COAL FEED
to reacton Table A3-10
Table A3-11
FGD WATER
Vaporized
Appendix 8
With sludge Appendix 8
TOTAL!
FGD sludge produced, wet
ASH HANDLING
Tables 3-18, 3-19
100
to boiler: Table A3-10
Table A3-11
Calcd. 103
10 Ib/hr
10 Ib/hr
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
Appendix 8
(continued)
-------
(continued)
(continued)
PROCESS WATER
NJ
CTi
O
a, Steam and boiler feed water required
b. Di rty condensate
c . Me tliajiat ion water
OTHฃR WATER
a . Dust control
b . Service , sanitary & pot-able water :
Required
Sewage recovered
c. Fevegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT
TREATMENT SLUDGES
a. Liae softening
b. Ion exchange
c. Biotreatment
Table A3-1Q
Table A3-10
Table A3-10
Appendix 9
Appendix 11
10 Ib/hr
solids water ฃ sludge
Appendix 11
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
10 Btu/hr
Table A3-11 (coal to pretreaUnent & boiler)
Table A3-11 (Product gas & fines, tar and oil)
Table A3-11
Table A3-11
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr % wet
Calcd. from effi-
ciency
Table A3-9
Table A3-11
10 Ib wacer
Btu/lb evap evap/hr
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
HYGAS PROCESS
SITE: Jefferson, Alabama
PRODUCT SIZE: 250 X 10 SCF/day
ENERGY: 10.34 x 10 Btu/hr
Coal Analysis (wt % as-received)
Moisture
C
H
O
N
S
Ash
HHV Calculated
(103 Btu/lb)
COAL FEED
to reactor:
FGD HATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
1,149 10 Ib/hr
9
14.7 10 Btu/hr
0.84 Lb/lb coal
0. 12 IVlb coal
to boiler:
115 10 Ib/hr
9
1.47 10 Btu/hr
96.5 10 Ib/hr
13.8 103 Ib/hr
110
19.7 10
10 Ib/hr
3
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
16.3
Jefferson, Alabama
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Methanation water
1,434
537
OTHER HATER HEEDS
a. Dust control
b. Service, sanitary ฃ potable water:
Required
Sewage recovered
c. Re vegetation water
d. Evaporation from storage ponds
GRAND TOTAi RAW WATER INPUT TO PLANT;
2,130
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
solida water ฃ sludge
0.01 0.05
80
(continued)
-------
Je fferson, Alahama
(continued)
WORK SHEET: WATER QUANTITY CAI>CULATIONS FOR
HYGAS PROCESS
Energy Total
Feed
Product and byproduct
Oncecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
IxJ g
(j\ 10 Btu/hr * wet
NJ
Direct loss 2.92 0
Designed dry 0.55 0
-Designed wet 0.40 100
Acid gas removal
regenerator condenser 0.80 10
Total turbine condensers 0.67 100
Total gas compressor
interstage cooling 0.17 100
TOTAL: 5.51
10 Btu/hr
16.2
10.7
5.5
65.9 ป
Btu/lb evap
1,310
1,310
1,310
1,310
1,310
1,310
10 3 Ib water
evap/hr
0
0
305
61
511
130
1,007
SITE: Marengo, Alabama
(Ground water and
surface water)
Coal Analysis (wt \ as-received)
Moisture
C
H
0
N
S
Ash
HHV Calculated
(103 Btu/lb)
COAL FEED
to reactor:
FGD WATER
Vaporized
With sludge
TOTAL:
FGD gludge produced, wet
ASH HANDLING
2.2BJ IQJ m/hr
_12.2 109 Btu/hr
PRODUCT SIZE: 250 X 10 SCF/day
ENERGY: 10.34 X 109 Btu/hr
32.1
2.2
100
5.34
to boiler:
coal (treat as zero)
ฐ - 2S Ib/lb coal
148 10 Ib/hr
10 Btu/hr
52.8
_10 Ib/hr
103 Ib/hr
_10 Ib/hr
103 Ib/hr
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
59.1
170
5.6B
0.57
6.25
(continued)
-------
(continued)
PROCESS WATER
a. Steam a_nd boiler feed water required
b . Dirty condensate
c. He than at ion water
1,015
OTHER WATER
a . Dus t control
b. Service, sanitary t potable water ;
Required
Sewage recovered
c . P.e vegetation water
d , Evaporation f rom storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT;
10 Ib/hr
73
1,298
TREATHENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
10 Ib/hr
solids water & sludge
0.005
Harengo, Alabama
(continued)
Energy Totals
Feed
Product and byproduct
Un recovered heat
10 Btu/hr
13.9
Conversion efficiency
73.00*
Disposition oฃ Un re cove red Heat
Direct loss
Designed d_ry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr % wet
0.67
10
10
10" Ib water
Btu/lb evap evap/hr
1,310 0
1,310 0
1,310
1, 310
1, 310
1,310
3.74
547
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
KYGAS PROCESS
SITE: Gibson, Indiana
PRODUCT SIZE: 250 X 10 SCF/day
ENERGY: 10.34 X IO9 Btu/hr
.nalysis (
wt ป as-received)
Moisture
C
H
0
N
S
Ash
10.
68.
4.
7,
1.
2.
6.
.0
2
,6
.6
.1
.1
,4
HHV Calculated
(10 3 Btu/lb)
1,205
COAL FEED
to reactor:
FGD WATER
Vaporized
With eludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
lb/hr
1-1.7 io Btu/hr
0.73
coal
0.29
Lb/lb coal
100
to boiler:
130 10 lb/hr
159 iQa Btu/hr
95.1 10J lb/hr
37.8 IO3 lb/hr
133
IO Lb/hr
54.0 ,10 lb/hr
Bottom ash: dry
water
sludge
Fly ash: dry
vater
sludge
78.8
6.67
0.67
Gibson, Indiana
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Metriajiation water
537
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAi RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
10 lb/hr
solids water E sludge
4.0
0.80
BO
0.5
(continued)
-------
Gibson, Indiana
(continued)
WORK SHEET: WATER QUANTITY CA1/3JLATIONS FOR
HYGAS PROCESS
SITE: Warrick, Indiana
PRODUCT SIZE: 250 x 10& ECF/day
9
ENERGY: 10.34 X 10 Btu/hr
Energy Totals^
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
tO 10 Btu/hr ป wet
Ln Direct loss 3.04 0
Designed dxy ฐ-55 ฐ
Designed wet ฐ-4ฐ 10ฐ
Acid gas rejnoval
regenerator condenser 0.80 10
Total turbine condensers 0.67 100
Total gas compressor
interstage cooling ฐ-17 10ฐ
TOTAL: 5-63
10 Btu/hr
16. 3
10.7
5.6
65.4 s
Btu/lb evap
1,370
1,370
1,370
1,370
1,370
1,370
103 Ib vater
evap/hr
0
0
292
58
489
124
963
Cool Analysis (wt % as-received)
Moisture 9 . 3
c 64.8
H 4.6
0 9.4
N I-2
S 2-4
Ash 8-3
100
HHV Calculated
(103 Btu/lb) 1;L-65
COAL FEED
to reactor: 1,262 10 Ib/hr to boiler:
14 -7 109 Btu/hr
FGD WATER
Vaporized 0.69 Ib/lb coal
With sludge 0.33 Ib/liJ coal
TOTAL:
FGD sludge produced, tfet
ASH HANDLING
10 3 Ib/hr
Bottom ash: dry 107
water 57.6
sludge 16S
Fly ash: dry . 9-01
water 0-9ฐ
sludge 9.91
136 103 Ib/hr
1'58 109 Btu/hr
93.6 lo3 Ib/hr
44.8 io3 Ib/hr
138 103 it/hr
63.9 103 uj/hr
(continued)
-------
Warrtck. Indiana
(continued)
PROCESS WATER
a, Steara and boiler feed water required
b. Di rty condensate
c. Me thanation water
10 Ib/hr
1,434
537
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary a potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAX RAW WATER INPUT TO PLANT:
10 Ib/hr
42
21
2 016
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
10 Ib/hr
solids water & ^sludge
0,05 0.27
0.5
Warrick, Indiana
(continued)
En e rgy
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
16. 3
10.7
Conversion efficiency
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Ib water
10 Btu/Kr
3.03
0.55
0.40
0.80
0.67
0.17
5.62
ป wet
0
0
100
10
100
100
Btu/U) evap
1,370
1,370
1,370
1,370
1,370
1, 370
evap/hr
0
0
292
58
489
124
963
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
HYGAS PROCESS
SITE: Tuscarawas, Ohio
(Ground water and
Mois ture
C
H
0
N
S
Ash
HHV Calculated
(103 Btu/Lb)
COAL FEED
to reactor: 1,140 10 Ib/hr
9
14.7 10 Btu/hr
FGD WATER
Vaporized 0.80 Ib/lb coal
With sludge 0.34 Ib/lb coal
TOTAL:
FGD sludge produced, wet
ASH HANDLING
Bottom ash : dry
water
s ludge
Fly ash: dry
water
sludge
PRODUCT SIZE: 250 X 10 SCF/day
9
ENERGY: 10.34 X 10 Btu/hr
6.3
71.2
4.9
8.1
1.4
2.5
5.6
100
12.90
to boiler: 118 103 Ib/hr
1.52 109 Btu/hr
94.3 lo3 Ib/hr
40.1 103 Ib/hr
134 io3 Ib/hr
57.2 103 Ib/hr
10 3 Lb/hr
65.1
35.1
100
5.28
0.53
5.81
Tuscarawas, Ohio
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Hethaiiation water
1,434
537
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary ฃ potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
10 Ib/hr
101
21
1,600
TREATMENT SLUDGES _
Solids
a. Lime softening 0.86
b. Ion exchange
c. Biotreatment
Ground water
Surface water
0.1
water & sludge
4.3
(continued)
-------
(continued)
ENCPCY
Energy Totals
q
10 Btu/hr
Feed 16.2
Product and byproduct 10.7
Unrecovered neat 5.5
Conversion efficiency 65.7 %
Disposition of Unrecovered Heat
103 U> water
10 Btu/hr % wet Btu/li> evap evap/hr
Direct loss 2-97 0 1,410 0
Designed dry ฐ-s5 0 1,410 0
Designed wet 0.40 100 1,410 284.
regenerator condenser 0-80 10 1,410 57
Total turbine condensers 0.67 10 1,410 46
Interstage cooling 0.17 100 1,410 121
TOTAL: 5.56 510
HYGAS PROCESS
SITE: Jefferson, Ohio PRODUCT SIZE: 2SO x 10 SCF/day
ENERGY: 10.34 X 109 Btu/hr
Coal Analysis (wt % as-received)
Moisture 2. 4
C 71.1
H 4.9
0 5.3
N 1.2
S 5.0
Ash 10.1
100
HHV Calculated
(103 Btu/lb) I3- 10
COM, FEED
to reactor: 1,122 103 Lb/hr to boiler: 112 103 Ib/hr
11-7 109 Btu/hr 1.47 109 Btu/hr
FGD WATER
Vaporized 0.86 Ib/lb coal 96.5 lo3 Ib/hr
With sludge 0.69 Ib/lb coal 77.4 103 Ib/hr
TOTAL: 174 103 Ub/hr
FGD sludge produced, wet 110 103 Ib/hr
ASH HANDLING
103 Ib/hr
Bottom ash: dry 116
water 62.2
sludge 179
Fly ash: dry 9.07
water 0.91
sludge
(continued)
-------
Jefferson/ Ohio
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Hethanation water
1,434
OTHER WATER NEEDS
a. Dust control
b. Service/ sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
10 Ib/hr
37
2,031
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreaunent
10 Ib/hr
solids water & sludge
0.3
0.5
Jefferson, Ohio
(continued)
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
16.2
10.7
5/51
Conversion efficiency
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr ป wet
0.67
10 Ib water
Btu/lb evap evap/hr
1,400 0
1,400
1,400
1,400
1,400
1,400
0
5.51
-------
WORK SHEET: WATER QUANTITY CALCULATIONS TOR
KYGAS PROCESS
Armstrong, Pennsylvania
(continued)
ro
-j
O
SITb: Armstrong, Pennsylvania
Coal Analysis (wt % as-received)
Moisture
C
H
O
N
S
Ash
COAL FEED
to reactor:
KHV Calculated
(103 Btu/lb)
1,09'' 10 Ib/hr
14.7 10' Btu/hr
Vaporized
with sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
P-ฐH Ib/Lb coal
ฐ-39 Lb/lb coal
PRODUCT SIZE: 250 X 10 SCT/day
ENERGY: 10.34 X 10 Btu/hr
73.6
Bottcan ash: dry
water
sludge
Fly ash: dry
water
sludge
13.40
to boiler:
"ฐ 10 Ib/hr
1-47 109 Btu/hr
96-s_ _10 Lb/hr
42-B 103 Ib/hr
J-39 1Q3 Ib/hr
61.1 103 Ib/hr
167
0.85
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Methonation water
OTHER WATER HEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
21
2,096
10 Ib/hr
solids water & sludge
0.1
0.5
(continued)
-------
Armstrong, Pennsylvania (continued)
WORK SHEET i WATER QUANTITY CALCULATIONS FOR
HYGAS PROCESS
SITE: Fayette, West Virginia PRODUCT SIZE: 250 x 10 SCF/day
Energy Totals
IO9 Btu/hr
Feed 16.2
Product and byproduct 10.7
Unrecovered heat ^-^
Conversion efficiency 65.9 %
Disposition of Unrecovered Heat
10 Ib water
10 Btu/hr % wet Btu/lb evap evap/hr
tj Direct loss 2-ซ 0 1,410 0
-J Designed dry ฐ-55 ฐ i'410 ฐ
*~ Designed wet ฐ-4ฐ 10ฐ L410 28<
Acid gas removal
regenerator condenser ฐ-Bฐ 1ฐ l'410 57
Tot*l turbine condensers 0.67 100 1,410 475
Total gas compressor
Jnterstaoe coolinq ฐ-" 10ฐ i'410 121
TOTAL: 5.51 937
ENERGY: 10.34 X IO9 Btu/hr
Coal Analysis (wt \ as-received)
Moisture 3.0
C 78.5
H 4.6
0 3.7
N 1.4
S 0.8
Ash 8-ฐ
100
HHV Calculated
(IO3 Btu/lb) 14.00
COAL FEED
to reactor: 1,050 io3 Ib/hr to boiler: 106 io3 rb/hr
14.7 10 Btu/hr 1.4B IQ Btu/hr
FGD WATER
Vaporized 0.91 lb/lb coal 96.2 103 Lb/hr
With sludge 0.11 lb/lb coal H-6 Io3 Ib/hr
TOTAL: 108 103 ib/hr
FGD sludge produced, wet 16.6 ^Q Ib/hr
ASH HANDLING
IO3 Ib/hr
Bottom ash: dry 85.7
water 46.1
sludge 132
Fly ash: dry 6.77
water 0.68
sludge 7.45
(continued)
-------
Fayette, West Virginia
(continued)
Fayette, West Virginia (continued)
PROCESS WATER
to
-J
to
a. Steam and boiler feed water required
b. Dirty condensate
c. Hethajnation water
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLODGES
a. Lime softening
b. Ion exchange
c. Biotreatment
1,434
537
2,032
10 Ib/hr
solids water & sludge
0.1 0.3
80
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
,.9
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
TOTAL:
0.67
0.17
10
100
10 Btu/hr
16.2
10.7
5.5
10 Btu/hr % wet Btu/Ib evap
2.93 0 1,360
0.55 0 1,360
1,360
1,360
1,360
1,360
10 Ib water
evap/hr
59
125
971
-------
HORK SHEET: WATER QUANTITY CALCULATIONS FOR
HYGAS PROCESS
Honongalia, West Virginia (continued)
SITE: Monongalia, West Virginia
PRODUCT SIZE: 250 x 10 ECF/day
ENERGY: 10.34 x 109 Btu/hr
KJ
^J
OJ
Coal Analysis (wt ป as-received)
Moisture 3 . 1
C 78.8
H 4.9
0 4.2
N 1-5
S 1-1
Ash 6.4
100
HHV Calculated
(103 Btu/lb) I4-20
COAL FEED
to reactor: 1,035 10 Ib/hr to boiler:
14.7 109 Btu/hr
FCD WATER
Vaporized 0.92 Ib/lb coal
With sludge 0.15 Lb/lb coal
TOTAL:
FGD sludge produced, wet
ASH HANDLING
103 Ib/hr
Bottom ash: dry 67.6
water 36-4
sludge 104
Fly ash: dry 5- 34
water ฐ-53
sludge 5-87
104 103 Ib/hr
1.48 io9 Btu/hr
95.9 io3 Ib/hr
15.6 JO3 Ib/hr
112 IO3 Ib/hr
22.3 IO3 Ib/hr
PROCESS WATER
o. Steam and boiler feed water required
b. Dirty condensate
c. Methanation water
OTHER WATER NEEDS
a. Dust control
b. Service, sajiitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchajige
c. Biotreatment
1,577
10 Ib/hr
solids water S sludge
0.02
0.11
(continued)
-------
Monongalia, West Virginia (continued)
WORX SHEET: WATER QUANTITY CALCULATIONS FOR
HYGAS PROCESS
SITE; Mingo, West Virginia
PRODUCT SIZE: 250 X 10 SCF/day
ENERGY: 10.34 X 1Q9 Btu/hr
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
10 Btu/hr
16.2
10.7
5.S
65.9 ป
Direct loss
Designed dry
Designed wet
Acid"gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr
2.93
0.67
Btu/Lb evap
1,380
1,380
1,380
1,380
1,380
1,380
10 Ib water
evap/hr
520
Moisture 2-2
C 79.5
H 5.2
0 5.9
M I-"
S 0.9
Ash 4-9
100
HHV Calculated
(103 Btu/lb) 14.30
COAL FEED
to reactor: 1,028 10 Ib/hr to boiler:
14.7 109 Btu/hr
FGD WATER
Vaporized 0.94 Ib/lb coal
With sludge 0.12 Lb/Lb coal
TOTAL:
FGD sludge produced, wet
ASH HANDLING
103 Lb/hr
Bottom ash: dry 51.4
water 27.7
sludge 79.1
Fly ash: dry 4.03
water 0.40
sludge 4.43
103 103 Ib/hr
i-47 109 Btu/hr
96 -6 io3 Lb/hr
12-3 103 Lb/hr
109 103 Lb/hr
17-6 103 Lb/hr
(continued)
-------
MInge ,_ We3 t Vi rgini_a.
(continued)
Mingo, West Virginia
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Hethanation water
OTHER WATER NEEDS
a.
b.
c.
d.
TRE
a.
b.
Dust control
Service, sanitary fi potable water:
Required
Sewage recovered
Evaporation from storage ponds
GRAND TOTAL RAH WATER INPUT TO PLANT:
1ATMZNT SLUDGES
Lime softening
Ion exchange
103 Ib/hr
1,434
537
ieo
103 Ib/hr
34
21
14
0
0
1,507
10 3 Ib/hr
solids water G sludge
0.03 0.17
80
ENERGY
Energy Totals
Feed
Product and byproduct
Conversion efficiency
Disposition of Unrecovered Heat
9
10 Btu/hr ป wet
Designed dry 0.55 0
Designed wet 0.40 100
Acid gas removal
regenerator condenser 0.80 10
Total turbine condensers 0.67 10
Total gas compressor
interstage cooling 0.17 100
TOTAL: 5.51
109 Btu/hr
16.2
10.7
5.5
65.9 \
10 Ib water
Btu/lb evap evap/hr
1,360 0
1,360 0
1,360 294
1,360 59
1,360 49
1,360 125
527
c. Biotreatment
0.1
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
HYGAS PROCESS
SITE: Gillette, Wyoming
PRODUCT SIZE: 250 X 10 SCF/dsy
ENERGY: 10.34 x IO9 Btu/hr
Coal Analysis (wt ^ as-received)
Mois ture
C
H
O
s
Ash
HHV Calculated
UO Btu/lb)
COAL FEED
to reactor:
FCD WATER
1,538 io
12.2
10 Btu/hr
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0-24 Ib/Ib coal
0-10 Lb/Ib coal
30.4
0.1
100
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
to boiler:
10 lฑ>/hr
124
17.1
249 IO3 Ib/hr
IO Btu/hr
59-7 IO3 Ib/hr
24-9 IO3 Ib/hr
84-6 IO3 Ib/hr
35-5 IO3 Ib/hr
Gillette, Wyoming
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Methanation water
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
1,267
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
solids water & sludge
1.2 6.0
0.2
52
1.0
(continued)
-------
i 11 pt- t-f . Mynmi ng
(continued)
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
14.2
10.1
4.1
Conversion efficiency
71.5 ป
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gaLS removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr t wet
1.45 0
0.55
50
10 It water
Btu/lb evap evap/hr
1,401 0
1,401 0
1,401
1,401
1,401
1,401
286
4.04
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
HYGAS PROCESS
SITE: Antelope Creek, Wyoming
PRODUCT SIZE: 250 X 10 SCF/day
EKERGY: 10.34 x 109 Btu/hr
Coal Analysis (wt % as-received)
Moisture 26.2
C 52.6
H 3-6
O 12.0
N 0-6
S 0.5
Ash 4.5
COAL FEED
to reactor:
HHV Calculated
(103 Btu/lb)
1,353 1Q3 Ib/hr
12-2 10 Btu/hr
FGD WATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.35 lb/lb coal
0.07 li/lb coal
9-ฐฐ
to boiler:
202 IP"1 Ib/hr
I-82 10 Btu/hr
70.B 10J
14-2 10 Ib/hr
84.9 iQ3 li/n,-
20-2 103 IJb/hr
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
62.7
96-5
7-2a
ฐ-73
(continued)
-------
Antelope Creek, Wyoming
(continued)
Antelope Creek, Wyoming (continued)
PROCESS HATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Methanation water
OTHER WATER MEEDS
a. Dust control
b. Service, sanitary & potable water:
IV) Required
03 Sewage recovered
c. Reve^etation water
d. Evaporation from storage ponds
GRAND TOTAL RAH WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Siotreatment
d. Electrodialysis
1,015
200
10 Lb/hr
59
Energy Totals
1,359
10 lb/hr
solids water & sludge
0.02 0.08
52
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
10 Btu/hr
14.0
Disposition of Unrecovered Heat
10 Lb water
10 Btu/hr % wet Btu/lb evap evap/hr
Direct loss
Designed dry
Designed wet
Acid gag removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
1.30
0.67
0.17
3.89
50
1,397
1,397
1,397
1,397
1,397
1,397
57
452
135
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
WYGAS PROCESS
SITE: Belle Ayr, Wyoming
PRODUCT SIZE: 250 x 10 SCF/day
ENERGY: 10.34 X 1Q9 Btu/hr
Coal Analysis (wt \ as-received)
Moisture 21.7
C 54. 3
H 3.9
0 13.2
N 0.9
S 0.5
Ash 5.5
HHV Calculated
(103 Btu/lb)
COAL FEED
to reactor:
FGD WATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
1,308 1QJ Ib/hr
12.2 1Q9 Btu/hr
Lb/Ib coal
0.069 Ib/lb coal
9.31
to boiler:
10 Ib/hr
109 Btu/hr
78-ฐ 103 Ib/hr
12-8 103 Ib/hr
91 103 Ib/hr
I" 103 U)/hl
Bottom ash: dry
water
sludge
Fly ash: dry
water
Bludge
0.82
Belle Ayr, Wyoming
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
C. Methanation water
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary t potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
10 Ib/hr
57
1,380
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
10 Ib/hr
solids water & sludge
1.3 6.5
52
(continued)
-------
{continued)
WORK SHEET: HATER QUANTITY CALCULATIONS FOR
bYGAS PROCESS
SITE: Hanna Coal Fid., Wyoming
PRODUCT SIZE: 250 X 10 SCT/day
ENERGY: 10.34 x 109 Btu/hr
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
10 Btu/hr
13.9
3.8
ro
00
O
Direct loss
Designed dry
Designed wet
Acid gas removal
Total turbine condensers
109
i
0
0
0
0
Btu/hr
.21
.55
.40
.80
.67
ป wet
0
0
100
10
10
Btu/lb evap
1
1
1
1
1
,401
,401
,401
,401
,401
10 Ib water
evap/>ir
0
0
286
57
48
Total gas compressor
interstage cooling
0.17
50
1,401
452
Coal Analysis (wt % as-received)
Moisture
C
H
O
N
S
Ash
HHV Calculated
(103 Btu/lb)
COM. FEED
to reactor i 1,143 10 Ifc/hr
12.2 109 Btu/hr
60.5
12.5
100
FGD HATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.60 Lb/Lb coal
0.15 Lb/lb coal
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
to boiler:
10 Ib/hr
1.53 10 Btu/hr
66.1 1Q3 Ib/hr
21.5 1Q Ib/hr
10 Ib/hr
108
30-S IQJ Ib/hr
10 Lb/hr
94.9
9.30
0.93
10.2
(continued)
-------
Hanna Coal Fid., Wyoming
(continued)
Hanna Coal Fjj., Wyoming (continued)
NJ
CO
PROCESS WATER
a. Stearo and boiler feed water required
b. Dirty condensate
c. Methanation water
OTHER WATER MEEDS
a. Dust control
b. Service, sanitary 6 potable water:
Required
Sewage recovered
c. Ravagetation water
d . Evaporation f rom s torage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMEirr SLUDGES
a. Lime eoftening
b. Ion exchange
c. BiotreaCment
10 Ib/hr
1,015
1,750
1.33
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of__ Umrecovered Heat
10 Btu/hr
13,7
73.7
9
10 Btu/hr % wet Btu/lb evap
10 Ib water
evap/hr
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
1.01
0.55
0.40
0.80
0.67
0
0
100
10
100
1,397
1,397
1,397
1,397
1,397
0
0
286
57
480
ฐ-17
3 60
1,397
122
945
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
IfYGAS PROCESS
SITE: Decker, Montana
PRODUCT SIZE: 250 x 1Q SCF/day
ENERGY: 10, 34 X 10 Btu/hr
Coal Analysis (wt * as-received)
Moisture
C
H
O
N
S
Ash
100
03 HHV Calculated
(103 Btu/lb)
COAL FEED
to reactor: 1,265 lo3 lb/hr
12.2 lo9 Btu/hr
TCD WATER
Vaporized 0.42 Ib/lb coal
With sludge 0.07 Ib/lb coal
TOTAL:
FGD sludge produced, wet
ASH HANDLING
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
9.48
to boiler: 18& 103 lb/hr
1.76 io9 Btu/h:
78.0 103 lb/hr
13-0 IO3 lb/hr
91-0 IO3 lb/hr
18-6 IO3 li/hr
IO3 lb/hr
48.9
26.3
75.3
5.50
0.55
6.05
Decker, Montana
(continued)
PROCESS WATER
a. Steam arid boiler feed water required
b. Dirty condensate
c. Methanation water
1,015
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary 6 potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT!
10 lb/hr
67
1,900
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
d. Electrodialysis
10 Ib/hr
solids water & sludge
0.05
0.3
1.0
(continued)
-------
DecXer, Montana
(continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
HYGAS PROCESS
Energy Totals
10 Btu/hr
SITE: East Hoorhead, Montana
Coal Analysis (wt \ as-received)
PRODUCT SIZE: 250 x 1Q6 EOT/day
ENERGY: 10.34 x 1Q9 Btu/hr
Feed j 3 q
Product ajid byproduct 10.1
Unrecovered heat 3.6
Conversion efficiency 72.5 1
Disposition of Unrecovered Heat
2 9 103 Lb water
10 Btu/hr % wet Btu/lb evap evap/hr
Direct loss 1.24 0 1,407 0
Designed dry 0.55 0 1,407 0
Designed wet 0.40 100 1,407 284
Acid gas removal
regenerator condenser 0.80 10 1,407 57
Total turbine condensers 0.67 100 1,407 476
Total gas compressor
interstage cooling 0.17 100 1,407 121
TOTAL: 3.83 938
Moisture 36 . 1
C 42.4
H 2.8
0 11.4
H 0.7
S 0.6
Ash 6.2
100
HHV Calculated
(103 Btu/lb) 7-04
COAL FEED
to reactor: 1,730 103 lb/hr to boiler: 308 1Q3 Lb/hr
12.2 109 Btu/hr 2.17 109 Btu/h
FGD WATER
Vaporized 0.13 lb/Lb coal 40 . 1 103 1:b^hr
With eludge ฐ-08 lb/lb coal 24.7 103 n,/^
TOTAL: 64.7 103 ]^fhr
FGD sludge produced, wet 35.2 ^n3 Lb/hr
ASH HANDLING
103 Lb/hr
Bottom ash:dry 111
water 59 . 8
sludge 171
Fly ash: dry 15.3
water 1.53
sludge 16.8
(continued)
-------
d5 c Moorhead, Montana (continued)
East Moorhead, Montana (continued)
KJ
CO
PROCESS WATER
a. Sneam ajid boiler feed water required
b. Di rty condensate
c. Hethanation water
OTHER WATER HEEDS
a. Dust control
b. Service , sanitary & pota_ble water;
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER IKPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
103 Lb/hr
1,015
296
200
103 lb/hr
95
21
14
0
5
1,263
103 lb/hr
solids water 6 sludge
1.2 6.0
52
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
10 Btu/hr ป wet
Direct loss 1.65 0
Designed dry 0.55 0
Designed wet 0-40 100
Acid gas removal
regenerator condenser 0.80 10
Total turbine condensers 0.67 10
Total gas compressor
interstage cooling ฐ-17 50
TOTAL: 4-24
9
10 Btu/hr
14.4
10.1
4. 24
70.5 %
Btu/Lb evap
1,407
1,407
1,407
1,407
1,407
1,407
103 Ib water
evap/hr
0
0
284
57
48
60
449
-------
WORK SKEET: WATER QUANTITY CALCULATIONS FOR
KYGAS PROCESS
Colstrip, Montana
(continued)
NJ
03
Ln
SITE: Colstrip, Montana
Coal Analysis (wt % as-received)
Mois ture
C
COM. FEED
to reactor:
H
0
N
S
Ash
HHV Calculated
(103 Btu/lb)
1,161 IQ] u,/hr
y
12.2 10 Btu/hr
FGD HATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.37 Ib/Lb coal
0.06 Lb/lb coal
PRODUCT SIZE: 250 x 10 SCF/day
ENERGY: 10.34 x 109 BtuAir
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
to boiler:
202 10 Ib/hr
1.80 10 Btu/hr
74.8 10 Ib/hr
12.1 10 Ib/hr
B6.9 103 Ib/hr
17.3 1Q3 Ib/hr
10 Lb/hr
97.1
52.3
11.2
1.12
12.3
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Methanation water
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary s potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAH WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
bo Ion exchange
c. Biotreatment
1,015
water S sludge
Q.003
52
1.0
(continued)
-------
Costnp, Montana
(continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
HYGAS PROCESS
SITE: El Paso, New Mexico
PRODUCT SIZE: 250 X 10 SCT/day
ENERGY: 10.34 X 10 Btu/hr
Energy Totals
10 Btu/hr
Feed 14.0
Product and byproduct 10.1
Unrecovered heat 3.9
Conversion efficiency 72.3 \
Disposition of Unrecovered Heat
9 103 Ib water
10 Btu/hr % wet Btu/Ib evap evap/hr
Direct loss 1.28 0 1,414 0
Designed dry 0.55 0 1,414 0
Designed wet 0.40 100 1,414 283
regenerator condenser 0.80 10 1,414 57
Total turbine condensers 0.67 10 1,414 47
interstage cooling 0.17 100 1,414 120
TOTAL: 3-87 507
Coal Analysis (wt \ as-received)
Moisture !6 . 3
c 49.2
H 3.6
0 10-2
N ฐ-fl
S 0.7
Ash !9-2
100
HHV Calculated
(103 Btu/lb) 8-62
COAL FEED
to reactor: 1,413 103 Ib/hr to boiler: 193 103 Ib/hr
12 -2 109 Btu/hr 1'66 109 BtuA'r
FGD WATER
Vaporized 0.42 Ib/lb coal 80.9 103 Ib/hr
With sludge 0.10 Ib/lb coal 19.3 1Q3 Ib/hr
TOTAL: 100 103 Ib/hr
FGD sludge produced, wet 27.5 10 Ib/hr
ASH HANDLING
103 Ib/hr
Bottom ash: dry 279
water ISO
sludge 429
Fly ash: dry 29.6
water 2.96
sludge 32.5
(continued)
-------
El Paso, New Mexico
ppf/JESS WATER
10 ib/hr
a. St<-aja a/id boiler fef-d water required 1,015
b Dirty rondf-naate nh
<-. M'jthination wat'-r 20ฐ
ryrHEH WATER NEEDS
103 ib/hr
a. Dust control 84
b ^<-rvicc -anitar t jtarle
Required 21
j 14
CKAJID TCTIAL RAW WATEK IlfflJT TO PLAIfT: 1,436
T(
-------
WORK SHEET: HATER QUANTITY CALCULATIONS FOR
HYGAS PROCESS
Gallup, New Mexico
(continued)
NJ
CO
CO
SITE: Gallup, New Mexico
Coal Analysis (wt % as-received)
Mois ture
C
H
O
S
Ash
HHV Calculated
(103 Btu/lb)
COAL FEED
,3
to reactor:
FGD WATER
10
I2-2 109 Btu/hr
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.61 Ib/lb coal
0,06 Ib/lb coal
PRODUCT SIZE; 250 x 10 SCF/day
ENERGY: 10.34 X 1Q9 Btu/hr
4.7
5.1
100
11.30
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
to boiler:
140 IP"1 Ib/hr
1-5S 109 Btu/hr
85.3 10 Ib/hr
8.39 103 Ib/hr
93.7 103 li/hr
12.0 10 Ib/hr
5.70
0.57
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Methanation water
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary 6 potable water:
Required
Sevage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
d. Electrodialysis
10 Ib/hr
1,015
1,412
solids
0.02
vater & sludge
0.11
52
137
6.27
(continued)
-------
Gallup, New Mexico (continued)
Energy Totals
109 Btu/hr
Feed 13.B
Product and byproduct 10.1
Unrecovered heat 3 . 7
Conversion efficiency 73.5 %
Disposition of Unrecovered Heat
g
10 Btu/hr % wet Btu/Lb evap evap/hr
NJ Direct loss 1.06 0 1,375 0
lQ Designed dry 0.55 0 1.375 0_
Designed wet O."0 1-00 1,375 291
Acid gas removal
regenerator condenser 0-80 10 1,375 58
Total turbine condensers ฐ-&7 !ฐ 1,375 49
Total gas compressor
interstage cooling
3.65
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
BIGAS PROCESS
PRODUCT SIZE: 250 X 10ฐ EOF/day
ENERGY: 9.9 x 10 Btu/hr
to
O
Coal Analysis (wt ป as-received)
Moisture
C
H
O
N
S
Ash
HHV Calculated
COAL FEED
to reactor:
bituminous
lignite
FGD HATER
Vaporized
With sludge
TOTAL:
FGD Bludge produced, wet
ASH HANDLING
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
Tables 3-18, 3-19
100
to boiler:
Table A4-5
Table A4-5
_10 Ib/hr
103 Ib/hr
_10 Ib/hr
103 Ib/hr
Ib/hr
Appendix 6
(continued)
-------
(continued)
(continued)
PROCESS WATER
ID3 Ib/hr
a. Steam and boiler feed water required Tabj.e A4-4 (steajti to gaaifier)
b. Dirty water input Table A4-4 (water to quench L water to slurry coal)
c. Di r ty condensate
d, M^'thanation water
Table A4-4
Table A4-4
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
Calculated
9.9
Table A4-5
OTHEK WATTR NEEDS
Conversion efficiency
Table A4-5
a. DTJSt control
b. Sen/ice, sanitary & potable water:
Requi red
Sewage recovered
c. Kevegeta tion water
d. Evaporat ion from a torage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
T H F.A TM rjrr s Ij
Disposition of Unrecovered Heat
Appendix 11
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr % wet
Table A4-6
Table A4-6
Table A4-6"
10 lb water
Btu/lb evap evap/hr
a. Lime aof tening
b, Ion excha/ige
Appendix 11
*Slag quench and wet cooljng in the process
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
BIGAS PROCESS
PRODUCT SIZE: 250 x .10 SCF/day
(Illinois river water and ^^ ; g ^ ^ ^ 8(;u/hr
we 1 1 water )
Moisture 16.1
C 60.1
H 4.1
0 8.3
N 1.1
S 2.9
Ash 7.4
100
HHV Calculated
(103 Btu/lb) 10.76
COAL FEED
to reactor: 1,170 10 Ib/hr to boiler: 151
12.6 109 Btu/hr 1-62
FGD WATER
Vaporized 0.57 Ib/Lb coal 86.1
With sludge 0.40 Ib/lb coal 60.4
TOTAL: 146
FGD sludge produced, wet 86.3
ASH HANDLING
10 3 Ib/hr
Bottom ash: dry 88.8
water 47.3
sludge I"
Fly ash: dry B-94
water O-8'
sludge 9-83
10 3 J-b/hr
109 Btu/hr
10 3 Ib/hr
10 3 Ib/hr
10 3 Ib/hr
103 Ib/hr
Bureau, Illinois
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty water input
c. Dirty condensate
d. Methanation water
1,193
890
OTHER MATER NEEDS
a. Dust control
b. Service, sanitary fi potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW HATER INPUT TO PLANT:
106
21
2,151
TREATMENT SLUDGES
a. Lima softening
b. Ion exchange
Well water
Illino
solids
water & sludge
0.3
11
(continued)
-------
bureau, Illinois
(continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
BIGAS PROCESS
N >
O)
OJ
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
10 Btu/hr
14.2
Direct loss
Designed d^y
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total ga3 compressor
interstage cooling
10 Btu/hr % wet
1 .00 0
10 Lb water
3tu/lb evap evap/hr
1, 390 _ 0
1, 390
1,390
1,390
1, 390
0_
281
820
1, 390
1, 338
SITE. Shelby, Illinois
Coal Analysis (wt * as-received)
Moisture
C
H
0
N
S
Ash
COAI. FEED
to reactor:
HHV Calculated
(LO3 Btu/Lb)
3
10
12.5 10 Btu/hr
O.SS
Vaporized
With sludge
TOTAL.:
FCD sludge produced, wet
ASH HANDLING
_Lb/Lb coal
Lb/Lb coal
PRODUCT SIZE: 250 x .10 SCF/day
ENERGY: 9.9 x 109 Btufttl
13.9
7.2
14.5
to boiler:
10 Ib/hr
1.61 10 Btu/hr
lb/hr
67-9 103 Lb/hr
155 _ 10 3 Lb/hr
97.1 103 Lb/hr
Bottom ash: dry
water
3ludge
Fly ash: dry
water
sludge
10 Lb/hr
183
(continued)
-------
Shelby, Illinois
(continued)
Shelby, Illinois
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty water input
c. Dirty condensate
d. Metlhanation water
10 Ib/hr
410
1,273
9 SO
234
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
OTHER WATER REEDS
Conversion efficiency
70.2%
a. Dust control
b. Service, sanitary G. potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponda
GRAND TOTAL RAW HATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
Disposition of Unrecovered Heat
21
0
1,355
solids
water & sludge
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
TOTAL:
10 Btu/hr ป wet Btu/lb evap
10 Ib water
evap/hr
0.98
0.32
0.42
1.02
1.14
0.33
4.21
0
0
100
0
10
50
J
1
1
1
1
1
,390
,390
,390
,390
,390
,390
0
0
302
0
82
119
503
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
BIGAS PROCESS
Vigo, Indiana
(continued)
SITE: Vigo, Indiana
Coal Analysis (wt * as-received)
Moisture
C
H
O
N
S
Ash
HHV Calculated
(Id3 Btu/lb)
COAL FEED
to reactor:
FGD WATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
1,111 103 Ib/hr
9
12.5 10 Btu/hr
_lb/Ib coal
Ib/lb coal
PRODUCT SIZE: 250 x .10 SCF/day
9
ENERGY: 9.9 X 10 Btu/hr
16.2
11.26
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
to boiler:
143
10 Ib/hr
87.8
47.3
135
10
1.61 10 Btu/hr
84.4 10 Ib/hr
12.9 10 Ib/hr
97.2 103 Ib/hr
18.4 103 Ib/hr
PROCESS WATER
a. Steajn and boiler feed water required
b. Dirty water input
c. Dirty condensate
d. Methanation water
OTHER HATER NEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
410
1,147
841
234
water ฃ sludge
4 0
(continued)
-------
Vigo, Indiana
(continued)
WORK SHEET: HATER QUANTITY CALCULATIONS FOR
BIGAS PROCESS
SITE: Kerranerer, Wyoming
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr % wet
0.98 0
0.36
0. 39
100
0.33
100
10 Btu/hr
1-1.1
70.2
Btu/lb evap
1,390
1,390
1,390
1,390
1,390
1,390
10 Ib water
evap/hr
820
237
1,338
PRODUCT SIZE: 250 x .10 SCF/day
ENERGY: 9.9 x 1Q9 Btu/hr
Moisture 2.8
C 71.8
H 5.0
O 9.0
N 1-2
s i.o
Ash 9.2
100
HHV Calculated
(103 Btu/lb) 12.88
COAL FEED
to reactor: 981 10 Ib/hr to boiler: 113
9
1.2.6 10 Btu/hr 1.46
FGD WATER
Vaporized 0.8-1 Ib/lb coal 94.9
With sludge 0.14 Lb/lb coal 15.8
TOTAL: m
FGD sludge produced, wet 22.6
ASH HANDLING
10 Ib/hr
Bottom ash: dry 92.3
water 49.7
sludge 142
Fly ash: dry 3.32
water 0.83
sludge 9.15
103 Ib/hr
109 Btu/hr
103 Ib/hr
10 3 Ib/hr
103 Ib/hr
103 Ib/hr
(continued)
-------
Kemmere^r, Wyoming
(cont inued)
PROCESS WflTTH
a. Steam and boiler feed water required
b. Dirty water input
c. Dirty condensate
d. Me thanation wate r
10" Ib/hr
OTKER WATER KEEPS
a . Dust control
b. Service, sanitary & potable water:
Re q u i r e d
Sewage re cove red
c. Revegetation water
d . Evaporation f rom storage ponds
GRAND TOTAL RAH WATLR INPUT TO PLANT:
TR11ATMHNT SLUDGES
a. - Lj_me softening
b. Ion exchange
10" Lb/hr
solids water & sludge
Kemmerer, Wyoming
(continued)
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10" Btu/hr
14.1
4.05
Conversion efficiency
Disposition of Unrecovered Heat
10' Ib water
Direct loss
Designed dry
Designed wet
Acid gas rejnoval
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
TOTAL:
10 Btu/hr
0.81
0.36
0.39
1.02
1.14
0.33
4.05
t wet
0
0
100
0
10
100
Btu/lb evap
1,397
1,397
1,397
1, 397
1, 397
1,397
evap/hr
0
0
279
0
82
236
597
-------
WORK SHEET: HATER QUANTITY CALCULATIONS FOR
BIGAS PROCESS
Slope, North Dakota
(continued)
tv)
VD
CD
SITE: Slope, North DaJcota
Coal Analysis (wt % as-received)
Hois ture
C
H
O
N
S
Ash
HHV Calculated
COAL. FEED
PRODUCT SIZE: 250 x 10 SCF/day
ENERGY: 9.9 x 1Q9 Btu/hr
100
to reactor:
FGD WATER
Vaporized
With sludge
TOTAL;
FGD sludge p
ASH HANDLING
?.ie
12. ;
Q_
:d,
(10 8tu/lb) S.62
y 10 Ib/hr to boiler: 514
q
i 10 Btu/hr 2.B9
,nfiซllb/lb coal 0
, ?s Ib/lb coal 129
129
wet 184
10 Ib/hr
103 lฑ>/hr
q
10 Btu/hr
103 Lb/hr
10 3 IbAr
3
10 Ib/hr
10 3 Ib/hr
Bottom ash: dry 152
Fly
water 81.8
sludge 234
a-sh: dry 27.6
water 2.75
sludge 30. 3_
PROCESS HATER
a. Steam and boiler feed water required
b. Dirty water input
c. Dirty condenaate
d. Methanation water
OTHER HATER HEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
10 Ib/hr
691
1,410
solids
wajier & sludge
(continued)
Due to large n-oistuxe content of coal; treat as ze
-------
5 loฃe , Noj^
(continued)
E_ne_rgy Totals
Feed
Product and byproduct:
Unrecovered heat
10 Btu/hr
15.1
9.9
Conversion efficiency
66.0 *
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Tota1 turbine condensera
Total gas compressor
inters taga cooling
10 Btu/hr % wet
10 Ib water
Btu/Ib evajJ evap/hr
1.55
0.49
0.56
1.02
1.14
0
0
100
0
10
1,417
1.417
1,417
1,417
1,417
0
0
395
0
80
0.33
1,417
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
BIGAS PROCESS
SITE: Center, North Dakota
PRODUCT SIZE: 250 x 10 SCF/day
ENERGY: 9.9 X 1Q9 Btu/hr
Coal Analysis (wt % as-received)
Moisture
C
H
0
N
S
Ash
HHV Calculated
(103 Btu/Lb)
COAL FEED
to reactor:
1,814 10 Lb/hr
12.2 109 Btu/hr
FGD HATER
Vaporized 0.10 Ib/lb coal
With sludge 0.12 Ib/lb coal
TOT AX. :
FGD sludge produced, wet
ASH HANDLING
36.2
39.9
11.0
100
to boiler:
378
10 Ib/hr
2.54 10 Btu/hr
37.8 10 Ib/hr
-15.4 10 Lb/hr
Bi.2 1C) Lb/hr
64. B 10 Lb/hr
Bottom ash : dry
water
sludge
Ply ash: dry
water
Bludge
87.5
(continued)
-------
Center, North DaXota
(continued)
Center, North Dakota
(continued)
to
O
O
PROCESS WATER
a. Steam and boiler feed water requi red
b. Dirty water input
c. Dirty condensate
d. He thanation wate r
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary fi potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW HATER IKPUT TO PLANT:
TREATMENT SLUDGES
Energy Totals
a. Lime softening
b. Ion exchange
l'377
10 3 Ib/hr
21
14
1,401
3
solids water & sludge
0 0
29
Feed
Product and byproduct
Conversion efficiency
Disposition of Unrecovered Heat
9
10 Btu/hr % wet
Direct loss l . 20 0
Designed dry 0.49 0
Designed wet 0.56 100
Acid gas removal
regenerator condenser 1.02 0
Total turbine condensers 1. 14 10
Total gas compressor
interstage cooling 0.33 50
TOTAL: 4.74
10 Btu/hr
14.7
9,9
67.6 %
10 Ib water
Btu/lb evap evap/hr
1,420 0
1,420 0
1,420 394
1,420 0
1,420 80
1,420 116
590
-------
WORX SHEET: WATER QUANTITY CALCULATIONS FOR
BIGAS PROCESS
Scranton, North Dakota
(continued)
LO
O
SITE: Scranton, North Dakota
Coal Analysis (wt \ as-received)
Moisture
C
H
O
H
S
Ash
HHV Calculated
COAX FEED
to reactor:
FGD WATER
Ib/hr
12. 2 109 Btu/hr
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.04 lb/ lb coal
0.18 Ib/lb coal
PRODUCT SIZE: 250 x 10 SCF/day
ENERGY: 9.9 X 1Q9 Btu/hr
38.2
Bottom ash: djry
water
sludge
Fly ash: dry
wate r
sludge
6-43
to boiler:
415 103 Ib/hr
9
2.67 10 Btu/hr
15.6 10 Lb/hr
74.7 10 Ib/hr
91.3 10 Ib/hr
106.7 10 Ib/hr
10 Ib/hr
149
80.0
229
24.9
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty water input
c. Di rty condenaate
d. Methanation water
OTHER HATER NEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAH WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
10 Ib/hr
691
10 Ib/hr
126
1,419
solids
water & sludge
0.27 1.4
(continued)
-------
Scra_nton, North Dakota
(continued)
ENERGY
Energy Totals
9
Feed 14,9
Product and byproduct 9f9
Unrecovered heat 5 0
Disposition of Unrecovered Heat
i^j 10 Ib water
O 10 Btu/hr * wet Btu/Lb evap evap/hr
ro
Direct loss 1.33 0 1,417 0
Designed dry 0.49 0 1,417 0
Designed wet 0.56 100 1,417 395
Acid gas removal
regenerator condenser 1.02 0 1,417 0
Total turbine condensers 1.14 10 1,417 80
Total gas compressor
interstage cooling 0.33 50 1,417 116
TOTAL: 4 87 591
BIGAS PROCESS
SITE: Chupp Mine, Montana PRODUCT SIZE: 250 x 10& SCF/day
ENERGY: 9.9 x 109 Btu/hr
Moisture 38.3
C 40.4
H 2.5
0 10.6
N 0.6
S 0.3
Ash 7.3
100
HHV Calculated
(103 Btu/Lb) 6.60
COAL FEED
to reactor: 1,840 llr.
ASH HANDLING
103 Lb/hr
Bottom ash: dry 140
water 75.4
sludge 215
Fly ash: dry 23.0
water 2.30
sludge 35.3
(continued)
-------
Ch upp Mine, Montana
(continued)
Chupp Mine, Montana
(continued)
PROCESS WATER
a . Steajn and boi ler feed water requi red
b, Dirty water input
c. Dirty condensate
d. He thanation wate r
10 Ib/hr
Energy Totai
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
14.7
OTHER WATER HEEDS
Conversion efficiency
O
a. Du5 t contro1
b. Service, sanitary ฃ potable water
Required
Sewage recovered
c. Revegetation water
d. Evaporation from s torage ponds
GRAND TOTAL PJ\W WATER IWPUT TO
TREATHQrr SLUDGES
a. Lime softening
b. Ion exchange
water s sludge
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condenaers
Total gas compressor
interstage cooling
10 lb water
Btu^/lb evap evap/hr
0.56
100
1,417
1,433
-------
HORX EHEETi WATER QUANTITY CALCULATIONS FOR
SYVTHAKE PROCESS
SITE,
PRODUCT SIZEi 250 x 10* SCF/day
ENERGYi 9.79 x 109 Btu/hr
Coal Analysis (wt > as-received) Char Analysis (wt %]
Table A5-11
100
U)
O
HHV Calculated
3
(10 Btu/lb)
COAI. FEED TO REACTOR:
Table A5-4
Calculated 109 Btu/hr
FGG WATER
Va
With
TOTALi
PGD sludge produced, wet
ASH HANDLING
Vaporized ^ Last 2 paragraphs
f inAppendix 5
With sludge ) Also Appendix 8
Bottom ash: dry
water
sludge
Fly ash: dry
water
eludge
CHAR FEED TO BOILER i
9
Calculated 10 Btu/hr
Table A5-10
_10 Ib/hr
103 Ib/hr
Calcd. 10 Ib/hr
103 Ib/hr
10 Ib/hr
(continued)
-------
(continued)
(continued)
PROCESS WATER
U)
O
tn
a. Steam to gaaifier & shift converter
t>. Dirty condensate (after scrub)
c. Kedium gua-lity condensata *
d. Kethanation water
OTHER HATER EffT'nS
a. Dust control
b= Service, sanitary C potable water:
Reqaired
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GPAND TOTAL RAW WATER INPUT TO PLANT i
TRZATKENT SLUDGES
a. Lima softening
b. Ion exchange
c. B i o tre a tmen t
Table A5-4
Table A5-4
Table A5-4
Taile A5-4
Energy Tqtalg^
Appendix 11
10 Ib/hr
solids water ฃ sludge
Appendix 11
10 Btu/hr
Feed
Product and byproduct
Dnrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
TOTAL:
9
10 Btu/hr * wet
Table A5-10
Table A5-10
Table A5-10*
i
Table A5-10 G
Table A5-10 5
t~-
Table A5-10
Calculated
Taฑ.le A5-10 (Char not fired
Table A5-10
Table A5-10
103 Ib water
Btu/lb evap evap/hr
s S
CD E-,
R ง
C a
fter shift reactor 6 after acid gas removal.
"Wet cooling 6 bottom ash quench.
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SYNTHANE PROCESS
Jefferson, Alabama
(continued)
SITE: Jefferson,
Coal Analysis (vt* as-received)
PRODUCT SIZE: 250 x 10 SCF/day
Q
ENERGYt 9.79 x 10 Btu/lir
Cha^Analysis fwt %?
Moisture
C
I
0
N
S
Ash
HHV Calculated
(103 Btu/Lb)
OJ COAL FEED TO REACTOR:
O
(Jl 1.243
..J.5...3
FGD. WATER
Vaporiled 0.79
With sludga 0.2J_
2.3
71.0
4.4
3.8
1.5
0.9
16.1
100
12.79
103 Ib/hr
9
10 Btu/hr
Ib/lb coal
Ib/lb coal
71.4
0.9
0.5
1.8
1.5
23.9
100
10.90
CHAR FEED TO BOILER:
231
2.5:
182
ii
TOTAL:
FGD sludge produced, wet
ASH HANDLING
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
_10 Ib/hr
109 Btu/hr
10 Ib/hr
ID3 Ib/hr
230 10 Ib/hr
6S.23103 Ib/hr
27.5
14.8
PROCESS WATER
a. Steam required
b. Dirty condensate
c. Medium quality condensate
d. Hethanation water
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT I
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatoent
1,215
578
1,981
10 Ib/hr
solids water & sludge
0.06 0.3
0.68
69
121
(continued)
-------
Jefferson, Alabama
(continued)
ENERGY
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
109 Btu/hr
Direct loss 0 82
Designed dry 1.38
Designed vet 0.49
A.cid gas reitsoval
regenerator condenser 0.69
Total turbine condensers 0.77
Total gas compressor
Interstage cooling 0.22
TOTAL: 4-37
109 Btu/Tir
15.9
11.5
4.4
72.5,
10 3 lb water
% wet Btu/lb evap evap/hr
0 1,310 0
0 1,310 0
100 1,310 374
0 1,310 0
100 1,310 588
100 1,310 168
1,130
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SVWTHANE PROCESS
SITE; Gibson, Indiana
PRODUCT SIZEi 250 x 1Q SCF/day
ENERGYi 9.79 x 109 Btu/hr
Coal Analysis (vt t as-received) Char Analysis (wt t)
Moisture
C
H
O
H
S
Ash
HHV Calculated
(103 Btu/lb)
COAL FEED TO REACTOR;
10.0
68.2
4.6
1.1
2.1
100
12.20
FGD WATER
Vaporized
With sludge
TOTALI
FGD sludge produced, wet
ASH HANDLING
10 Lb/hr
9
10 Btu/hr
Lb/lb coal
Ib/lb coal
71.4
23.9
CHAR FEED TO BOILER:
10 LbAr
2,59 10 Btu/hr
188
10 Ib/hr
49.1 10 Lb/hr
237
10 Ib/hr
70.1 10 Ib/hr
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
(continued)
-------
Gi-bson, Indiana
(continued)
Gibson, Indiana
(continued)
PROCESS WATER
a. Steam required
b- Dirty condensate
c. Medium quality condensate
d. Hethanation water
1,237
599
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
15.9
'll.S
Ul
O
CD
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary ft potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT!
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
Conversion efficiency
72.1ป
14
1,926
10 Ib/hr
solids water s sludge
0.77 3.85
71
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
109 Btu/hr
0.89
1.38
0.49
0.69
0.77
% wet
0
0
100
0
100
Btu/lb evap
1,370
1,370
1,370
1,370
1,370
10 3 Ib water
evap/hr
0
0
358
0
562
Total gas compressor
interstage cooling
0.22
100
1,370
161
1,081
0.7
3.5
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SYNTHANE PROCESS
Sullivan, Indiana
(continued)
SITE: Sullivan, Indiana
O
Coal Analysis
% as-received)
Moisture
C
H
0
H
S
Ash
13.
63.
4.
7 .
1
2
7
5
,9
5
,1
.4
.2
. 4
PRODUCT SIZE: 250 X 10 SCF/day
Q
ENERGY! 9.79 X 10 Btu/hr
Char Analysis (wt %)
HHV Calculated
(103 Btu/lb)
COAI, PEED TO REACTOR:
1,243 10 Ib/hr
14.4 10 Btu/hr
FGD WATER
Vaporized 0.'
With sludge 0. :
TOTAL:
FGD sludge produced, wet
ASH HANDLING
_lb/Ib coal
Ib/lb coal
Bottom ash: dry
water
sludge
Ply ash: dry
water
sludge
CHAR FEED TO BOILER;
242
_10 Ib/hr
2.64 109 Btu/hr
191
_10 Ib/hr
50.0 1Q3 Ib/hr
241
_10 Ib/hr
71.5 lo3 Ib/hr
7.12
5.29
PROCESS WATER
a. Steam required
b. Dirty condensate
c. Medium quality condensate
d. Hethanation water
OTHER HATER NEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b* Ion exchange
c. Biotreatment
1,234
595
115
1,847
10 Ib/hr
solids water s sludge
1.1
(continued)
-------
Sullivan, Indiana
(continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SYNTHANE PROCESS
CO
H
O
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
10 Btu/hr
15.9
71.8,
10 Btu/hr ป wet
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
TOTAL:
0.
1.
0.
0
0
0.
4
.94 0
. 38 0
.49 100
.69 0
.77 100
.22 100
.49
Btu/Lb evap
1,330
1,380
1,380
1,380
1,380
1,380
103 Ib water
evap/hr
0
0
355
0
560
159
1,074
SITE: Floyd, Kentucky
Coal Analysis (wt % as-received)
Moisture
C
H
O
N
S
Ash
3.4
1.6
HHV Calculated
3
(10 Btu/lb)
COAL FEED TO REACTOR:
1,113 10 lb/hr
15.9 109 Btu/hr
0.79
FGD HATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
_lb/lh coal
Ib/lb coal
PRODUCT SIZE: 250 x 10 SCF/day
ENERGY: 9.79 x 1Q9 Btu/hr
Char Analysis (wt. %)
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
1.5
10.90
CHAR PEED TO BOILER:
231.2 10 Ib/hr
2.52 1Q9 Btu/hr
182
_10 Lb/hr
17.8 io3 Lb/hr
231
10 lb/hr
68.2 10J lb/hr
(continued)
-------
Floyd, Kentucky
(continued)
_Floydlf Kentucky
(continued)
PROCESS WATER
a. Steaffi required
b, Dirty condensate
c. Kediuss quality condensate
d. M-athanation water
1,247
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
15.9
OTHER WATER HEEDS
a. Dust control
b Service ,, sanitary ฃ potable wate r :
Re-quired
Sewage recovered
c . Re vegetation water
d. Evaporation from storage ponds
GRAND TOTAI, RAW WATER INPUT TO PLANT:
TREATMEWT SLUDGES
a. Lome softening
br Ion exchange
c. Biocreatment
10 Ib/hr
108
1, 320
10 Ib/hr
solidg water & sludge
71
Conversion efficiency
Disposition^ of Unrecovered Heat
72.5%
Direct loss
Designed dry
Designed wet
Acid gas ransoval
regenerator condenser
Total turbina condensers
Total gas compressor
interatage cooling
10 Btu/hr
0.22
10 Ib water
wet Btu/Ib evap evap/hr
0.82
1,38
0.49
0.69
0. 77
0
0
100
0
10
1,360
1,360
1,360
1, 360
1,360
0
0
360
0
57
1,360
0.72
-------
WORK SHEET: HATER QUANTITY CALCULATIONS FOR
SYNTHANE PROCESS
Gallia, Ohio
(continued)
SITE: Gallifl, Ohio
Coal Analysis (wt % as-received)
PRODUCT SIZE: 250 x 10 SCF/day
ENERGY! 9.79 x 10 Btu/hr
Char Analysi* (wt %)
Moisture
C
H
O
N
S
Ash
4.6
3.2
HHV Calculated
3
(10 Btu/lb)
COAL FEED TO REACTOR;
11.70
1.315 10J Ib/hr
15.4 io9 Btu/hr
0.79
0.21
FGD HATER
Vaporized
Hith sludge
TOT Ail
FGD sludge produced, wet
ASH HANDLING
_lVlb coal
Ib/lb coal
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
71.4
0.5
23.9
10.90
CHAR FEED TO BOILER I
235
10'
2.56 10!
Ib/hr
Btu/hr
10 Ib/hr
18.0
27.7
7.19
79.1
PROCESS WATER
a. Steam required
b. Dirty condensate
c. Medium quality condensate
d. Methanation water
OTHER HATER NEEDS
a. Dust control
b. Service, sanitary ฃ potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLODGES
a. Lime softening
b. Ion exchange
c. Biotreatment
124
21
1,896
10 Ib/hr
solids water fc sludge
0,3
0.06
70
(continued)
-------
nhio
(continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SYHTHANE PROCESS
SITE: Jefferson, Ohio
Energy Totals^
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
0.86
0.49
0.77
100
10 Btu/hr
15.9
72.3%
10 Btu/hr % wet Btu/lb evap
1,420
1,420
1,420
1,420
1,420
1,420.
10 It water
evap/hr
345
155
i-ฐ*2
PRODUCT SIZE: 250 x 10 SCF/day
ENERGY: 9.79 x 10 Btu/hr
Coal Analysis (wt % as-received) Char Ana^ysia^ (yt^ *)
Moisture 2.4
C 71.1
H 4.9
0 5.3
N 1.2
S 5.0
Ash 10.1
100
HHV Calculated
(103 Btu/Lb) 13.10
COAL FEED TO REACTOR:
1,215 103 jfc/hr
15 -9 109 Btu/hr
FGD WATER
Vaporized 0.79 lb/lb coal
With sludge ฐ-2l lb/lb coal
TOTAL:
FGD sludga produced, wet
ASH HANDLING
Bottom ash: dry
water
sludge
Ply ash: dry
water
71.4
0.9
0.5
1.8
1.5
23.9
100
10.90
CHAR FEED TO BOILER:
231
2.52
182
47.3
230
68.2
103 Ib/hr
16.9
9.07
25.9
67.4
6.74
10 3 Ib/hr
9
10 Btu/hr
10 3 Ib/hr
10 3 Ib/tir
103 Ib/hr
103 Ib/hr
sludge
(continued)
-------
Jefferson, Ohio
(continued)
PROCESS WATER
a. Steam required
b. Dirty condensate
c. Medium qua-lity condensate
d. Methanation water
OTHER HATER KEEPS
a. Dust control
b. Service, sanitary ฃ potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
1,810
TREATMENT SLUDGES
a. Lijne softening
b. Ion exchange
c. Biotreatment
10 Ib/hr
solids water ฃ sludge
0.06 0.3
70
Jefferson, Ohio
(continued)
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
9
10 Btu/hr ป wet
Direct loss 0.82 0
Designed dry 1.38 0
Designed wet 0.49 100
Acid gas removal
regenerator condenser 0.69 0
Total turbine condensers 0.77 100
Total gas compressor
interstage cooling 0.22 100
TOTALi 4.37
10 Btu/hr
15.9
11.5
4.4
72. 5ป
Btu/Xb evap
1,400
1,400
1,400
1,400
1,400
1,400
10 Lb water
evap/hr
0
0
345
0
542
155
1,042
-------
WORK SHEET: WATER QUANTITY CAJ^CUUATIONS FOR
SYNTHAUE PROCESS
SITE : Anns trong, Pennsylvania
PRODUCT SIZE: 250 x 10 SCF/day
ENERGY; 9.79 X 1Q9 BtU/hr
Coal AnalysJ3 (wt ^ as-received)
Char Analysis (wt. %)
Moisture
C
H
0
M
S
Ash
2.3
100
HlfV Calculated
(103 Btu/lb)
COAL FEED TO REACTOR:
1,187 1Q3
10 Btu/hr
0.79
FCD HATER
Vaporized
With sludge
TOTAL:
FGD aludge produced, wet
ASH HANDLING
_l_b/lb coal
Lb/lb coal
Bottom ash: dry
water
a ludge
Fly ash i dry
water
sludge
0.5
CHAR FEED TO BOILER:
10 Lb/hr
231 10 Ib/hr
2-52 10 Btu/hr
182.3 ioj li,/hr
41-B 1Q3 Ib/hr
230 103 it/hr
6B-2 10 Ib/hr
A-na3Lrong , Pennsylvania (continued)
PROCESS MATER
a. Stean required
b. Dirty condensate
c. H-edium quality condensate
d. Methanation water
1,231
593
115
130
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary ฃ potable water:
Required
Sewage recovered
c, Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
1,872
TREATMEOT SLUDGES
a. Lime softening
b. Ion exchange
Cc Biotreatment
10 Ib/hr
solids water S sludge
0.31
0.06
70
1.2
(continued)
-------
Armstrong. Pennsylvania (continued)
WORK SHEET: HATER QUANTITY CALCULATIONS FOR
SYNTHANE PROCESS
SITE: Kanauha, West Virginia
PRODUCT SIZE: 250 X 10ฐ SCF/day
ENERGY: 9.79 x 10 9 Btu/hr
Energy Totals
Coal Analysis fvt * as-received) Char ^nalysia (vrt
10 Btu/hr
Feed 15.9
- '
Product and byproduct 11.5
Unrecovered heat ^"4
Conversion efficiency 72.5%
Disposition of Unrecovered Heat
103 Ib water
109 Btu/hr % wet Btu/lli evap evap/hr
Direct loss ฐ-82 ฐ 1'410 ฐ
De.igned dry 1.38 0 1,410 0
Designed vet 0.49 100 1,410 348
Acid gas removal
regenerator condenser 0.69 0 1,410 0
ivM-,1 .-,*( ,,rtซnซ.,rซ 0.77 100 1,410 546
Total gas compressor
interstage cooling 0.22 100 1,410 156
wrrปr, 4.37 1-050
Moisture
N
Ash
HHV Calculated
COAL FEED TO REACTOR:
1,187
FGD HATER
Vaporized 0.79
TOTAL:
F
-------
a , West Virginia
(continued)
Kanawha, We a1 Virginia (continued)
PROCESS WATER
a. Steam required
b. Dirty condensate
c. Medium quality condensate
d. Keth&nation water
1,232
594
Energy Totals
Feed
Product and byproduct
Unrecovered heat
.10 Btu/hr
15.9
11.5
OTHER WATER NEEDS
Conversion efficiency
72.5%
a. Dust control
b. Service, sanitary ฃ potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTA-L RAW WATER INPUT TO PLANTi
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
Disposition of Unrecovered Heat
0
1,865
10 Ib/hr
solids water & sludge
Direct loss
Designed dry
Designed wet
10 Btu/hr
0.82
1. 38
0. 49
% wet
0
0
100
Btu/lb evap
1,360
1,360
1,360
103 Ib water
evap/hr
0
0
360
Acid gas removal
regenerator condenser
Total turbine condensers
Total gaa compressor
Interstage cooling
1,360
1,360
1,360
1,068
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SYNTHANE PROCESS
Preston, West Virginia (continued)
SITE: Preston, West Virginia
PRODUCT SIZE; 250 x 10 SCF/day
PROCESS WATER
Coal Analysis (wt * as-received)
Moisture
C
H
O
N
S
Ash
2.5
74.6
4.7
3.3
1.5
2.7
10.7
100
HHV Calculated
l_i (IO3 Btu/lb) 13.60
COAL FEED TO REACTOR:
1,170
15.9
FGD WATER
Vaporized 0.79
With sludge 0.21
TOTAL:
FGD sludge produced, wet
ASH HANDLING
10 3 Ib/hr
IO9 Btu/hr
lb/lb coal
Ib/lb coal
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
ENERGY: 9.79 X 10 Btu/hr
Char Analysis (wt \)
71.4
0.9
0.5
1.8
1.5
23.9
100
10.90
CHAR FEED TO BOILER:
231 io3 Ib/hr
2.52 io9 Btu/hr
183 io3 Ib/hr
47.8 IO3 Ib/hr
230 io3 Ib/hr
68.2 IO3 Ib/hr
IO3 Ib/hr
17.2
9.26
26.5
68.8
6.88
75.7
10 3 Ib/hr
a. Steam required 1 , 229
c. Medium quality condensate 115
d. Methanation water 130
OTHER WATER NEEDS
IO3 Ib/hr
a. Dust control 112
b. Servica, sanitajry & potable water:
Required 21
Sewage recovered 14
Reve etation water 0
GRAND TOTAL RAW WATER INPUT TO PLANT: 1,392
TREATMENT SLUDGES
IO3 Lb/hr
solids water & sludge
a. Lime softening 0.03 0.15
b. Ion ejcchange 70
c. Biotreatment 0.23 1.2
(continued)
-------
Preston, West VITginia (continued)
WORX SHEET: WATER QUANTITY CALCULATIONS FOR
SYNTHANE PROCESS
SITE: Antelope Creek, Wyoming
PRODUCT SIZE:. 250 Jt 10 SCF/day
ENERGYi 9.79 x 10 Btu/hr
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Pi sposition of Unrecovered Heat
10 Btu/hr
IS.9
72.5%
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr % wet
10 Ib water
Btu/lb evap evap/hr
0.
1.
0.
0.
0.
0
4
82
38
49
69
.77
.22
.37
0
0
100
0
10
100
1,380
1, 380
1,380
1,380
1,380
1,380
0
0
355
0
56
159
570
Coal Analysis (wt ป
Moisture
C
H
0
H
S
Ash
HHV Calculated
UO3 Btu/Lb)
COAL FEED TO REACTOR:
1,472
13.3
FGD WATER
Vaporised 0.70
With sludge 0.041
as-received)
26.2
52.6
3.6
12.0
0.6
0.5
4.5
100
9.00
103 Ib/hr
109 Btu/hr
Ib/lb coal
Ib/lb coal
TOTAJ.:
FGD eludge produced, wet
ASH HANDLING
Bottc
Fly s
Jffi ash: dry
water
sludge
ish: dry
water
sludge
Char Analysis (wt ป)
63.6
1.0
1.4
0.4
0.3
33.3
100
9.73
CHAR FEED TO BOILER:
370 103
3.61 109
259 103
15.2 lo3
274 IQ3
2.20103
103 Ib/hr
11.5
6.19
17.7
46.0
4.60
50.6
Ib/hr
Btu/hr
Ib/hr
Ib/hr
Ib/hr
Ib/hr
(continued)
-------
Antelope_Creek, Wyoming (continued)
Antelope Creek, Wyoming (continued)
PROCESS WATER
*. Steam required
b. Dirty condensate
c. Medina qua-lity condensate
d. Methanation water
1,177
526
Energy Totals
Feed
Product and byproduct
Unrecovered heat
10 Btu/hr
17.1
OTHER WATER NEEDS
Conversion efficiency
U)
(O
O
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreanaent
d. Electrodialysis
Dispositionof Unrecovered Heat
21
1,432
10 Ib/hr
solids water s sludge
0.03 0.14
66
0.33
1.65
Direct loss
Designed dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr
1.77
0.34
5.94
Btu/lb evap
1,397
1,397
1,397
1,397
1,397
1,397
10 Ib water
evap/hr
-------
WORK SHEET > WATER QUANTITY CALCULATIONS FOR
SYNTHANE PROCESS
Spotted Horse, Wyoming (continued)
SITEi Spotted Horse, Wyoming
PRODUCT SIZE: 250 X 10 SCF/day
9
ENERGY i 9.79 x 10 Btu/hr
PROCESS WATER
LO
to
3.5
N
S
Aih
100
HHV Calculated
HO3 Btu/Lb) 8.06
COAL FEED TO REACTOR:
FCD WATER
Vapo ri red
WLtLh sludge
TOTAL:
1,596 10 Lb/hr
12.9 109 Btu/hr
0.70 Ib/Ib coal
0.04 Ib/lb coal
FGD sludge produced, wet
^H HAJIDLINC
Coal Analysis (wt % as-received) Char Analysis (wt %)
Moisture 78.n
C
H
O
Bottom ash: dry
wa te r
Bludge
Fly ash: dry
water
sludge
63.6
1.4
0.4
0.3
33. 3
100
9.73
CHAR FEED TO BOILER:
10 Lb/hr
22.2
12.0
34. 2
88.6
97.7
381 10 lb/hr
3.71 10 Btu/hr
267 10 Lb/hr
15.6 103 Lb/hr
282 10 Lb/hr
2.26.103 Lb/hr
a. Steam required
b. Dirty condensate
c. Medium quality condensate
d. 1-tetha/iation water
OTHER WATER HEEDS
a. Dust control
b. Service, sajiitary ฃ potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
1,162
1,315
solids
water 6 sludge
6.41
(continued)
-------
Jjpotted Horse, Wyoming (continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
SYNTHANE PROCESS
LO
NJ
ro
Engrgy Totals
Feed
Product arid byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecoyered Heat
10 Btu/hr
17.1
11.0
6.1
Direct loss
beiigned dry
Designed wet
Acid gas removal
regenerator condenser
Total turbine condensers
Total gas compressor .
interstage cooling
1.87
1.33
0.45
1.01
1.04
0.34
10
50
1,401
1 401
1,401
1 401
1,401
1,401
10 Ib water
10 Btu/hr % wet Btu/lb evap evap/hr
321
171
SITE: Colstrip, Montana
Coal Analysis (wt
Moisture
C
H
O
M
as-received)
24.4
S
Ash
52.4
3.5
6.9
100
HHV Calculated
3
(10 Btu/lb)
COAL FEED TO REACTOR:
8.91
1,525 10 Ib/hr
13.6 109 Btu/hr
FGD HATER
Vaporized
With sludge
TOTAL:
0.70
0.04
_lb/li> coal
_lb/lb coal
FGD sludge produced, wet
ASH HANDLING
PRODUCT SIZE: 250 X 10 SCF/day
9
ENERGY: 9.79 x 10 Btu/hr
Char Analysis (vt %)
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
100
9.73
CHAR FEED TO BOILER:
36710 Ib/hr
3.57 10 Btu/hr
257 IQJ Ib/hr
14.7 10 Ib/hr
?72 103 Ib/hr
2-17103 Ib/hr
10 Ib/hr
18.1
9.72
27.8
(continued)
-------
Colstrip, Montana
(continued)
Colstrip, Montana
(continued)
PROCESS _WATฃR
a. Steam required
b. Dirty condensate
c. Medium quality condensate
d. Hethanation water
1,168
Energy Totals
Feed
Product juid byproduct
Unrecovered heat
10 Btu/hr
17.1
11.2
S.9
LO
NJ
UJ
OTHฃR WATER NEEDS
a, Dust control
b. Service, sanitary fi potable water:
Required
Sewage recovered
c, Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT i
TREATMENT SLUDGES
a. J-ime softening
b. Ion exchange
c. Biotreatraent
1,420
10" IVhr
solids water^ C sludge
0.16
79
Conversion efficiency
Disposition of Unrecovered Heat
65.5 ซ
Direct loss
Designed dry
Designed wet
JU:id gas removal
regenerator condenser
Total turbine condensers
Total gas compressor
interstage cooling
10 Btu/hr I wet Btu/Lb evap
10 1ฑ> water
evap/hr^
1
1
0.
1.
1.
0.
5
.73
.33
.45
.01
.04
.34
.90
0
0
100
0
10
100
1.414
1,414
1,414
1,414
1,414
1,414
0
0
316
0
74
240
632
-------
WORK SHEET t WATER QUANTITY CALCULATIONS FOR
LURGI PROCESS
SITE!
PRODUCT SIZE: 250 x 10 SCP/day
ENERGY! 9.9 x 10 Btu/hr
W
NJ
Coal Analysis (wt 4 as-received)
Moisture
C
H
O
N
S
Ash
HHV Calculated
(103 Btu/lb)
COAL FEED
to reactor: Table A6-3
Table A6-3
FGD HATER
Vaporized
With sludge
TOTALi
Appendix 8
Appendix 9
PGD sludge produced, wet
ASH HANDLING
Tables 3-18, 3-19
to boiler:
Table A6-3
Table A6-3
_10 Ib/hr
103 Ib/hr
Calcd. 10 Ib/hr
103 Ib/hr
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
Appendix 8
(continued)
-------
(continued)
PROCESS_WATER
B. Steam and boiler feed water required
b. Dirty condensate
c. Methanation water
10 Ib/hr
Table A6-3
Table A6-3
Table Afe-3
OTHER WATER NEEDS
10
ro
Ln
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Re vegetation water
d. Evaporation from storage ponds
GRAND TOTAL. RAW WATER INPUT TO PLANT i
Appendix 9
Appendix 11
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
solids water C sludge
Appendix 11
(continued)
Em? r gy^ To ta 1 s
Feed
Product and byproduct
Unrecovered heat
Btu/hr
Table A6-3
Table A6-3
A6-j (Product gas & byproduct)
Conversion efficiency
Table A6-3
Total unrecovered heat
% of unrecovered heat
wet cooled
Wet cooling load
Btu/lb evap
10 Ib water evap/hr
Table A6-3
From jjther gas plants in the same area*
Calculated
Table A7-2
Calculated
"Synthane
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
LURGI PROCESS
SITE: Marengo, Alabajna
water)
Coal Analysis (wt % as-received)
Moisture
C
H
O
N
S
Ash
HHV Calculated
(103 Btu/lb)
COAL FEED
to reactor: 2,765 10 lb/hr
q
14 8 10 Btu/hr
FGD WATER
Vaporized 0.11 Ib/lb coal
With sludge 0.25 Ib/lb coal
TOTAL:
FGD sludge produced, wet
ASH HANDLING
Bottom ash: dry
water
8 ludge
Fly ash: dry
water
sludge
PRODUCT SIZE: 250 x 10 SCF/day
o
48.7
32.1
2.2
9.8
0.6
1.8
4. S
100
5.34
to boiler: 845 103 lb/hr
4.51 10* Btu/hr
0 103 lb/hr
211 103 lb/hr
211 103 lb/hr
302 10 lb/hr
1O3 lb/hr
141
75.8
217
32.6
3.25
35.7
Marenqo. Alabama
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Methanation water
1,767
2,325
260
OTHER WATER NEEDS
a . Dus t contro 1
b. Service, sanitary & potable water;
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange & reverse osmosis
c. Biotreataient
water ft sludge
(contLnued)
-------
Harenqo, Alabama
{continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
LURGI PROCESS
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Total unrecovered heat
% of Unrecovered heat
wet cooled
Wet cooling load
Btu/lb evap
10 Lb water evap/hr
10 Btu/hr
19.3
'l2.6
6. 76
6.76 10 Btu/hr
1.2S 10 Btu/hr
1,310
980
SITE: Bureau, Illinois
Coal Analysis (wt t as-received)
Moisture
C
H
0
N
S
Ash
HHV Calculated
COAL FEED
to reactor:
FGD WATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
1,364 10 Ib/hr
g
14.7 10 Btu/hr
0.57 Lb/lb coal
0.40 lb/Ib coal
PRODUCT SIZE: 250 x 10 SCF/day
ENERGY: 9.9 x 1Q9 Btu/hr
16.1
1.1
100
(10 Btu/Lb) 10.16
to boiler: 204 10 Lb/hr
2.2 109 Btu/hr
116 10 Ib/hr
81.6 10 Ib/hr
19B 103 Ib/hr
117 10 Lb/hr
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
(continued)
-------
Bureau, Illinois
(continued)
Bureau, Illinois
(continued)
PROCESS WATER
a. Steam and boiler feed water required
b* Dirty condensate
c. Hethanation water
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary S, potable water:
Required
LO
^ Sewage recovered
00
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
ENERGY
10 3 Ib/hr
2.693 Energy Totals
2.149 109 Btu/hr
279 Peed 16.9
Product and byproduct 11.4
Unrecovered heat 5.55
10 Ib^hr Conversion efficiency 67 4
150
Disposition of Unrecovered Heat
21
14 Total Unrecovered heat 5.55 lo9 Btu/hr
0
0 wet cooled 44 %
2,668 Wet cooling load 2.44 109 Btu/hr
Btu/lb evap 1,390
10J Ib water evap/hr 1,757
10 3 Ib/hr
solids water & sludge
1 4 6.7
ISO
c. Biotreatment
-------
WORK SHEET: HATER QUANTITY CALCULATIONS FOR
LURGI PROCESS
St. Clair. Illinois
(continued)
OJ
r-o
st. Clair, Illinois
(Underground and Surface
Coal Mining)
PRODUCT EliE: 250 X 10 SCF/day
Q
ENERGY: 9.9 X 10 Btu/hr
Coal Analysis (wt % as-received)
Moisture 11.3
C 61.1
H 4.2
O 7.4
N 1.2
S 3.7
Ash 11.1
100
HHV Calculated
(103 Btu/Lb) 11.07
COAL FEED
to reactor: 1,351 1Q3 Ib/hr to boiler: 199
14.9 109 Btu/hr 2'2
FGD WATER
Vaporized 0.63 lb/Ib coal 125
With sludge 0.51 lb/Ib coal 101
TOT*,, 226
ASH HANDLING
103 Ib/hr
Bottom ash: dry I54
water 83. 1
sludqe 23S
Fly ash: dxv 17'7
water 1-"
sludae 19'4
103 Ib/hr
109 Btu/hr
103 Ib/hr
103 Ib/hr
103 Ib/hr
103 Ib/hr
PROCESS HATER
&. Steam and boiler feed water required
b. Dirty condensate
c. Methanation water
(Surface coal mining
\ Underg
OTHER WATER HEEDS
a. Dust control , .
' n rground coal mining
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
(Surface coal mine
\Underground coal mine
10 Ib/hr
2,653
2,736
TREATMENT SLUDGES (Note: Surface coal mining ฃ underground coal mining are the same)
a. Lime softening
b. Ion exchange
c. Biotreatment
0.07
water ฃ sludge
0.33
(continued)
-------
St. Clair. Illinois
(continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
LURGI PROCESS
Ul
CO
O
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Total Unrecovered heat
% of Unrecovered heat
wet cooled
Wet cooling load
Btu/lb evap
10 Ib water evap/hr
5.61 1Q^ Btu/hr
44 %
2.48 io9 Btu/hr
1,370
1,752
SITE: Fulton, Illinois
Coal Analysis (wt % as-received)
Moisture
C
H
O
N
S
Ash
COAL FEED
HHV Calculated
(103 Btu/lb)
to reactor: 1,410 1QJ Lb/hr
15.0 IO9 Btu/hr
FGD WATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.56 Lb/lb coal
0.43 Lb/Lb coal
PRODUCT SIZE: 250 x 10 SCF/day
9
ENERGY: 9.9 X 10 Btu/hr
15.6
1.1
10.65
to boiler: 207 IP"1 Ib/hr
2.2 109 Btu/hr
10" Lb/hr
3
S9.0 10
205 103 Ib/hr
127 IOJ Lb/hr
Bottom ash: dry
water
sludge
Ply ash: dry
water
sludge
16.6
(continued)
-------
Fulton, Illinois
(continued)
Fulton, Illlnoig
(continued)
LJ
OJ
H
PKDCMS WATCH
a. Steam a/id bailor feed water required
b. Dirty condensato
c, Methttnatiori water
OTHER WATER HEEDS
a. Dust control
b. Service, Bfl/iitary b potable woteri
Required
Sewogo recovered
c. Revecjetntion water
d. Evaporation from storage poftds
GHA1TD TOTAL RAW WATER IHPUT TO
Tf-K/iTHEHTSUJlXjES
o. Lime coftening
bn Ion exchange t reverse ostnoais
c, Biotr eabcoertt
d, C1cctrodialysis
0
osa'
10" lb/hr
Bolids water fc aludge
163
I-oad
Product nrid byproduct
Unrecoverad haat
Conversion efficiency
Disposition ol Unrecovered Hent
Total unrecovored heat
% of unrccovercd boat
wet cooled
Wet cooling load
Btu/lb evop
10 Ib water evap/hx
10 Btu/hr
17.2
' 11.4
5.8
67
5.76 ID" Btu/hr
25
1-44 ioa Btu/hr
1,380
1,034
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
LURGI PROCESS
Muhlenberg, Kentucky
(continued)
SITE: Muhlenberg, Kentucky
OJ
U>
NJ
COAL FEED
to reactor:
FGD HATER
HHV Calculated
(103 Btu/lb)
1,183 IP"1 Ib/hr
13.9 lo9 Btu/hr
Vaporized
With eludge
TOTAL i
FGD sludge produced, wet
ASH HANDLING
0.68 ib/lb coal
0. 36 Ib/lb coal
PRODUCT SIZE: 250 x 10 SCF/day
o
ENERCK: 9.9 X 10 Btu/hr
Moisture
C
H
0
N
S
Ash
11.
64
4
8
1
2
7
.0
.8
.7
.3
.4
.6
.2
100
to boiler:
26910 Ib/hr
3-17 10 Btu/hr
1S2-9 1Q Ib/hr
96-B io3 ib/hr
2BO 1Q3 lt,/hr
138-3 IO3 Ib/hr
Bottom ash: dry
water
aludge
Fly ash: dry
water
sludge
10 Ib/hr
69.1
48.0
137.0
17.0
PROCESS WATER
a. Steam ajid boiler feed water recjuired
b. Dirty condensate
c. Methanation water
OTHER WATER HEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAH HATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange ฃ reverse osmosis
c. Biotreatment
1,918
10 Ib/hr
52
1,478
10 Ib/hr
solids water & sludge
3.1
(continued)
-------
Muhlenburg, Kentucky (continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
LURGI PROCESS
U)
OJ
LO
ENERGY
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Total Unrecovered heat
% of Unrecovered heat
vet cooled
Wet cooling load
Btu/Lb evap
10 Ib water evap/hr
10 Btu/hr
17.1
11.4
67
5.63 10 Btu/hr
0.73 103 Btu/hr
1,370
533
SITE: Jim Bridger, Wyoming
Coal Analysis (wt ป as-received)
Moisture
C
H
O
H
S
Ash
COAL FEED
HHV Calculated
(103 Btu/Lb)
to reactor: 1,661 10 lb/hr
14.1 109 Btu/hr
FGD WATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.3B Lb/lb coal
0.07 Lb/lb coal
PRODUCT SIZE: 250 x 10 SCF/day
q
ENERGY: 9.9 X 10 Btu/hr
1.1
.50
to boiler: 519 10 Lb/hr
4.41 109 Btu/hr
197 10 Lb/hr
36.3 1Q-1 Lb/hr
234 1Q3 lb/hr
51.9 103 Lb/hr
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
145
77.9
223
34.1
37.5
(continued)
-------
Jim Bridget", Wyoming (continued)
Jim Bridqer, Wyoming (continued)
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Methanation water
OTHER WATER NZEDS
a. Dust controi
b. Service, sanitary t potable water:
Required
Sewage recovered
c- Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
10 lb/hr
1,596
1,121
10 lb/hr
100
1,548
10 lb/hr
eolids water & sludge
ENERGY
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Total Unrecovered heat
\ of Unrecovered heat
wet cooled
Wet cooling load
Btu/lb evap
10 Ib water evap/hx
10 Btu/hr
18.5
6.11 10 Btu/hr
1-13 10 Btu/hr
1,401
807
0.71
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
LURGJ PROCESS
Kemmerer, Wyoming
(continued)
SITE: Kemmeier, Wyoming
PRODUCT SIZE: 250 x 10" SCF/day
ENERGY: 9.9 X 1Q9 Btu/hr
LJ
Ul
ui
Coal Analysis (wt * as-received)
Moisture 2 . B
C 71.8
H 5.0
0 9.0
N 1.2
S 1.0
Ash 9.2
100
KHV Calculated
(103 Btu/lb) I2-88
COAL FEED
to reactor: 1,170 lo3 Lb/hr to boiler: 220
I*. 9 109 Btu/hr 2.83
FGD WATER
Vaporized 0.64 Ib/Lb coal IBS
with sludge 0.14 Lb/Lb coal 30.8
TOTAL: 216
FGD sludqe produced, wet 44.0
ASH HAJIDLJNG
10 Ib/hr
Bottom asn: dry -^2
water 60-1
sludge 172
water 1-62
sludge 17'8
103 Ib/hr
ID9 Btu/hr
103 Ib/hr
103 Ib/hr
10 3 Ib/hr
103 Lb/hr
PROCESS HATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Methanation water
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary ฃ potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage pondfi
GRAND TOTAL RAW WATER IOTUT TO PLANT:
TREATMENT SLUDGES
a. Li me softening
b. Ion exchange ฃ reverse osmosis
c. Biotreatment
1,934
272
1,925
10' Ib/hr
solids water ฃ sludge
1.91
(continued)
-------
Kenwerer, Wyoming
(continued)
WORK SHEET: HATER QUANTITY CALCULATIONS FOR
LURGI PROCESS
SITE: Knife River, North DaXota PRODUCT SIZE: 250 x 10* SCF/day
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Total Unrecovered heat
% of Unrecovered heat
wet cooled
Wet cooling load
Btu/Ub evap
10 lt> water evap/hr
10 Btu/hr
17.7
11.9
67
10 Btu/hr
20.6 %
1-21 109 Btu/hr
1,397
866
Coal Analysis (wt % as-received)
Moisture
C
H
O
N
S
Ash
HHV Calculated
(103 Btu/lb)
ENERGY: 9.9 x 109 Btu/hr
35.0
42.5
2.8
12.3
0.6
0.7
6.1
100
7.00
COAL FEED
to reactor:
FGD WATER
Vaporized
Kith sludge
2,037
14.3
0.14
0.10
10 3 Ib/hr
109 Btu/hr
_lb/lb coal
Ib/li coal
TOTAL:
PGD sludge produced, wet
ASH HANDLING
to boiler: 589
4.12
82.5
SB. 9
141
84.1
10 3 Ib/hr
109 Btu/hr
103 Ib/hr
_103 Ib/hr
103 Ib/hr
103 Ib/hr
Bottom ash: dry
water
sludge
Ply ash: dry
water
sludge
70.8
2.87
31.6
(continued)
-------
e River , North Dakota (continued)
ICnife River, North Dakota (continued)
U>
LO
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Methanation water
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTA1, RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange & reverse osmosis
c. Biotreatioent
1,199
10 Ib/hr
solids water & 3ludga
Energy Totaj.3
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Total Unrecovered heat
% of unrecovered heat
wet cooled
Wet cooling load
Btu/lb evap
10 Ib water evap/hr
1.1
10 Btu/hr
18.4
65
10 Btu/hr
1-19 10 BtuAir
1,420
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
UIRGI PROCESS
Hilliston, North Dakota (continued)
SITE: Williston, North Dakota
Coal Analysis fwt % as-received)
Moisture
C
H
O
N
S
Ash
U)
to
00
COAL FEED
to reactor:
FGD WATER
HHV Calculated
(103 Btu/lb)
2,245 10 Ib/hr
p
14.B 10 Btu/hr
Vaporized
WiUi sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.53 lb/lb coal
O.OB lb/lb coal
PRODUCT SIZE: 250 x 10 SCF/day
ENERGY: 9.9 X 109 Btu/hr
2.8
11.2
0.7
0.6
5.6
100
6.58
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
to boiler:
678 10J Ib/hr
-1.46 1Q9 Btu/hr
359 1Q-* Ib/hr
54.2 103 Ib/hr
413 103 Ib/hr
77.5 io ib/hr
71.8
205
3.04
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Methanotion water
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
10 Ib/hr
1,780
1,897
268
10 Ib/hr
191
21
2,464
10 Ib/hr
solids water t sludge
0.09
0.45
97
1.20
(continued)
-------
Williston, North Dakota (continued)
WORK SHEET: HATER QUANTITY CALCULATIONS FOR
U1RCI PROCESS
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Total unrecovered heat
% of unrecovered heat
wet cooled
Wet cooling load
Btu/lb evap
10 Lb water evap/hr
10 Btu/hr
19. 3
12.5
10 Btu/hr
2-BB 109 Btu/hr
1,420
2,028
SITE; Decker, Montana
Coal Analysis (wt % as-received)
Moisture
C
H
O
N
S
Ash
COAL FEED
to reactor:
FGD WATER
Vaporized
With sludge
TOTALi
FGD sludge produced, wet
ASH HANDLING
HHV Calculated
(103 Btu/lb)
l.SOS 10 Lb/hr
9
14.3 3-0 Btu/hr
0.42 Ib/lb coal
0.07 Ib/lb coal
PRODUCT SIZE: 250 x 10 SCF/day
ENERGY: 9.9 x 109 Btu/hr
3.2
0.5
3.7
to boiler:
10 Ib/hr
10 Btu/hr
. B 10 Ib/hr
Bottom ash: dry
water
eludge
Fly ash: dry
water
sludge
31.8
(continued)
-------
Decker, Montana
(continued)
_peckejr, Montana
(continued)
o
PROCESS HATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Methajiation water
OTHER WATER
a. Dust control
b. Service, sanitary & potable wateri
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
1,696
1,186
2,472
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Total Unrecovered heat
% of Unrecovered heat
wet cooled
Wet cooling load
Btu/lb evap
10 Ib water evap/hr
10" Btu/hr
IB. 6
12.4
67
6.12 lpa Btu/hr
10* Btu/hr
1,407
1,500
a. Lime softening
b. Ion exchange
c. Biotreatment
d. Electrodialysis
0.08
91
0.75
247
-------
WORK SHEET; WATER QUANTITY CALCULATIONS FOR
LURGI PROCESS
Foster Creek, Montana
(continued)
SITE: Foster Creek, Montana
Coal Analysis (wt \ as-received)
Moisture
C
H
O
N
S
Ash
HHV Calculated
PRODUCT SIZE: 250 x 10 SCF/day
9
ENERGY: 9.9 x 10 Btu/hr
45.7
0.7
7.7
COAL FEED
to reactor:
(10 Btu/Lb)
_1,B97 10 Ib/hr
14.3 IO9 Btu/hr
FCD WATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.22 Lb/lb coal
0.07 Lb/Lb coal
Bottom ash: dry
water
gludge
Fly ash: dry
water
sludge
to boiler:
574 10 Lb/hr
4.33 10 Btu/hx
126 10 Ib/hr
40. 2
Ib/hr
167 10 Ib/hr
57.4 io3 Lb/hr
3.54
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. MetJianation water
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary fi potable water;
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTA1, RAW WATER IKPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange S reverse osmosis
c. Biotreatment
10 Ib/hr
1,312
0.87
(continued)
-------
Foster Creek, Montana (continued)
HORX SHEET: HATER QUANTITY CAICULATIONS FOR
LURGI PROCESS
OJ
4^
KJ
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition of Unrecovered Heat
Total Unrecovered heat
* of Unrecovered heat
wet cooled
Wet cooling load
Etu/lb evap
10 Ib water evap/hr
Btu/hr
18.6
12.5
6.16
6-16 iQ9 Etu/hr
10 Btu/hr
SITE: El Paso, New Mexico
Coal Analysis (wt * as-received)
Moisture
C
H
O
N
S
Ash
HHV Calculated
(103 Btu/lb)
COAL FEED
to reactor: 1,672 IQ lb/hr
14-4 109 Btu/hr
FGD HATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH HANDLING
0.42 lb/lb coal
0.10 Ib/Uj coal
PRODUCT SIZE: 250 X 10ฐ SCF/day
ENERGY: 9.9 X 109 Btu/hr
8.62
to boiler:
10 ]_b/hr
3-99 109 Etu/hr
"6-3 103 Ib/hr
66-1 103 Ib/hr
Bottom ash: dry
water
sludge
Fly ash: dry
water
sludge
182
(continued)
-------
El Paso, New Mexico
(continued)
El Paso, New Mexico (continued)
OJ
J^
OJ
PROCESS WATER
a. Steam and boiler feed water required
b. Dirty condensate
c. Hethanation water
OTHER WATER REEDS
a. Dust control
t>. Service, sanitary 6 potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange
c. Biotreatment
10 Ib/hr
1,725
10 Ib/hr
Boj.ids water & sludge
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
Disposition __gf_ U"_f g_covered^_Hea;t
Total unrecovered heat
^ of unrecovered heat
wet cooled
Wet cooling load
Btu/lb evap
10 Ib water evap/hr
10 Btu/hr
18.4
12. 3
6.07
&-07 10 BtuAr
Btu/hr
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
LURGI PROCESS
9
ENERGY. 9.9 * 10 Btu/hr
Coal Analysis (wt t as-received)
Moisture 12. 4
S 0.7
Ash 25.6
100
HHV Calculated
(103 Btu/lb) 8.44
COAL FEED
to reactor: 1,689 1Q3 lb/hr to boiler: 475
14.3 109 Btu/hr 4.01
FGD WATER
Vaporized 0.45 Lb/lb coal 214
With sludge 0.10 Ib/lb coal 47.5
TOTAL: 262
FGD sludge produced, wet 67.9
ASH HANDLING
103 lb/hr
Bottom ash: dry 4^7
water 24&
sludge 7ฐ3
Fly ash: dry 97.3
water 9.73
sludge 107
103 lb/hr
109 Btu/hx
103 lb/hr
103 lb/hr
103 lb/hr
103 Ih/hr
Wesco, New Mexico
(continued)
PROCESS WATER
a. Steam arid boiler feed water required
b. Dirty condensate
c. Methanation water
310
OTHER WATER NEEDS
a. Dust control
b. Service, sanitary t potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
11
1,865
TREATMENT SLUDGES
a. Lime softening
b. Ion exchange & reverse osmosis
c. BiotreatnMnt
10 lb/hr
solids water t sludge
4.8
(continued)
-------
Wesco. New Mexico
(continued)
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
LURGI PROCESS
Energy Totals
Feed
Product and byproduct
Unrecovered heat
Conversion efficiency
D^spgsit^on of Unrecovered Heat
Total unrecovered heat
* of unrecovered heat
wet cooled
Wet cooling load
Btu/lb evap
10 Ib water evap/hr
10 Btu/hr
18. 3
6-M 109 Btu/hr
1-09 Id9 Btu/hr
1.375
793
SITE: Gallup, New Mexico
Coal Analysis (wt % as-received)
Moisture
C
H
O
N
S
Ash
COAL FEED
to reactor:
1,263 IP*1 Ib/hr
9
14.3 10 Btu/hr
FGO HATER
Vaporized
With sludge
TOTAL:
FGD sludge produced, wet
ASH_HANDLING
0.61 Ib/lb coal
0.06 Ib/lb coal
PRODUCT SIZE: 250 > 10" SCF/day
ENERGY; 9.9 x 1Q9 Btu/hr
10.4
1.1
0.4
5. 1
HHV Calculated
(103 Btu/li>) 11.30
to boiler:
10
4.01 10a Btu/hr
217 103 it/hr
21.3 io3 ib/hr
. 23B 1Q3 ib/hr
30-" 103 ib/hr
Bottom ash t dry
water
sludge
Fly ash: dry
water
sludge
36.6
105
14.5
15.9
(continued)
-------
Gallup, New Mexico
(continued)
G a11up, H ew He x i co
(continued)
PROCESS WATER
a. Steajn and boiler feed water required
b. Dirty condensate
c. MetJianation water
OTHER WATER KEEPS
a. Dust control
b. Service, sanitary & potable water:
Required
Sewage recovered
c. Revegetation water
d. Evaporation from storage ponds
GRAND TOTAL RAW WATER INPUT TO PLANT:
TREATMENT SUJPGES
a. Lime softening
b- Ion exchange
c. Biotreatment
d. Electrodialysis
1,603
1,007
276
En e r gy^ _Tot_a _ls_
59
1,778
10 Ifr/hr
B_pli_ds_ vater & sludge
0.03 0.15
85
Peed
Product and byproduct
Unrecovered heat
Conversion efficiency
on of Unrecovered Heat
Total Unrecovered heat
% of Unrecovered heat
wet cooled
Wet cooling load
Btu/lb evap
10 Ib water evap/hr
10 Btu/hr
18,3
67 %
6-04 10 Btu/hr
Btu/hr
1,375
793
-------
APPENDIX 11
WATER TREATMENT PLANTS
In this appendix we estimate the dollar and energy cost of the water
treatment sections of each process/site combination. The quantity of waste
sludge and waste soluble salts is also estimated. (The costs and energy
requirements for disposing of the wet-solid residual streams are not included
in this study.) The background information for this appendix will be found in
Reference 1.
In making these estimates the following sequence of decision and calcu-
lation is used:
1) Individual water treatment blocks are chosen and a water flow diagram
is made. The blocks used are described briefly in the following paragraph;
details are given in Reference 1. For convenience in presentation and to
avoid printing many similar diagrams, standardized flow diagrams, each
applicable to one or more processes at many sites, are given on Figure All-1
(A through E) and in Figure All-2 (Scheme 1 through Scheme 3).
2) For each process/site combination the flows of all streams are
entered on the summary Table All-4 (which has a page for each process/site).
The streams are entered by number, corresponding to the flow diagram. Since
water losses in waste sludge are accounted for, this step proceeds simul-
taneously with the next step. On each page of Table All-4 will be found
reference to the applicable flow diagrams.
3) For each treatment block at each process/site, the dollars cost, the
energy cost and the water produced are calculated and entered on the summary
table. Each result is the product of a unit cost and a parameter measuring
quality. The unit costs are given on Table All-1 and the quality parameters
on Tables All-2 and All-3.
Brief mention is now made of the treatment blocks used.
347
-------
Lime soda softening. This is used on cooling water makeup and blowdown,
and occasionally on total plant raw water or boiler feed. Theoretical lime,
soda ash and magnesia additions are assumed for cost estimation. The
treatment conditions are 1) Ca reduced to 20 mg/1, 2) Mg reduced to
7 mg/1, 3) 1 mg SiO removed per 2 mg Mg . Two or three probable locations
are shown on Figure 11-1; not all locations will be used at the same time.
Electrodialysis. This is required for all plants when the raw intake
water is brackish. The cost depends on the fraction of total dissolved
solids removed, and the fraction is taken to be one of four stages: 50%
demineralization, 75%, 87.5% 93.8%. The water recovery is 90%. Two locations
are shown, one on Figure All-1 and one on Figure All-2. In fact, they will
be separate streams in the same piece of equipment.
Ion exchange. This is required for all boiler feed water procedures.
The cost of the ion exchange depends on the quality of the intake water,
which is usually site dependent, and on the pressure of the steam raised in
the boiler. All the plants use a lot of high pressure steam for driving
machinery, but this condensate is returned with less than 2 percent loss. The
big need for boiler water makeup is for steam which enters into reaction.
Thus to some extent the Lurgi, SRC and Synthoil plants make lower
pressure steam at less cost, and Hygas, Bigas and Synthane make higher
pressure steam at more cost for boiler feed water treatment. Based on
Reference 1, three ion exchange systems have been chosen and costed; they
are shown on Figure All-2. Scheme 1 is the general purpose scheme for
reasonable river water. Scheme 2 is for presoftened high alkalinity water.
Scheme 3 is for brackish water intake.
Condensate polishing, while necessary, is minor and its cost is treated
as zero in the calculations.
Phenol extraction. This is a solvent extraction of phenolic compounds.
The phenols are recovered, which helps to defray the cost. This process is
used only when the foul condensate has a high concentration of phenol. The
process is not used for Lurgi or Synthane when the coal fed is bituminous.
It is not used for Hygas and Bigas processes. Ninety-five percent removal
is assumed. Since 1 mg phenol is equivalent to 2.38 mg BOD, the BOD is
reduced during phenol extraction by 2.26p, where p is the influent phenol
concentration.
348
-------
Ammonia separation. This is required at all process/sites. It is a
distillative, extractive process. Ammonia is assumed recovered as 30 wt %
solution and sold to help defray costs. Ammonia is usually reduced to
450 mg/1, at which concentration it is a suitable nutrient for subsequent
biotreatment.
Biotreatment. Because of lack of clear information on how much organic
contamination is acceptable in cooling water, this procedure is used on dirty
condensate from all plants except Bigas. Two multistage, high purity oxygen
activated sludge tanks are used in series and the removal percentage is high;
costs, energy and sludge are therefore calculated on the assumption of 100
percent removal.
Filter. Water effluent from dissolved air floation in biotreatment
contains about 100 mg/1 suspended solids. This is usually undesirable for
cooling tower feed. A sand filter is assumed to remove 80 percent of the
solids and to give a waste backwash stream which is 5 percent solids. The
filter backwash is returned to the biotreatment clarifiers and so is not
shown on the flow diagram.
Acid treatment of cooling water. This is used on all high alkalinity
cooling water makeup streams. Since more than 90 percent of the alkalinity
must be replaced to do any good, a 100 percent replacement is assumed.
Chemicals added to cooling water. Biocides, anticorrosion chemicals and
suspending agents are added to the cooling water. Their cost is shown on
Table All-1.
Potable water treatment. This is just chlorination; the quantity is
low and the cost is treated as zero.
Reverse osmosis. This 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. It is followed by activated carbon adsorption.
Activated carbon adsorption. This is used when treated condensate is
returned to a boiler.
The following additional notes apply to specific conversion processes.
Synthane. 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 circu-
lating cooling water at 10 cycles blowdown is removed, softened and used
349
-------
as makeup to the flue gas desulfurization scrubber. All Synthane plants are
shown on Figure All-lA.
Lurgi. Many Lurgi plants yield more treated condensate than is required
in the cooling tower. These plants use flow diagram Figure All-IB. When
all the condensate is consumed in the cooling tower, the same flow diagram
as Synthane is used (see Figure All-lA). 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.
Bigas. Figure All-1C 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. Synthoil plants take in large amounts of quench water into
the hydrogen production train and put out large amounts of condensate.
Figure 11-ID applies 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.
SRC. Figure All-IE is used for all 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,
and when high cycles are used the makeup is softened to ensure satisfactory
operation.
Hygas. Hygas plants use the same flow scheme as Synthane, in Figure
All-lA.
350
-------
REFERENCE - APPENDIX 11
1. Goldstein, D.J. and Yung, D., "Water Conservation and Pollution Control
in Coal Conversion Processes," Report EPA-600/7-77, U.S. Environmental
Protection Agency, Research Triangle Park, N.C., June 1977.
351
-------
Streams are numbered for identification
OJ
Ul
21
24
25
28
1
(REVEGETATION^)
27
i
POTABLE
WATER
TREATMENT
u
/"SERVICE & A
\SANITARY USE,/
20
35
20
(EVAPORATION)*^
N
Flow rates are given in Appendix 11 lw" "ซ>tn
( RESERVOIR ")-^-* EVAPORATION ( RESERVOIR )-J1* EVAPORATION
i' " '
3 3
SOFTENER NO. 1 [f> SLUDGE SOFTENING NO.l f^>SLUDGE
n ' 1 . iซ iv
BOILE
TREA
FIG.
*5 ซ 2 ,,
R FEED *
H-2 " ,,,cTr ^- BOILER FEED CARBON
|8 '" V- TREATMENT ADSORPTION'
,. rnNnFNSATF a [' |
POLISHING 1 M CONDENSATE REVERSE
IT ( REVEGETATION ) POLISHING OSMOSIS
,, /- ^\ ' |7 //
53 { PROCESS ) * \^-
^ J 1 .13 f \ WASTF
1 " * \ PROCESS I
IB A ^ . '
EXTRACTION * PHENOL POTABLE WATER 1ฐ
i ' TREATMENT PHENOL ป. PHENOL
Lป 1 -T- 1 EXTRACTION 1^
us |9
AMMONIA _^ AII10NIA * ^
SEPARATION ' / SERVICE & ^\ AMMONIA
I 1 nrnunitt ^ fiMMnuTfl
5 (
-* BIOTRE/
[ FIL1
10 \^ANIIAKT Ubty SEPARATION -"-""
.TMFNT => 51 UDGF 'In
29 V
18 * BlUIRtAIMtNl ^>SLUDlit
, ,, 18 k
rER I " I * 1
FILTER
/- DUST A f cr.n >( ซ ,
32
I,
/ N V CONTROL J \"" J " /'DUST \ S '
*f rnnt i ur \ ^ i ' 13 ' r 1 / FRn
^ TOWER ) C COOLING ^ Vj^TRGL^ V,
(AS
DISPC
39 31 ISOFTFNFR I ,n ^-^. luiitn y
,5 I NO 3 I .. v..^^ 1 "
H ^\ "v ^ ' i 15
SAL ^) SLUDGE ^ ASH "^
^DISPOSAL J
Figure A11-1A. Hater treatment plant block diagram for all Synthane,
some Luxgi and all Hygas.
Figure All-IB. Water treatment plant
Block diagram for some Lurgi.
Figure All-1 Water treatment block diagrams.
-------
RAW WATER
Streams are numbered for identification
Flow rates are given in Appendix 11
RAW WATER
U)
LJ
C RESERVOIR y^-* EVApOWTION
21
1
1
j.3
| SOFTENING NO.l |=>SLUDGE
s
U
-4
5
,, BOILER FEED
TREATMENT ฑ> WASTE
FIG. 11-2
27 " ja
1 34 t CONDENSATE
POTABLE WATER POLISHING
TREAlMtNV
} A /" :
7
[ PROCESS )
( SERVICE i }
\SANITARY USE/ - ^^
SEPAR
PACICAGE
SEWAGE PLANT
29
10
e
A!?ON ^AMMONIA
10
11
13
14
32 r rmi ING "N 37
\, TOWER J ซ '
33 >^
/
(^EVAPORATION)^ j
38 ^ ' ;
^CONTROL J C FG
1
31 SOFTFNINR -K...
NO. 3 -^5LU
/" ASH A
^DISPOSAL J
21
24
25
2fl
1
( REVEGETATION)
r
POTABLE WATER
TREATMENT
I"
/"SERVICE & ^\
\S_ANITARY USE^/
29
30
EVAPORATION)*^'
^ RESERVOIR 3-^^ EVAPORATIO
h
33
23
^
'
SOFTENING NO.l [:
(5
BOILER FEED
TREATMENT -^
FIG. 11-2 ""
I
CONDENSATE
POLISHING
S ^
*f PROCESS J
PHENOL
EXTRACTION
I"
AMMONIA ,
SEPARATION
I10
BIOTREATHENT -
f)
35
32
^
31
(
FILTER |
14
^ COOLING A
^ TOWER J
39
15
^ ASH A
v DISPOSAL J
^> SLUDGE
> WASTE
ป PHENOL
AMMONIA
> SLUDGE
le
ia
( DUST
Figure All-ID. Water treatment block diagram for Synthoil process.
Figxure AA1-1C. Water treatment plant block diagram
for Bigas process.
Figure All-1 (continued)
-------
Streams are numbered for identification
Flow rates are given in Appendix 11
RAW WATER
RESERVOIR )-22-ป EVAPORATION
33
U>
Ul
SLUDGE
Figure All-IE. Hater treatment block diagram
for SRC process.
Figure All-1 (concluded)
-------
WEAK-ACID
IX
>
r
STRONG-AGIO
IX
>
(
WEAK-BASE
IX
>
r
STRONG-BASE
IX
MIXED BED
IX
SCHEME 1
u>
Ln
Ln
|
STRONG-ACID
IX
>
r
WEAK-BASE
IX
1
MIXED BED
IX
ฑ-
SCHEME 2
BRACKISH
WATER
i
r
WEAK
ACID
IX
\
DEGASIFIER
ELECTRODIALYSIS
No. 1
>
r
STRONG
ACID
IX
>
r
WEAK
BASE
IX
>
r
STRONG
BASE
IX
1
MIXED
BED
IX
...w
SCHEME 3
Figure All-2. Boiler feed water treatment schemes.
-------
$ x 103
UJ
<_n
CFi
oo
o
o
GO
600
500
400
300
200
100
0
(103 gpm)
0.6 gpm/ft
8 9 10
Figure All-3. Clarifier
costs.
-------
1
2
3
4
One Stage, approximately 50% demineralizatlon
Two Stages, approximately 75% demineralization
Three Stages, approximately 87.5% demineralization
Four Stages, approximately 93.8% demineralization
13
CX
60
J-l
c
01
O)
01
D.
rt
0=2
0.0
0.5 1 2 4 6 8 10 20 40 60 80 100
Capacity (10 gal/day)
Figure All-4 Approximate electrodialysis capital investment
as a function of capacity for various numbers
of stages. (Each stage removes approximately
50% of salts in its feed water).
357
-------
TABLE All-1. WATER TREATMENT BLOCKS AND OTHER COSTS
Ln
CD
Lime Soda Softening
Cos t: clarifiers: capital cost is taken from Figure 11-3 with the
result multiplied by 2.0 for updating and spare
capacity. To enter Figure 11-3, note that
10 Ub water/hr - 0.002 x 10 gpm.
Capital charges axe 12*/yr for 7000 hours per
year; so if
Y - installed cost in 10 5 from Figure 11-3
charges are
2Y x 103 x 0.12/7000 S/hr
- 3.43Y C/hr.
chemicals: costs are given below.
Energy; negligible.
was te: Based on dry weight of CaCO^ precipitated with the sludge
assumed to be 20* solids.
Waste:
Electricity charges are 0.8C/I10 gallons)(100 mg/1 removed),
so if z is the reduction of TDS in mg/1, electricity charges
are 0.000960 zQ C/hr.
Total charge in C/hr is
1.14 YQ + 2.40 Q + 0.000960 zQ
0.4 kw-hr/(103 gallons) (100 mg/1 removed),
- 0.000480 z kw-hrs/103 Ib water
5.62 zQ Btu/hr.
10% of the feed flow
Ion Exchange (see Figure 11-2 for schemes)
Cost: Scheme 1
Scheme 2:
Scheme 3:
Negligible
6% of feed water
10.5 Q C/hr for Hygas, Bigas (. Eynthane
9.5 Q C/hr for Lurgi, Synthoil & SRC
Where Q - flow rate.io3 Ib water/hr
6.5 Q C/hr
11.5 Q C/hr not including the electrodialysis
Electrodialysis
Cost:
The cost is the sum of capital charges, membrane replacement,
etc., and electricity.
Capital cost is taken from Figure 11-4 and multiplied by 1.35 to
update. To enter Figure 11-4, note that
103 Ib/hr - 0.00288 x 106 gal/day.
Capital is charges at 17%/yr for 7000 hrs/yr and if
Y - capital investment shown on Figure 11-4
Q ซ flow rate, 103 Ib water/hr.
Phenol Extraction
Cost: 300 C/thousand gallons, 36C/10 Ib, 36Q C/hr where Q is the
feed rate in 103 Ib/hr. Sale of phenol yields 2.3C/lb phenol.
If y is phenol concentration in the feed stream in mg/1 the
rate of recovery of phenol is 0.95 y Q/1000 Ib/hr.
The net process cost, in C/hr, is
36 0 - 0.00219 yQ.
Energy; 10 Btu/thousand gallons; 120,000 0 Btu/hr.
Waste: negligible
charges are
(1.35Y)(Q/0.00288)(0.17J/7000 S/hr
- 1.14 YQ C/hr.
Membrane charges are 20C/thousand gallons of throughput, or
2.40 0 C/hr.
-------
OJ
Ln
ID
Table AJ.1-1 (cc..tinued)
Ammonia Separation
Cos C :
Biotreatment
Gas plants: MGD < 1.5, cost = [4.75 - 0.5 MGD) 5/10 gals
where MGD 106 gallorus feed/day.
That 13, if C - feed in 103 Ib/hr.
Q < 520; cost - 157.0 - 0.0173 Q] Q C/hr.
If Q _> 520, cost - S4/103 gallons,
that is 4 3 0. C/hr.
SRC & Synthoil: Q < 867, cost =. (63.0 - 0.01730.1 Q C/hr.
Q .> 667; cost - 48 Q c/hr.
All plants; credit 7C/lb ammonia recovered.
If y is the concentration of airmonia in the feed streajn in
mg/1, the rate of recovery of ajnmonia is
(y - 450) Q/1000 Ib/hr,
The value of the recovered anunonia is
0.007 (y - 450)Q C/hr.
1.7 x 10 Btu/thousand gallons; 204,000 Q Btu/hr.
Lose 2. 3 Ib water/Lb amronia recovered.
Cos t: A-L1 Hygas S bituminous coals in Lurgi and Synthane:
2.5C/lb BOD removed, that is 0.0025 yQ C/hr, where
y ซ BOD concentration in mg/1 and Q ป feed rate in 10 Ib/hr
All SRC & Synthoil, and subbituminous coals and lignites in
Luxgi and Synthane:
2.1 f/lb BOD renoved, that is 0.0021 y<2 */hr.
Energy: All plants: 4 Btu/lb BOD removed, that is 4 yQ Btu/hr.
Waste: 0.1 Lb dry waste/lb BOD removed. Cost includes dissolved
air flotation and vacuum filtration and sludge is discharged
at 20ซ solids.
Filter
Cost:
Capital cost is 5100/gpm = S200/10 Ib/hr. Charges are
12%/yr for 7000 hrs/yr, so operating cost is:
S200 x 0.12/7000 - 0.343 c/hr for 10 Ib/hr.
Negligible
None. Backwash is returned to clarifiers in biotreaUnent.
Acid Treatment of Cooling Water
Cost:
Chemicals
Cost:
If x ซ mg/1 HCO-j then x/61 = meq/1 HCO-j. 100* replacement
by H2S04 (equivalent weight 49) means (49/61) x mg/1 acid.
Cost: 3
0.00305 xQ C/hr where Q = flowrate in 10 Ib/hr.
3.8 e/ib
2.7
-------
Table All-1
Reverse Osmosis
Coat; ซ/10 water treated - 19.5 - 0.0043Q where g is flowrate in
103 Ib/hr; therefore
f/hr - 19.50. - 0.0043Q2
Sequestering chemicals are included in the cost.
Haste: 10* of feed water.
Activated Carbon Adsorption
Cost; $1/10 gallons treated - 12 0 C/hr.
Energy: 4,500 Btu/10 Ib water treated - 4,500 0 Btu/hr.
Waste; Negligible.
U>
CTi
O
-------
TABLE All-2. EFFLUENT WATER QUALITY
Concentrations in
Phenol as C,H,OH
b b
Ammonia as NH
BOD
Ca**
f+
Mg
HCO ~
Sulfide as S
Sฐ4ฐ
Phenol as C^H.OH
6 b
Amoonia * ? NH
BOD
-M-
Ca
Mg**
HCO
ng/1
SRC ฃ Synthoil
Hydxoge nation
section
condensate
All Coals
6,000
13,000
30,000
v. 20
x. 15
4,000
14,000
s
Synthane fi Lurgi
Dirty condensate
Subbi tuminous
ฃ Lignite
6,000
7,000
20,000
x, 20
v- 15
14,000
Bigas
condensate
All Coals
s
4,500
s
x. 120
x. 50
x, 100
3
-x, 100
Synthane
SRC ฃ Synthoil
Gasification
Condensate
s
a
B
-v. 120
x. 50
x, 100
3
x, 100
Synthane
Medium quality Medium quality
condensate
Bi tuminous
Coals
300
500
1,000
s
3
1,000
condensa te
Subbi tuminous
ฃ Lignite
600
500
2,000
s
s
1,000
Synthane ฃ Lurgi
Dirty condensate
Bi tuminou3
Coals
3,000
7,000
10,000
V 20
V 15
14,000
1,000
s
Hygas
Dirty
condensate
Bituminous
Coals
300
4,500
2,000
v 20
X. 15
11,000
Effluent
Hygas from Effluent
Dirty -condenaata Methanation Phenol from
Subbituminous water Extraction Ammonia
ฃ Lignite All Plants (see Note 1) Separation
Phenol as C H OH 4,000 O.OSp
Ammonia as NH 4,500 s unchanged 450
BOD 14,000 b - 2.26p
Ca** -x- 20
Mg** 1- 15
HCO3~ 11,000 a
Sulfide as S a
4
Effluent
from
Biotreatment
(see Note 2)
Phenol as C.H..OH
o b
Ammonia as NH_ ~~
3
Note 1. p ป mg/1 phenol in
BOD influent
^w- ^ 6Q t - mg/1 BOD in influenl
++ Note 2. Lime added to neutralizi
and carbon dioxide
HCO - -x, 4o added by treatment.
Sulfide as S
4
Sulfide as S
ป small
-------
TABLE All-3. RAW WATER QUALITIES
Concentrations in
Concentrations in mq/1
LJ
CTi
SOURCE
PROCESS
SITE
-n-
Ca
Mg"
HCO
so/
TDS
sio2
pH (units)
SOURCE
PROCESS
SITE
Ca++
H-
M9
HC03-
Sฐ4~
TDS
Si02
pH (units)
Tombigbee R. at
Jackson, Ala.
Hygas, Lurgi, SRC
Harengo, Ala.
15
3.1
53
18
91
9.1
6.9
Illinois R. at
Harseilles, 111.
Bigas
Bureau, 111.
69
24
247
102
466
7
7.5
Alabama R. at
Selma, Ala.
Hygas, Synthane,
Eynthoil
Jefferson, Ala.
12
3.2
53
92
76
7
7.3
Well water from
Alluvial Ground at
Bureau, 111.
Bigas, Lurgi, SRC
Bureau, 111.
60
18
200
90
360
7.5
7.4
Well water at
Harengo, Ala.
Hygas, Lurgi, SRC
Harengo, Ala.
2.4
0.4
600
17
880
9
8.3
Ohio R. at
Grand Chain. 111.
Bigas, Lurgi, SRC
St. Clair,. White.
Saline, Shelby, 111.
36
9
106
60
209
6.5
7.4
SOORCE
PROCESS
SITE
Ca++
Hg^
HCO3~
so/
TDS
Si02
pH I units )
SOURCE
PROCESS
SITE
C."
Kg*4
HCOj"
so4
TDS
Si02
pH (units)
Green R. at
Beech Grove, Ky.
Lurgi
Muhlenberg, Ky ,
39
9
115
54
191
5.9
6.9
Kanawha R. at
Kanawha Falls,
W.Va.
Hygas, Synthane
Synthoil
Fayette, Kanawha,
Preston, Mingo, W.Va
21
5
62
29
134
7.3
7.1
Huskingum R. at
McConnelsville, Ohio
Hygas, Synthoil
Tuscarawas, Ohio
83
17
132
145
582
6.3
7.2
Well water from
Alluvial Ground at
Tuscarawas , Ohio
Hygas, Synthoil
Tuscarawas, Ohio
75
20
217
60
363
7
7.5
Allegheny R. at
Oakjnont, Pa.
Hygas, Synthane,
Synthoil
Armstrong, Somerset, Pa.
Monongalia, W.Va.
34
10
17
108
215
7
6.2
-------
Table All-3. (continued)
Concentrations in pg/1
Concentrations in tag/1
u>
en
u>
SOURCE
PROCESS
SITE
Ca*+
-I-+
Hg
HCO/
50 4~
TDS
sio2
pH (units)
Ground water
Lurgi , SRC
Fulton, 111.
90
50
250
1000
2000
9.0
7.7
White R. at
Hazleton, Ind.
Hygas, Synthane,
Synthoil, Bigas
Gibson, Vigo,
Sullivan, Ind.
51
16
166
110
269
5.7
7.7
Ohio R. at
Cannelton Dam, Ky.
Hygas, Synthoil,
Synthane
Warrick, Ind., Floyd,
Harlan, Pike, Ky .
Gallia, Jefferson, Ohio
3B
10
97
69
216
4.6
7.1
SOURCE
PROCESS
SITE
Ca~
Mg~
HCO^
so,"
TDS
sio2
SOURCE
PROCESS
SITE
Ca~
ป9~
HCO/
Sฐ4"
TDS
Sio2
Tongue R. at
Goose Creek below
Sheridan, Wyo.
Synthoil
Lake de Smet, Wyo.
59
36
245
137
451
8.3
Green R. below
Green River, Wyo.
Synthoil, Lurgi, SRC
Jim Bridger,
Rainbow IB, Wyo.
55
21
175
164
394
5.7
Medicine Bow R.
above Seminee Res.,
near Hanna, Wyo.
Hygas
Hanna, Wyo.
109
60
189
537
945
7.4
Beaver Creek near
Newcastle, Wyo.
Hygas, Synthane, SRC
Antelope Creek, Wyo.
446
156
183
1802
4667
6.8
Hams Fork near
Granger, Wyo.
Bigas, Lurgi
Kennnerer, Wyo.
65
30
211
171
429
4.2
Ground water
SRC
Otter Creek, Mont.
70
100
600
1200
2200
12
-------
Table All-3. (continued)
Concentrations in tog/1
Concentrations in
SOURCE
PROCESS
SITE
Cn*"*
wg^
HCO
SO/
TDS
sio2
SOURCE
PROCESS
SITE
Ca~
-H-
Mg
HCO ~
S04~
TDS
Si02
Yellowstone R. at
Terry, Mont.
Bigas
Slope, N.D.
54
21
173
187
424
9.6
Missouri R. near
williston, N.D.
Lurgi
Hilliston, N.D.
62
21
191
176
436
9.3
Knife R. at
Hazen, N.D.
Lurgi, Bigas, SRC
Bently, Center,
Knife River, N.D.
69
39
511
419
1037
11
Grand River at
Shadehill, S.D.
Biga,
Scranton, N.D.
39
21
363
412
931
5.6
Lake Sakakawea, N.D.
SFC
Underwood, Dickinson, N.D.
49
19
181
170
428
7
San Juan R. in N.M.
Hygas , Lurgi
Wesco, El Paso, N.M.
55
9
143
114
300
12
SOURCE
PROCESS
SITE
Ca~
Mg~
HCO/
S04~
TDS
Si02
SOURCE
PROCESS
SITE
Ca++
Mg~
HC03~
Sฐ4~
TDS
sio2
Yellowstone R. in
Mont.
Hygas, Syn thane, SRC
Colitrip, Mont.
40
14
138
109
284
10
Missouri R. at
Culbertson, Mont.
SRC
Coalridge, Mont.
63
21
197
168
427
6.3
Powder R. at
Arvada, Wyo.
Hygas , Synthane
Spotted Horse, Wyo.
East Moorehead, Mont.
138
69
247
769
1580
9.5
Yellowstone R. , average
between Sidney, Terry,
Mont.
Bigas
U.S. Steel, Mont.
55
21
183
197
439
10
Tongue R., average between
Decker, Miles City,
Mont.
Lurgi , SRC
Pumpkin Creek,
Foster Creek, Mont.
52
36
222
167
328
e
Crazy Woman Creek at
Upper Station near
Arvada, Wyo.
Hygas, SRC
Belle Ayr,
Gillette, Wyo.
133
66
216
620
1046
"
-------
Table All-3. (continued)
Concentrations in mg/1
OJ
O^
Ln
SOURCE
PROCESS
SITE
Ca~
H9~
HCO3"
Sฐ<"
TDS
Sio2
Well vater
Hygas, Lurgi
Decker, Mont.
13
6
1700
13
2400
7
Groundwater in N.h.
Hygas, Lurgi,
Synthoil
Gallup, N.H.
12
13
408
509
2655
5.6
Colorado River
near Glenwood Springs, Col
Paraho Direct, Paraho
Indirect, TOSCO II
Parachute Creek, Colo.
61
20
137
98
589
14
-------
TABLE All-4 WATER TREATMENT PLANTS
LURGI
366
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Site Williston, N.D.
Lurgi
Site Decker, Mont.
CT>
Flow Diagram Figure A11-1A
Flow rates by stream number (10 Ib/hr):
1- 2456 10. 1868 21. 847 31. 150
3. 1609 11. 1868 22. 8 32. 826
4. 1609 14. 1427 24. 0 33. 268
5- 1609 15. 75 25. 847 34. 268
6. 1512 16. 455 26. 0 36. 0
7. 1780 17. 264 27. 21 37. 150
8. 1B97 18. 191 28. 21 39. 225
9. 1897 20. 2028 29. 14 40. 2464 RAW WATER
Treatment blocks:
waste (103 lฑ>/hr>
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening -No. 1 NOT USED
Lime-Soda Softening - No. 3 907 0.09 0.45
Ion Exchange - Scheme 1 15,300 97
Phenol Extraction 43,400 228
Aimwnia Separation (-5,410) 387
Biotreatment 25,300 48 1.20 4.8
Filter 489
Acid addition to cooling water 655
Other chemicals to cooling water 4,120
Total 84,800 663
Flow Diagram Figure All-lA
Flow rates by stream number (10 Ib/hr):
1. 2472 10. 1168 21. o 31. 134
3. 2472 11- 1168 22. 9 32. 680
4. 2225 14. 987 24. 701 33. 265
5. 1524 15. 33 25. 701 34. 265
6. 1433 16. 195 26. 0 36. 0
7. 1698 17. 86 27. 21 37. 134
B. 1186 18. 109 28. 21 39. 167
9. 1186 20. 1500 29. 14 40. 2481 RAW WATER
Treatment blocks:
waste (10 Ib/hr)
sludge or
*/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USEฃ)
Lime-Soda Softening - No. 3 905 0.08 0 40
Electrodialysis' 12,700 33.3 247
Ion Exchange - Scheme 3_ 17,500 91
Phenol Extraction 27,100 142
Ammonia Separation (-3,380) 242
Biotreatment 16,000 30.6 0.75 3.8
Filter 339
Acid addition to cooling water 1,200
Other chemicals to cooling watec 3,060
Total 75,400 448
*Located roughly in place of Softening No. 1.
-------
TABLE All-4. HATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Flow Diagram Figure All-IB
Ftov rates by stream number (10 Ib/hr):
i. 1307 10.1353 20. 806 29.14
2. 1286 11-1353 21. 21 32. 170
3. 1286 12.0 22. 5 33. 265
4. 1286 13.1063 23. 153 34. 265
5. 1439 14.1063 24. o 36. 0
&. 1353 15.87 25. 21 38. 0
7. 1618 16.304 26. 0 39. 87
OJ a 1362 17.166 27. 21 40. 1312 RAW HATER
O^
CO 9. 1362 18.138 28. 21
Treatment blocks:
waste (103 lb/hr>
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Ion Exchange - SchenK 1_ 13,700 86
Phenol Extraction 31,100 163
Armenia Separation (-3,880) 27.8
Biotreatment 18,300 34.9 0.87 4.4
filter 365
Acid addition to cooling water 130
Other chemicals to cooling water 1,590
Reverse Osmosis 3,190 1.7 17
Activated Carbon Adsorbtion 1,840 0.69
Total 66'30ฐ 228
Process Lurgi Site El Paso, N.H.
Flow Diagram Figure A11-1A
Flow rates by stream number (10 Ib/hr) :
1. 171S 10. 1064 21. 258 31. 0
3. 1457 11. 1064 22. 10 32. 159
4. W57 14. 699 24. 0 33. 270
5. H57 15. 190 25. 258 34. 270
6. I370 16. 375 26. 78 36. 0
7. I640 17. 241 27. 21 37. 0
8. 1ฐ80 18. 134 28. 21 39. 189
9- 1080 20. 79j 29. 14 40. 1725 RAW WATER
Treatment blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 Ncrr USEQ
Lime-Soda Softening - No. 3 NOT USED
Ion Exchange - Schema 1 13,900 88
Phenol Extraction 24,700 130
Ainnonia Separation (-3,080) 220
Biotreatnent 14,600 27.8 0.69 3.5
Filter 240
Acid addition to cooling water I54
Other chenicala to cooling water 3,460
Total 54,000 378
-------
TABLE All-4. HATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process Lurqi
Site
We3co, N.M.
Site Gallup, N.H.
Flow Diagram Figure All-LB
Flow rates by stream number (10 Ib/hr) :
1.
2.
3.
4.
5.
6.
7.
8.
9.
1854
1754
1754
1754
1787
1680
1990
1-190
1490
10.
11.
12.
13.
14.
15.
16.
17.
18.
. 1468
. 1468
.0
. 1085
. 1085
, 256
. 397
261
136
20.
21.
22.
23.
24.
25.
26.
27.
28.
| .LIJ- vj i , *_: .
Flow Diagram Figure A11-1A
Flow rates by stream number (10 Ib/hr):
792
100
11
33
0
100
79
21
21
29.
32.
33.
34.
36.
38.
39.
40.
14
37
310
310
0
0
254
1865 RAH WATER
1.
3.
4.
5.
6.
7.
8.
9.
1768
1768
1654
1410
1325
1603
1007
1007
10.
11.
14.
15.
16.
17.
18.
20.
992
992
716
38
290
188
102
792
21.
22.
24.
25.
26.
27.
28.
29.
0
6
244
244
59
21
21
14
31.
32.
33.
34.
36.
37.
39.
40.
50
164
278
278
0
50
88
1778 RAW WATEI
Treatment blocks:
Lime-Soda Softening - No. 1
Ion Exchange - Scheme 1
Phenol Extraction
Ammo ru. a Separation
Biotreatment
Filter
Acid addition to cooling water
Other chemicals to cooling water 4,650
Reverse Osmosis
Activated Carbon Adsorbtion
Tnt-Al 72,900
17
34
(-4
19
4
C/hr
,000
,100
,250)
,900
372
132
,650
716
396
waste (10 Ib/hr)
sludge or
10 Btu/hr dry solution
NOT USED
107
179
304
37.8 0.95 4.8
0.37 3.7
0.15
Treatment blocks:
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Electrodialysis *
Ion Exchange - Scheme 3
Phenol Extraction
Ammonia Separation
Biotreatment
Filter
Acxd addition to cooling water
Other chemicals to cooling water
Total
C/hr
892
6,090
16,200
23,000
(-2,870)
13,400
246
226
1,610
waste (10 Lb/hr)
sludge or
10 Btu/hr dry solution
NOT USED
0.03 0.15
16.5 114
85
121
205
25.6 0.64 3.2
58,800
521
Located roughly in place of Softening No. 1.
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process Lurqi
Site
Flow Diagrajn Figure All-IB
Flow rates by streajn number (10 Ib/hr) :
1. 810
2. 769
3. 789
4. ?89
5. 16o:!
6. 1507
7. 1767
u. s- 2325
0
Treatment blocks:
10. 2290 20. 980 29. 14
11- 2390 21. 21 32. 904
12. 874 22. 0 33. 260
13. 1089 23. 814 34. 260
14. 1963 24. 0 36. 0
15. 79 25. 21 38. 30
16. 341 26. 0 39. 109
17. 211 27. 21 40. 810 RAW WATER
18. 13ฐ 28. 21
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime- Soda Softening - No. 1 NOT USED
Ion Exchange - Scheme 1 15,200 96
Phenol Extraction 53,200 297
Ammonia Separation (-6,630) 474
Biotreatment 36,900 59.0 1.47 7.4
Filter 670
Acid addition to cooling water 130
Other chemicals to cooling water 2,000
Reverse Osmosis 14,100 9.04 90.4
Activated Carbon Adsorbtion 9,770 3.66
Total
125,000 825
Flow Diagrajn Figure All- IB
Flow rates by stream number (10 Ib/hr) :
1. 810 10.2290 20. 980 29. 14
2. 789 11.2290 21. 21 32.904
3. 789 12.874 22. 0 33. 260
4. 789 13.1089 23. 814 34. 260
5. 1603 14.1963 24. 0 36. 0
6. 1507 15.79 25. 21 38. 30
7. 1767 16.341 26. 0 39. 109
8. 2325 17.211 27. 21 40. BIO RAW WATER
9. 2325 18.130 28. 21
Treatment blocks:
waste (103 Ib/hr)
sludge or
*/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Ion Exchange - Scheme 1 10,400 96
Phenol Extraction 53,200 279
Ammonia Separation (-6,630) 474
Biotreatment 36,900 59.0 1.47 7.4
Filter 670
Acid addition to cooling water 130
Other chemicals to cooling water 2,000
Reverse Osmosis 14,100 9.04 90.4
Activated Carbon Adsorbtion 9,770 3.66
Total 121,000 825
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process Lurgi
Site Fulton, Illinois
Flow Diagram Figure All-IB
Flow rates by stream number (10 Ib/hr) :
1.
2.
3.
4.
5.
6.
7.
a.
OJ
~J 9.
2058
1831
2058
1852
2585
2430
2707
2158
2158
10.
11.
12.
13.
14.
15.
16.
17.
18.
. 2125
727
1149
1149
1876
80
263
205
58
20.
21.
22.
23.
24.
25.
26.
27.
28.
1034
0
0
754
21
21
0
21
21
29.
32.
33.
34.
36.
38.
39.
40.
14
762
277
277
0
35
115
2058 RAW WATER
Flow Diagram Figure All-IB
Flow rates by s
1.
2.
3.
4.
5.
6.
7.
8.
9.
1478
1457
1457
1457
2346
2205
2496
1918
1918
itream number (10 Ib/hr) :
10
11.
12.
13.
14.
15.
16.
17.
18.
.1889
.1889
.979
.592
.1571
.50
,332
280
52
20.
21.
22.
23.
24.
25.
26.
27.
28.
533
21
0
889
0
21
0
21
21
29.
32.
33.
34.
36.
38.
39.
40.
14
988
291
291
0
9
59
1478 RAW WATE
Treatment blo_cXs_;
Lira-Soda Softening - No. 1
Electrodialysis*
Ion Exchange - Scheme 3_
Phenol Extraction
Ammonia Separation
Biotreatment
Filter
Acid addition to cooling water
Other chemicals to cooling water
Reverse Osmosis
Activated Carbon Adsorbt-ion
Total
"Located in place of Softening Ho
10,100
29,700
waste (10 Lb/hr)
sludge or
10 Btu/hr dry solution
Not Used
23
63,000
(-6,150)
17,100
654
154
2,100
12,400
9,050
138,000
. 1.
259
440
55.6
7.62
3.4
789
206
155
3.42
7.6
Treatment blocks:
Lime-Soda Softening - No. 1
Ion Exchange - Scheme j
Phenol Extraction
Ammonia Separation
Biotreatment
Filter
Aci d addition to cooling water 300
Other chemicals to cooling water 1,060
Reverse Osmosis 15,100
Activated Carbon Adsorbtion 10,700
Total 114,000
22,300
43,800
(5,470)
25,900
539
waste (10 Ib/hr)
sludge or
10 Btu/hr dry solution
NOT USED
140
230
391
49.4 0.61 3.1
9.88
4.0
-------
Process Luroi
TABLE All-4. WATER TREATMENT PLANTS
Site Bureau, Illinois
TABLE All-4. WATER TREATMENT PLANTS
Process Luroi
Site St. Glair, Illinois (surface mining)
Flow Diagram Figure A11-1A
Flow rates by stream number (10 Ib/hr) i
1. 2628 10. 2117 21. Q 31- 138
3. 2628 11. 2117 22. o 32. 39
4. 2628 14. 1913 24. 60 33. 279
5. 2568 15. 57 25. 60 34. 279
6. 2414 16. 218 26. 0 36. o
7. 2693 17. 68 27. 21 37. 138
8. 2149 18. 150 28. 21 39. 195
9. 2149 20. 1757 29. 14 40. 2628 RAW WATER
Treatment blocks:
waste (103 Ib/hr)
sludge or
ซ/nr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 2,300 1.3 6.3
Lime-Soda Softening - No. 3 905 0.08 0.4
Ion Exchange - Scheme 2 16,700 150
Phenol Extraction 63,300 258
Ammonia 'Separation (-6,130) 438
Biotreatment 17,100 27.3 0.68 3.4
Filter 656
Acid addition to cooling water NOT USED
Other chemicals to cooling water 3,570
Total 98,400 723
Flow Diagram Figure AJ.1-LA
Flow rates by stream number (10 Ib/hr) :
1. 2653 10. 2057 21. 70 31. 110
3. 2583 11. 2057 22. 0 32. 49
4. 2583 14. 1898 24. 0 33. 277
5. 2583 15. 85 25. 70 34. 277
6. 2428 16. 173 26. 0 36. 0
7. 2705 17. 117 27. 21 37. 110
8. 2089 18. 56 28. 21 39. 195
9. 2ฐ89 20. 1752 29. 14 40. 2653 RAW WATER
Treatment blocks:
waste (103 Ib/hr)
, sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NQT USฃD
Lime-Soda Softening - No. 3 g0i o 07 0 33
Ion Exchange - Scheme T 24,500 160
Phenol Extraction 61,500 252
Ammonia Separation (-5,950) 426
Biotreatment 16,600 26.5 0.66 3.3
Filter 651
Acid addition to cooling water 247
Other chemicals to cooling water 3,570
Total 102,000 705
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
LUTQi
St. Clair, Illinois (underground coal mine) Process Lurgi
Site
Jim Br_idger_, Wyo.
Flow Diagram Figure A11-1A
Flow Diagram Figure A11-1A
rates by stream number (10 Ib/hr)i
Flow rates by stream number f10 Ib/hr)!
1. 2736 10. 2057 21. 153 31. 110
3. 2583 11. 2057 22. 0 32. 132
4. 2b83 14. 1815 24. 0 33. 277
5. 2583 15. 85 25. 153 34. 277
ฃ,. 2428 16. 256 26. 0 36. 0
7. 2705 17. 117 27. 21 37. 110
8. 2089 18. 149 28. 21 39. 195
g_ 20B9 20. 1752 29. 14 40. 2736 RAW WATER
Treatment blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 3 901 0.07 0.33
Ion Exchange - Scheme 1 24,500 160
Phenol Extraction 61,500 252
Ammonia Separation (-5,950) 426
Biotreatment 16,600 26.5 0.66 3.3
Filter 623
Acid addition to cooling water 264
other chemicals tc- cooling water 3,570
1. 1541 10. 1104 21. 125 31. o
3. 1416 11. 1104 22. 7 32. 104
4. 1416 14. 784 24. 0 33. 265
5. 1416 15. 81 25. 125 34. 265
6. 1331 16. 334 26. 0 36. 0
7. 1596 17. 234 27. 21 37. 0
8. 1121 18. 100 28. 21 39. Bl
9. 1121 20. 807 29. 14 40. 154B RAW HATER
Treatment blocks:
waste (103 Ib/hr)
sludge or
(/hi 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 3 NOT USED
Ion Exchange - Scheme 1 13,500 85
Phenol Extraction 25,600 135
Ammonia Separation (-3,200) 229
Biotreatment 14,900 28.4 0.71 3.6
Filter 269
Acid addition to cooling water 151
Other cheraicals to cooling water 1^480
Total 102,000 705
Total 52,700 392
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. HATER TREATMENT PLANTS
Lurgi
Site
Site
Knife River, N.D.
Flow Diagram Figure All-IB
Flow Diagram Figure All-IB
Flow rates by stream number (10 Ib/hr) : plฃ
1.
2.
3.
4.
5.
6.
7.
8.
9.
1917
1896
1896
1896
2536
2384
2656
1934
1934
10.
11.
12.
13.
14.
15.
16.
17.
18.
1905
1905
677
962
1639
62
280
216
64
20.
21.
22.
23.
24.
25.
26.
27.
28.
866
21
8
640
0
21
0
21
21
29.
32.
33.
34.
36.
38.
39.
40.
14
711
272
272
0
34
96
1925 RAW WATER
1.
2.
3.
4.
5.
6.
7.
e.
9.
jw rates by stream number (10 Ib/hr) :
1195
1174
1174
1174
1585
1490
1754
1694
1694
10.
11.
12.
13.
14.
15.
16.
17.
18.
1668
1668
435
934
1369
74
313
141
172
20.
21.
22.
23.
24.
25.
26.
27.
28.
838
21
4
411
0
21
0
21
21
29.
32.
33.
34.
36.
38.
39.
40.
14
457
264
264
0
22
96
1199 RAW WAI
Treatment blocks:
Line-Soda Softening - No. 1
Ion Exchange - Schema 1
Phenol Extraction
Ansnonia Separation
Biotreatment
Filter
Acid addition to cooling water
24,100
(-5,510)
47,600
562
200
Other chemicals to cooling water 1,760
Reverse Osmosis 11,700
Activated Carbon Adsorbtion
Total
7.680
10 Btu/hr dry
NOT USED
NOT USED
395
76.2 1.91
7.1
2.9
waste (10 Ib/hr)
sludge or
solution
152
9.5
71.0
88,000
Treatment blocks:
Lime-Soda Softening - No. 1
Ion Exchange - Scheme 1
Phenol Extraction
Ammonia Separation
Biotreatment
Filter
Acid addition to cooling water
Other chemicals to cooling water
Reverse Osmosis
Activated Carbon Adsorbtion
Total
ซ/hr 106 Btu/hr
NOT USED
15,100
38,700 203
(-4,830) 346
22,600 43.0
470
170
1,760
8,010 4.57
4,930 1.85
waste (10 Ib/hr)
sludge or
dry solution
95
1.1 4.3
46
86,900
-------
SOLVENT REFINED COAL
375
-------
TABLE All-4. WATER TREATMENT PLANTS
Process SRC
Process SRC
TABLE All-4. WATER TREATMENT PLANTS
Site Marengo, Ala. (ground water)
Flow Diagram Figure All-IE
Flow rates by stream number (10 Ib/hr) i
1- 1354 9. 247 21. 1273 29. 14
3- 455 10. 247 22. 0 32. 1252
4. 455 14. 259 24. 0 33. 376
5. 455 15. 96 25. 1273 39. 208
7. 428 18. 112 27. 21 40. 1354 RAW WATER
8. 247 20. 1303 28. 21
Treatment Blocxjs:
waste <103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 2 1,300 0.3 1.7
Electrodialysis NOT USED
Ion Exchange - Scheme 1 4,320 27
Phenol Extraction 5,630 29.6
Anmonia Separation (-7,200) 50.4
Biotreatment 8,540 16.2 0.4 2.0
Filter 89
Acid addition to cooling water 234
Other chemicals to cooling water 2,560
Total 15,500 96-2
Flow Diagram Figure All-IE
Flow rates by stream number (10 lฑ)/hr) :
1. 1354 9. 247 21. 1273
3. 455 10. 247 22. 0
4. 455 14. 259 24. 0
5. 455 15. 96 25. 1273
7. 428 18. 112 27. 21
8. 247 20. 1303 28. 21
Treatment Blocks:
ซ/hr 106 Btu/hr
Lime- Soda Softening - No. 1 N&p USED
Lime-Soda Softening - No. 2 1,300
Electrodialysis NOT USED
Ion Exchange - Scheme _j 4 320
Phenol Extraction 5,650 29 6
Ammonia Separation (-7,200) 50.4
Biotreatment a S3o
Filter 89
Acid addition to cooling water 2,323
Other chemicals to cooling water 2,560
Tot^1 17,600 119
29. 14
32. 1252
33. 376
39. 208
40- 1354 RAW WATER
waste (103 Ib/hr)
sludge or
dry solution
0.3 1.7
27
0.4 2.0
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process SRC
Site Bureau, 111, (well water)
Process SRC
Site White, 111.
Flow Diagram Figure All-IE
Flow Diagram Figure All-IE
Flow rates by_stirtiam nlumber (10 Ib/hr):
Flow rates by stream number (10 Ib/hr):
1. 1747 9- 81 21. 0 29. 14
3. 1853 10. 81 22. 0 32. 1518
4. 1846 14. 94 24. 1539 33. 106
5. 307 15. 69 25. 1539 39. 208
7. 290 18. 139 27. 21 40. 1747 RAW WATER
8. 81 20. 1406 28. 21
Treatment Blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 2,670 1.5 7.0
Lime-Soda Softeninq - No. 2 NOT USED
Electrodialysis NOT USED
Ion Exchange - Scheme 2 2,000 I7
Phenol Extraction 1,850 9.7
Ammonia Separation (-2,130) 16.5
Biotreaunent 2,800 5.3 0.16 0.8
Filter 32
Acid addition to cooling water 460
Other chemicals to cooling water 2,560
Total 10,200 31.5
1. 1617 9. 48 21. 0 29. 14
3. 1690 10. 48 22. 0 32. 1425
4. 1687 14. 62 24. 1445 33. 73
5. 242 15. 76 25. 1445 39. 202
7. 228 18. 126 27. 21 40. 1617 RAW WATER
8. 48 20. 1285 28. 28
Treatment Blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 1,870 0.7 4
Lime-Soda Softening - No. 2 NOT USED
Electrodialysis NOT USED
Ion Exchange - Scheme 2 1,490 14
Phenol Extraction 1,100 5.8
Ammonia Separation (-1,230) 9.8
Biotreatment 1,660 3.2 0.08 0.4
Filter 21
Acid addition to cooling water 180
Other chemicals to cooling water 2,480
Total 7,670 18.8
-------
Process SRC
TABLE All-4. WATER TREATMENT PLANTS
Site Fulton, 111.
Process SRC
TABLE All-4. WATER TREATMENT PLANTS
Site Saline. 111.
Flow Diagram Figure A11-1E
Floy rates by streaja number (10 Ib/hr) ;
Flow Diagram Figure All-IE
Flow rates by stream number (10 Ib/hr) i
1. 1297 9. 66 21. 0 29. 14
3. 1393 10. 66 22. 0 32. 853
4. 1156 14. 80 24. 874 33. 96
5. 282 15. 98 25. 874 39. 153
7. 271 18. 55 27. 21 40. 1297 RAW WATER
8. 66 20. 780 28. 21
Ul
-J
CD
Treatment Blocks;
waste (103 Ib/hr)
filudge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 2 NOT USED
Electrodialysis* ' 11,600 26.6 237
Ion Exchange - Scheme 3 3,200 11
Phenol Extraction 1,510 7.9
Ammonia Separation (-1,720) 13.5
Biotreatment 1,950 3.7 0.09 0.5
Filter 27
Acid addition to cooling water 7g
Other chemicals to cooling water 2,200
Total 18,800 52
1. 1020 9- 42 21. 0 29- 14
3. 1110 10. 42 22. 0 32. 799
4. 1108 14. 56 24. 820 33. 90
5. 288 15. 81 25. 82o 39. 128
7. 272 18. 47 27. 21 40. 1020 RAW WATER
8. 42 20. 727 28. 21
Treatment Blocks l
waste (103 Ib/hr)
sludge or
*/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 1,390 0.4 2
Lime-Soda Softening - No. 2 NOT USED
Electrodialysis NOT USED
Ion Exchange - Scheme 2 1,870 16
Phenol Extraction 960 5.04
Ammonia Separation (-1,070) 8.57
Biotreatment 1,230 2.36 0.06 0.3
Filter 19
Acid addition to cooling water 99
Other chejnicals to cooling water 1,570
Total 6,100 16.0
located roughly in place of Softening No.1 .
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process SRC
Site Gillette, Wyo.
Site Antelope Creek, Wyo.
Flow Diagram Figure All-IE
Flow rates by stream number (10 Lb/hr)i
Flow Diagram Figure All-IE
Flow rates by streaj^nuinber {10 Ih/hr) :
1. 797 9. 186 21. 0 29. 14
3. 951 10. 181 22. 5 32. 599
4. 946 14. 195 24. 620 33. 154
5. 326 IS. 101 25. 620 39. 193
7. 308 18. 92 27. 21 40. 802 RAW WATER
8. 186 20. 601 28. 21
Treatment Blocks:
waate (1Q3 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 2,090 1.0 5.0
Lime-Soda Softening - No. 2 NOT USED
Electrodialysis NOT USED
Ion Exchange - Scheme 2 2,120 18
Phenol Extraction 4,250 22.3
Ainmonia Separation (-5,220) 37.9
Biotreatment 6,250 11.9 0.30 1.5
Filter 67
Acid addition to cooling water small
Other rhpmi r-ซl <* to cooling water 2,370
Total 11,900 72.1
1. 841 9. 166 21. 0 29. 14
3. 992 10. 161 22. 5 32. 510
4. 873 14. 175 24. 531 33. 151
5. 342 15. 51 25. 531 39. 132
7. 323 18. 81 27. 21 40. 846 RAW WATER
8. 166 20. 553 28. 21
Treatment Blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 2 NOT USED
Electrodialysis" 8,120 25.7 120
Ion Exchange - Scheme 3 3,930 19
Phenol Extraction 3,800 19.9
Ammonia Separation (-4,600) 33.9
Biotreatment 5,550 10.6 0.26 1.3
Filter 60
Acid addition to cooling water small
Total 18,500 90.1
* Situated about where Softening No. 1
is shown on Figure All-IE.
-------
TABLE All-4. HATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Site Rainbow t8. Wvo.
Process SRC
Site Dickinson. N.D.
Flow Diagram Figure All-IE
Flow Diagram Figure All-IE
Flow rates by stream number (10 Ib/hr) :
Flow rates by stream number (10 Ib/hr) :
1- 1487 9. Ill 21. 0 29. 14
3. 1602 10. 108 22. 12 32. 1244
4. 1596 14. 122 24. 1265 33. 115
5. 331 15. 48 25. 1265 39. Ill
7. 312 18. 63 27. 21 40. 1499 RAW WATER
8. Ill 20. 1255 28. 21
Treatment Blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 2,310 1.1 6.0
Lime-Soda Softening - No. 2 NOT USED
Electrodialysis NOT USED
Ion Exchange - Scheme 2 2,150 19
Phenol Extraction 2,540 13.3
Ammonia Separation (-2,940) 22.6
Biotreatment 3,730 7.1 0.18 0.90
Filter 42
Acid addition to cooling water 268
CW-HT r*\Amicals to cooling water 640
Total 8,700 43-ฐ
1. 903 9. 234 21. 761
3. 396 10. 227 22. 4
4. 396 14. 241 24. 0
5. 396 15. 107 25. 761
7. 374 18. 167 27. 21
8. 234 20. 707 28. 21
Treatment Blocks :
ซ/hr 106 Btu/hr
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 2 NOT USED
Electrodialysis NOT USED
Ion Exchange - Scheme 1_ 3,760
Phenol Extraction 5,350 28.1
Ammonia Separation (-6,760) 47.7
Biotreatment ',810 ซ-9
Filter 83
Acid addition to cooling water 433
Other chemicals to cooling water 3,370
Total 14,100 90.7
29. 14
32. 740
33. 254
39. 274
40. 907 RAW WATER
waste (103 Ib/hr)
sludge or
dry solution
22
0.37 1.9
-------
TABLE All-"!. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process SRC
Site Bentley, N.D.
Process SRC
site Underwood. N.O.
Flow Diagram Figure All-IE
Flow rates by atreajn number (10 Ib/hr) :
1.
3.
4.
5.
7.
8.
943
1147
1143
367
346
213
9.
10.
14.
15.
18.
20.
213
207
221
85
148
743
21.
22.
24.
25.
27.
28.
0
4
776
776
21
21
Treatment Blocks:
10 Btu/hr
Lime-Soda Softening - No. 1
Lime-Soda Softening -No. 2
Electrodialysis
Ion Exchange - Scheme 2
Phenol Extraction
AJnmonia Separation
Biotreatiaent
Filter
Acid addition to cooling water
Other chemicals tx> cooling water
Total
1,900
2S.6
43.5
13.6
29. 14
32. 755
33. 204
39. 233
40. 947 RAW WATER
waste (10 Ib/hr)
sludge or
dry solution
0.8 4
0.34
1.7
Flow Diagram Figure All-IE
Flow jrates by stream number (10 jJo/hr^i
9. 226
10. 219
14. 233
15. 81
18. 147
20. 1517
1. 1714
3. 1945
4. 1939
5. 406
7. 383
8. 226
Treatment Blocks:
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 2
Electrodialysis
Ion Exchange - Scheme 2_
Phenol Extraction
Ammonia Separation
Bio treatment
Filter
Add addition to cooling water
Other chemicals to cooling water
Total
-b/hr) i
21. 0
22. 10
24. 1533
25. 1533
27. 21
28. 21
g
ซ/hr 10 Btu/hr
2,670
NOT USED
NOT USED
2,640
5,170 27.1
(-6,500) 46.1
7,560 14.4
80
NOT USED
2,800
14,400 87.6
29. 14
32. 1512
33. 231
39. 228
40. 1724 RAH WATER
3
waste (10 Ib/hr)
sludge or
dry solution
1.2 6
23
0.36 1.8
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process SRC
ฃlte Otter Creek. Hont.
Process SRC
Site Pumpkin Creek, Mont.
Flow Diagrajn Figure All-IE
Flow Diagram Figure All-IE
Flow rates by streajn number (10 Ib/hr? :
Flow rates by stream number (10 Ib/hr) :
1. 1186 9. 161 21. 0 29. 14
3. 1413 10. 156 22. 6 32. 736
4. 1230 14. 170 24. 757 33. 227
S. 473 15. 63 25. 757 39. 173
7. 445 18. 110 27. 21 40. 1192 RAW WATER
8. 161 20. 733 28. 21
CD
to
Treatment Blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Line-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 2 1,300 0.2 1.0
Electrodialysis* 9,000 20.0 183
Ion Exchange - Scheme 3 5,400 28
Phenol Extraction 3,680 19.3
Ammonia Separation 1-4,450) 32,8
Biotreataent 5,390 10.3 0.26 1.3
Filter 58
Acid addition to cooling water 453
Other chemicals to cooling water 7&0
Total 21,600 83
1. 947 9. 222 21. 750 29. 14
3. 420 10. 216 22. 5 32. 729
4. 420 14. 230 24. 0 33. 223
S. 420 15. 110 25. 750 39. 231
7. 396 18. 121 27. 21 40. 952 RAW WATER
8. 222 20. 728 28. 21
Treatment Blocks:
waste (103 Ib/hr)
, sludge or
*/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 2 1,300 o.2 1.0
Electrodialysis NOT USED
Ion Exchange - Scherae 1 3,990 24
Phenol Extraction 5,080 26.6
Ammonia Separation (-6,370) 45.3
Biotreatment 7,460 14.2 0.36 1.8
Filter 79
Acid addition to cooling water 522
Other chemicals to cooling water 2,840
Total 14,900 86.1
located roughly in place of Softening Ho.l .
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
SRC
Site Coalridqe, Hont.
Flow Diagram Figure All-IE
Flow rates by stream number (10 Ib/hr) :
1. 1075 9- 330 21. 0
3. 1514 10. 320 22. 6
4. 1509 14. 334 24. 963
5. 552 15. 144 25. 963
7. 521 18. 167 27. 21
8. 330 20. 965 28. 21
Treatment Blocks:
C/hr 10 Btu/hr
Lime-Soda Softening - No. 1 2,050
Lame-Soda Softening - No. 2 NOT USED
Electxodialysis NOT USED
Ion Exchange - Scheme 2 3,590
Phenol Extraction 7,540 39.6
Ammonia Separation (-10,100) 67.3
Biotreatm-nt 11,000 21.0
Filter 11S
Acid addition to cooling vater NOT USED
Other rhf>T-l ^*1 K ^ cooling water 3f330
Total 17,500 128
29. 14
32. 942
33. 440
39. 311
40. 1081 RAW WATER
waste (103 Ib/hr)
sludge or
dry solution
1.0 5.0
31
0.53 2.7
Process SRC
Site Colstrip, Mont.
Flow Diagram Figure All-IE
Flow rates by stream number (10 Ib/hr) :
9. 160
10. 155
14. 169
15. 80
18. 101
20. 794
1- 1045
3. 386
4. 386
5. 386
7. 364
B. 160
Treatment Blocks :
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 2
Electrodialysis
Ion Exchange - Scheme 1
Phenol Extraction
Ammonia Separation
Biotreatment
Filter
Acid addition to cooling water
Other chemicals to cooling water
Total
21. 827
22. 6
24. 0
25. 827
27. 21
28. 21
C/hr 10 Btu/hr
NOT USED
1,150
NOT USED
3,670
3,660
(-4,420)
5,350
58
360
2,230
12,100
19.2
32.6
10.2
29. 14
32. 806
33. 169
39. 181
40. 1051 HAW WATER
waste (10 . Ib/hr)
dry
sludge or
solution
0.1
0.6
22
1.3
62.0
-------
SYNTHANE
384
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process Synthane
Site Jefferson, Ala.
Process Synthane
Gibson, Indiana
UJ
CD
Ul
Flow Diagram Figure All-LA
Flow rates by stream number (10 Ib/hr):
1. 1981 10. 569 21. 827 32. 806
3. 1154 11. 684 22. 0 33. 245
4. 1154 14. 450 24. 0 34. 130
5. 1154 15. 26 25. B27 36. 115
6. 1085 16. 248 27. 21 37. 100
7. 1215 17. 130 28. 21 39. 126
8. 573 IB. 118 29. 14 40. 1981 RAW WATER
9. 578 20. 1130 31. 100
Treatntent blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No . 1 NOT USED
Lime-Soda Softening - No. 3 899 0.06 0.3
Ion Exchange - Scheme 1 12,100 69
Phenol Extraction NOT USED
Ammonia Separation (-1,650) 118.0
Biotreatment 17,100 27.0 0.68 3.4
Filter 154
Acid addition to cooling water 185
rrfhvr chemicals to cooling water 2,050
Flow Diagram Figure A11-1A
Flow rates by stream number (10 Ib/hr) :
1. 1926 10. 590 21. o 32. 724
3. 1926 11. 705 22. 0 33. 245
4. 1923 14. 477 24. 745 34. 130
5. 1178 15. 8 25. 745 36. 115
6. 1107 16. 242 27. 21 31. u2
7. 1237 17. 125 28. 21 39. 120
8. 599 18. 117 29. 14 40. 1926 RAW WATER
9. 599 20. 1081 31. 112
Treatment blocks:
waste (103 Ib/hr)
sludge or
(/hi 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 1,690 0.69 3.45
Lime-Soda Softening - No. 3 901 0.08 0.40
Ion Exchange - Scheme 2 7,660 71
Phenol Extraction NOT USED
Ammonia Separation (-1,710) 122
Biotreatjnent 17,600 28.2 0.70 3.50
Filter 164
Acid addition to cooling water NOT USED
Other chemicals to cooling water 1,960
ISO
-------
TABLE All-4. WATER TREATMENT PLANTS
Process Synthane
Flow Diagram Figure All-LA
Flow rates by stream
1- 1847
3. 1847
4. 1845
5. 1174
6. 1104
ro 7' 1234
CTl 8. 595
9. 595
Treatment blocks:
T.I ire -Soda Softening -
Lime-Soda Softening -
Ion Exchange - Scheme
number (10 Ib/hr):
10. 586 21. 0
11. 701 22. 0
14. 543 24. 671
15. 12 25. 671
16. 179 27. 21
17. 134 28. 21
18. 45 29. 14
20. 1074 31. 107
ซ/hr 106 Btu/hr
No. 1 1,600
No. 3 1,200
2 7,630
32. 650
33. 245
34. 130
36. 115
37. 107
39. 119
40. 1847 RAW HATER
waste (103 li>/hr)
sludge or
dry solution
0.4 2.0
0.06 0.3
70
Phenol .Extraction
AnHnonia Separation (-1,700)
Biotreatment 5,640
Filter 165
Acid addition to cooling water
Other chemicals to cooling water 1,940
Total 16.500
NOT USED
121
9.0
0.2
1.1
Process Synthane
TABLE All-4. WATER TREATMENT PLANTS
Floyd, Ky.
Flow Diagram Figure A11-1A
Flow rates by stream number (10 Ib/hr) :
1.
3.
4.
5.
6.
7.
8.
9.
1320
1188
1188
1188
1117
1247
609
609
10.
11.
14.
IS.
16.
17.
18.
20.
600
715
442
4
287
179
108
498
21.
22.
24.
25.
27.
28.
29.
31.
132
0
0
132
21
21
14
51
32.
33.
34.
36.
37.
39.
40.
Ill
245
130
115
51
55
1320
Treatment blocks :
C/hr
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3 892
Ion Exchange - Scheme _L 12,500
Phenol Extraction
Ammonia Separation (-1,740)
Biotreatment 17,900
Filter 152
Acid addition to cooling water 140
Other chemicals to cooling water 1,010
30,800
10 Btu/hr dry
NOT USED
0.03
NOT USED
124
29 0.72
waste (10 Lb/hr)
sludge or
solution
0.15
71
3.6
-------
Process Synthane
TABLE All-4. WATER TREATMENT PLANTS
Site Gallia, Ohio
Process Synthane
TABLE All-4. WATER TREATMENT PLANTS
Jefferson, Ohio
Plow Diagram Figure All-lA
Flow rates by stream numbex (10 Ib/hr);
Flow Diagram Figure All-lA
Flow rates by stream number (10 Ib/hr);
Ul
CD
^J
1.
3.
4.
5.
6.
7.
8.
9.
1896
1168
1168
1168
1098
1228
590
590
10.
11.
14.
15.
16.
17.
18.
20.
581
696
451
17
259
135
124
1042
21.
22.
24.
25.
27.
28.
29.
31.
728
0
0
728
21
21
14
99
32.
33.
34.
36.
37.
39.
40.
707
245
130
115
99
116
1896 RAW WATER
1.
3.
4.
5.
6.
7.
8.
9.
Wo
1169
1169
1169
1099
1229
591
591
10.
11.
14.
15.
16.
17.
18.
20.
582
691
538
16
173
130
43
1042
21.
22.
24.
25.
27.
28.
29.
31.
641
0
0
641
21
21
14
100
32.
33.
34.
36.
37.
39.
40.
620
245
130
115
100
116
1810
Treatment blocks:
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Ion Exchange - Schema 1
Phenol Extraction
Ammonia Separation
Biotreatment
Filter
Acid addition to cooling water
C/hr
899
12,300
(-1,680)
5,600
155
264
10 Btu/hr dry
NOT USED
0.06
NOT USED
120
9.0 0.2
waste (10 Ib/hr)
sludge or
solution
0.30
70
1.1
Treatment blocks:
Lima-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Ion Exchange - Scheme 1
Phenol Extraction
Aosnonia Separation
Biotreatment
Filter
Acid addition to cooling water
C/hr
899
12,300
(-1,680)
5,610
185
249
21. 641
22. 0
24. 0
25. 641
27. 21
28. 21
29. 14
31. 100
10 Btu/hr
NOT USED
32. 620
33. 245
34. 130
36. 115
37. 100
39. 116
40. 1810 RAW WATER
waste (103 Ib/hr)
sludge or
dry solution
0.06 0.3
70
NOT USED
121
9.0
Other chemicals to cooling water 1.890
Total 19,400
129
Other chemicals to cooling water 2,120
Total 19,700
130
-------
TABLE All-4. HATER TREATMENT PLANTS
TABLE All-4. HATER TREATMENT PLANTS
Process Synthane
Flow Diagram Figure A11-1A
Plow rates by stream number
Site Armstrong. Pa.
Process Synthane
Flow Diagram Figure A11-1A
Kanawha, West Virginia
UJ
CD
CO
1.
3.
4.
5.
6.
7.
8.
9.
1872
1171
1171
1171
1101
1231
593
593
10.
11.
14.
15.
16.
17.
18.
20.
584
714
487
15
241
128
113
1050
21.
22.
24.
25.
27.
28.
29.
31.
701
0
0
701
21
21
14
102
32.
33.
34.
36.
37.
39.
40.
680
245
115
130
102
117
1872 RAH WATER
1.
3.
4.
5.
6.
7.
8.
9.
1865
1172
1172
1172
1102
1232
594
594
10.
11.
14.
15.
16.
17.
18.
20.
let \J.w A*-*/
585
700
471
14
243
130
113
1029
21.
22.
24.
25.
27.
28.
29.
31.
693
0
0
693
21
21
14
100
32.
33.
34.
36.
37.
39.
40.
672
245
130
115
100
114
1865 RAW WATER
Treatment blocJcs:
Lime-So
-------
Process Synthane
TABLE All-4. WATER TREATMENT PLANTS
Site Preston, West Virginia
Flow Diagram Figure A11-1A
Flow rates by streaJD number (10 Ib/hr):
U)
03
1.
3.
4.
5.
6.
7.
8.
9.
1392
1169
1169
1169
1099
1229
591
591
10.
11.
14.
15.
16.
17.
18.
20.
582
712
431
16
295
183
112
570
21.
22.
24.
25.
27.
28.
29.
31.
223
0
0
223
21
21
47
32.
33.
34.
36 ~.
37.
39.
40.
202
24S
130
115
47
63
139
Treatment blocks:
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Ion Exchange - Scheme 1
Phenol Extraction
Ammonia Separation
Biotreatment
Filter
Acid addition to cooling water
Other chemicals to cooling water 1,150
Total 18'600
C/hr
891
12,300
(-1,680)
5,730
148
91
1,150
waste (10 Ib/hr)
sludge or
10 Btu/hr dry solution
NOT USED
0.03 0.15
70
NOT USED
120.6
9.2 0.2 1.2
130
TABLE All-4. WATER TREATMENT PLANTS
Process Synthane
Flow Diagram Figure A11-1A
Site Antelope Creek, Wyo.
1.
3.
4.
5.
6.
7.
e.
9.
1426
1426
1283
1102
1036
1177
526
526
Treatment blocks:
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Electrodialysis *
Ion Exchange - Scheme
Phenol 'Extraction
Ammonia Separation
Biotreatment
Filter
Acid addition to cooling water
Other chemicals to cooling water 1,060
Total 42,600
U.1-1A
number (10 Ib/hr) :
10. 518 21. 0
11. 667 22. 6
14. 416 24. 181
15. 11 25. 181
16. 285 27. 21
17. 227 28. 21
IB. 58 29. 14
20. 518 31. 47
*/hr 106 Btu/hr
No. 1 NOT USED
No. 3 891
9,550 32.1
: 3 12,700
12,000 63.1
(-1,500) 107.3
7,820 14.9
126
32. 160
33. 310
34. 141
36. 169
37. 47
39. 58
40. 1432 HAW WATER
waste (103 Ib/hr)
sludge or
dry solution
0.03 0.14
143
66
0.33 1.65
217
Located roughly in the place of Softening No. 1.
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process Synthane
Flow Diagram Figure All-LA
FUov rates by st-reajn number (10 Ib/hr) i
Site Spotted Horse, Wyo.
Process Synthane
Flow Diagram Figure All-LA
Flow rates by stream number (10 Ib/hr):
Site CoIs trip, Montana
Ul
vฃ>
o
1.
3.
4.
5.
6.
7.
8.
9.
1309
1309
1303
1086
1021
1162
511
511
10.
11.
14.
15.
16.
17.
18.
20.
503
672
378
21
308
246
62
517
21.
22.
24.
25.
27.
28.
29.
31.
0
6
217
217
21
21
14
36
32.
33.
34.
36.
37.
39.
40.
196
310
141
169
36
57
1315 RAW WATER
1.
3.
4.
5.
6.
7.
8.
9.
1415
1093
1093
1093
1027
1168
518
518
10.
11.
14.
15.
16.
17.
IB.
20.
510
679
401
17
292
219
73
632
21.
22.
24j
25.
27.
28.
29.
31.
322
5
0
322
21
21
14
53
32.
33.
34.
36.
37.
39.
40.
301
310
141
169
53
70
1420
RAW WATER
Treatn>ent blocks:
Lime-Soda Softening - No. 1
Lime-Soda Softening - No.' 3
Ion Exchange - Scheme 2
Phenol Extraction
Anroonia Separation
Biotreatment
Filter
Acid addition to cooling water
Other chemicals to cooling water
Total
C/hr
2,140
890
7,060
11,700
(-1,4601
7,510
130
1,040
29,000
waste (103 Ib/hr)
filudge or
10 Btu/hr dry solution
1.3 6.3
0.02 0.11
65
61.3
104.2
14.3 0.30 1.5
NOT USED
180
Treatment blocks:
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Ion Exchange - Scheme 1
Phenol ".Extraction
Ammonia Separation
Biotreatment
Kilter
Acid addition to cooling water ^75
Other chemicals to cooling water ฑ 280
Total 31,900
waste (10 Ib/hr)
t/hr
892
11,500
11,800
(-1,470)
7,610
10 Btu/hr drv
NOT USED
0.03
62.2
105.7
14.5 0.03
sludge or
solution
0.16
79
1.5
137
-------
HYGAS
391
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process Hygaa_
Site Jefferson, Ala.
Flow Dlagrajn Figure A11-1A
Flow rates by stream number (10 Ib/hr) :
1. 2130 10. 532 21. 796 31. 9
3. I"4 11. 532 22. 0 32. 775
4. 1334 14. 344 24. 0 33. 180
5. I"4 15. 103 25. 796 34. 1BO
6. 1254 16. 202 26. 0 36. 0
U> 7. I"" 17. 101 27. 21 37. 9
NJ 8. 537 18 10-1 28. 21 39. 112
9. 537 20. 1ฐ07 29. 14 40. 2130 RAW HATER
Treatment blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lima-Soda Softening - No. 1 NOT USED
Ljjne-Soda Softening - No. 3 686 0.01 0.05
Ion Exchange - Schejne 1 14,000 60
Phenol Extraction NOT USED
Ajnnonia Separation 7,870 109
Biotreatment 2,660 4.2 0.1 0.5
Filter 118
Acid addition to cooling water 167
Other chemicals to cooling water 1,630
Total 27,600 113
Flow Diagram Figure A11-1A
Plow rates by stream number (10 Ib/hr) :
1. 1298 10. 293 21. 431 31. 1
3. 867 11. 293 22. 0 32. 410
4. 867 14. 198 24. 0 33. 200
5. 867 15. 60 25. 431 34. 200
6. 815 16. 109 26. 0 36 . 0
7. 1015 17. 36 27. 21 37. 1
8. 296 18. 73 28. 21 39. 61
9. 296 20. 547 29. 14 40. 1298 RAW HATER
Treatment blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 3 884 0.001 0.005
Ion Exchange - Scheme 1 9,100 52,
Phenol Extraction 7,220 35.5
AniDOnia Separation 6,960 60.4
Biotreatment 3,630 8.2 0.2 1.0
Filter 6a
Acid addition to cooling water 90
Other chemicals to cooling water 994
Total 28,900 104
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Hyqas
Site Harengo, Ala, (well water)
Hygaa
Site
Gibson, Ind.
Flow Diagram Figure A11-1A
Flow rates by stream number (10 Ib/hr) :
1. 1298 10. 293 21. 431 31. 1
3. 867 11. 293 22. 0 32. 410
4. 867 14. 198 24. 0 33. 200
5. 867 15. 60 25. 431 34. 200
6. 815 16. 109 26. 0 36. 0
7. 1015 17. 36 27. 21 37. 1
8. 296 18. 73 28. 21 39. 61
9. 296 20. 547 29. 14 40. 1298 RAW WATER
Treatment blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 3 884 0.001 0.005
Ion Exchange - Scheme 1_ 9,100 52
Phenol Extraction 7,220 35.5
Ammonia Separation 6,960 60.4
Biotreatment 3,630 8.2 0.2 1.0
Filter 6a
Acid addition to cooling water '74
Other chemicals to cooling water 994
Total 29,600 104
Flow Diagram Figure A11-1A
Flow rates by stream number (10 Ib/hr) i
1. 2048 10. 532 21. 0 31. 64
3. 2048 11. 532 22. o 32. 690
4. 2045 14. 380 24. 711 33. 180
5. 1334 15. 43 25. 711 34. 180
6. 1254 16. 176 26. 0 36. n
7. 1434 17. 69 27. 21 37. 64
B. 537 18. 107 28. 21 39. 107
9. 537 20. 963 29. 14 40. 2048 RAW WATER
Treatment blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 1,720 0.73 3.65
Lime-Soda Softening - No. 3 900 0.07 0.36
Ion Exchange - Scheme 2 8,670 80
Phenol Extraction NOT USED
Ammonia Separation 7,870 109
Biotreatment 2,660 4.2 0.1 0.5
Filter 136
Acid addition to cooling water NOT USED
Other chemicals to cooling water 1,530
Total 23,500 113
-------
Hyqas
TABLE All-4. WATER TREATMENT PLANTS
Site Warrwiek. Indiana
Process Hyqas
TABLE All-4. WATER TREATMENT PLANTS
Site Tuscaramas, Ohio (surface water)
Flow Diagram Figure JQ1-1A
Flow rates by stream number (10 Ib/hr);
Flow Diagram Figure All-LA
Flow rates by stream number (10 Ib/hr) :
1. 2016 10. 532 21. 682 31. 48
3. 1334 11. 532 22. 0 32. 661
4. 1334 14. 409 24. 0 33. 180
5. 1334 15. 59 25. 682 34. 180
6. 1254 16. 132 26. 0 36. 0
7. 1434 17. 90 27. 21 37. 48
8. 537 18. 42 28. 21 39. 107
9. 537 20. 963 29. 14 40. 2016 RAW WATER
Treatinent blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. '3 1,050 0.05 0.27
Ion Exchange - Scheme _1 14,000 80
Phenol Extraction NOT USED
Aumonia Separation 7,870 109
Biotreatn^nt 2,660 4.2 0.1 0.5
Filter 136
Acid addition to cooling water 245
Other chemicals to cooling water 1,740
Total 27,700 113
1. 1600 10. 532 21. 0 31. 21
3. 1600 11. 532 22. 0 32. 240
4. 1595 14. 327 24. 261 33. 180
5. 1334 15. 36 25. 261 34. 180
6. 1254 16. 214 26. 0 36. 0
7. 1434 17. 113 27. 21 37. 21
8. 537 18. 101 28. 21 39. 57
9. 537 20. 510 29. 14 40. 1600 RAH WATER
Treatment blocks:
waste (103 Ib/hr)
fc sludge or
ซ/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 1,890 0.93 4.7
Lime-Soda Softening - No. 3 900 0.02 0.11
Ion Exchange - Scheme 2 8,670 BO
Phenol Extraction NOT USED
Ammonia Separation 7,870 109
Biotreatment 2,660 4.2 0.1 0.5
Filter 112
Acid addition to cooling water NOT USED
Other chemicals to cooling water 1,040
Total 23,200 113
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process Hygas
Tuscaraifas , Ohio (around
Process
Hygas
Site
Flow Diagram Figure A11-1A
Flow rates by stream number (10 lb/hr) i
1. 1599 10. 532 21. 0 31. 21
3. 1599 11. 532 22. 0 32. 240
4. 1595 14. 327 24. 261 33. ISO
5. 1334 15. 36 25. 261 34. 180
6. 1254 16. 214 26. 0 36. 0
7. 1434 17. 113 27. 21 37. 21
8. 537 18. 101 28. 21 39. 57
J^j 9 537 20. 510 29. 14 40. 1599 RAW WATER
Ln
Treatment blocks:
waste (103 lb/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 1,820 0.84 4.2
Lime-Soda Softening - No. 3 900 0.02 0.11
Ion Exchange - Scheme _2 8,670 80
Phenol Extraction NOT USED
funnonia Separation 7,870 109
Biotreatment 2,660 4.2 0.1 0.5
Filter H2
Acid addition to cooling water NOT USED
Other chemicals to cooling water 1,040
Total 23,100 113
Flov Diagram Figure A11-1A
Flow rates by stream number (10 Ib/hr) :
1. 2031 10. 532 21. 697 31. 42
3. 1334 11. 532 22. 0 32. 676
4. 1334 14. 372 24. 0 33. 180
5. 1334 15. 63 25. 697 34. 180
6. 1254 16. 169 26. 0 36. 0
7. 1434 17. 132 27. 21 37. 42
8. 537 18. 37 28. 21 39. 105
9. 537 20. 943 29. 14 40. 2031 RAW WATER
Treatment blocks:
waste (10 lb/hr)
g sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 3 895 0.06 0.3
Ion Exchange - Scheme 1 14,000 80
Phenol Extraction NOT USED
Ammonia Separation 7,870 109
Biotreatment 2,660 4.2 0.1 0.5
Filter 128
Acid addition to cooling water 197
Other chemicals to cooling water 58
Total 25,8OO 113
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Hygas
Site
Armstrong, Pa.
Process
Site Fayette, W. Va.
Plow Diagrajn Figure A11-1A
Flow rates by
U)
IX)
CTi
1.
3.
4.
5.
6.
7.
8.
9.
2046
1334
1334
1334
1254
1434
537
537
streajn number (10 Ib/hr) :
10.
11.
14.
15.
16.
17.
18.
20.
532
532
350
59
191
94
97
937
21.
22.
24.
25.
26.
27.
28.
29.
712
0
0
712
0
21
21
14
31.
32.
33.
34.
36.
37.
39.
40.
45
691
180
180
0
45
104
2046 RAW WATER
Flow Diagram Figure A11-1A
Flow rates by
1.
3.
4.
5.
6.
7.
e.
9.
2032
1334
1334
1334
1254
1434
537
537
stream number (10 Ib/hr) :
10.
11.
14.
15.
16.
17.
18.
20.
532
532
402
47
139
47
92
971
21.
22.
24.
25.
26.
27.
28.
29.
698
0
0
698
0
21
21
14
31.
32.
33.
34.
36.
37.
39.
40.
61
677
180
1BO
0
61
108
2032 RAW WATEI
Treatment blocks;
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Ion Exchange - Scheme j- ^
Phenol Extraction
Ainnonia Separation
Biotreatment
Filter
Acid addition "to cooling water
Other chemicals to cooling water 1,900
Total
waste (10 Ib/hr)
sludge or
10ฐ Btu/hr dry solution
NOT USED
1,020 0.1
14,000
NOT USED
7,870 109
2,660 4.2 0.1
120
35
1,900
0.5
80
0.5
27,700
113
Treatjnent blocks;
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Ion Exchange - Scheme _1
Phenol Extraction
Amnonia Separation
Biotreatment
Filter
Acid addition to cooling water
Other chemicals to cooling water 1,760
Total 27,600
C/hr
950
14,000
7,870
2,660
138
177
1,760
waste (10 Ib/hr)
sludge or
10 Btu/hr dry solution
NOT USED
0.1 0.3
80
NOT USED
109
4.2 0.1 0.5
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process Hygas
Site Monongalia, W. Va.
Sit*
Mingo, W. Va.
Flow Diagrajn Figure A11-1A
Flow rates by stream number (10 Ib/hr) i
1. 1577 10. 532 21. 243 31. 21
3. 1334 H. 532 22. 0 32. 222
4. 1334 14. 356 24. 0 33. 180
5. 1334 15. 37 25. 243 34. 180
6. I254 16. 165 26. 0 36. 0
7. 1434 17. 91 27. 21 37. 21
kฃ> 8 537 18. 94 28. 21 39 58
^J
9 537 20. 52ฐ 29. I4 40. 1577 RM< HATER
Treatment blocks:
waste (10 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 3 900 0.02 0.11
Ion Exchange - Scheme ฑ 14,000 80
Phenol Extraction NOT USED
Ammonia Separation 7,870 109
Biotreatment 2,660 4.2 0.1 0.5
Filter 122
Acid addition to cooling water 11
Other chemicals to cooling vater 950
Total 26,600 113
Flow Diagrajn Figure A11-1A
Flow rates by stream number (10 Ib/hr) :
/
1. 1507 10. 532 21. 173 31. 30
3. 1334 11. 532 22. 0 32. 152
4. 1334 14. 433 24. 0 33. 180
5. 1334 15. 28 25. 173 34. 180
6. 1254 16. 113 26. 0 36 . 0
7. 1434 1.7. 79 27. 21 37. 30
8. 537 18. 34 28. 21 39. 58
9. 537 20. 527 29. I4 40. I507 RA" WATER
Treatment blocks:
waste (103 Ib/hr)
sludge or
*/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 3 900 0.03 0.17
Ion Exchange - Scheme 1 14,000 80
Phenol Extraction NOT USED
Ammonia Separation 7,870 109
Biotreatment 2,660 4.2 0.1 0.5
Filter 148
Acid addition to cooling water 28
Other chemicals to cooling water 1,060
Total 26,700 113
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
00
Process Hygaa Site
Flow Diagram Figure All-lA
Flow rates by stream number {10 ll>/hr)
Gillette, Wyo.
Hygaป
Site Antelope Creek, Wyo.
Flow Diagram Figure All-lA
1.
3.
4.
5.
6.
7.
a.
9.
1261
1261
1255
867
815
1015
296
296
10.
11.
14.
15.
16.
17.
18.
20.
293
293
154
69
153
85
68
452
21.
22.
24.
25.
26.
27.
28.
29.
0
6
388
388
0
21
21
14
31.
32.
33.
34.
36.
37.
39.
40.
0
367
200
200
0
0
69
1267 RAW WATER
1.
3.
4.
5.
6.
7.
8.
9.
1353
1353
1218
867
815
1015
296
296
10.
11.
14.
15.
16.
17.
18.
20.
293
293
172
35
135
76
59
452
21.
22.
24.
25.
26.
27.
28.
29.
0
6
351
351
0
21
21
14
31.
32.
33.
34.
36.
37.
39.
40.
15
330
200
200
0
15
50
135!
Treatment bloch-9:
ซ/hr
Lime-Soda Softening - No. 1 2,060
Lima-Soda Softening - No. 3
Ion Exchange - Schema 2
Phenol Extraction
Anmonia Separation
Biotreatrment
Filter
Acid addition to cooling water
Othซr chemicals to cooling water 1,130
Total
5,640
7,220
6,960
3,630
53
waste (10 Ib/hr)
sludge or
10 Btu/hr dry solution
35.5
60.4
5.8
1.2
0.2
6.0
52
1.0
26,700
102
Treatment blocks:
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Electrodialyais
Ion Exchange - Scheme 3_
Phenol Extraction
Ammonia Separation
Biotreatment
Filter
Acid addition to cooling water
Other chemical* to cooling water
Total
ซ/hr
887
11 , 300
9,970
7,220
6,960
3,630
58
156
815
waste (10 Ib/hr)
aludge or
10 Btu/hr dry solution
NOT USED
0.02 0.08
292 135
52
35.5
60.4
5.8 0.2 1.0
41.000
394
Situated roughly in placa of softener No. 1.
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Site Belle Ayr, Wyo.
Hygas
Site
Hanna CCal Fid., Wyo.
Flow Diagram Figure A11-1A
Flow rates by stream number (10 Ib/hr) ;
1. 1374 10. 293 21. o 31- 0
3. 1374 11. 293 22. 6 32. 479
4 1367 14. 44 24. 500 33. 200
5. 867 15. 71 25. 500 34. 200
6 815 16. 263 26. 0 36. 0
7 1015 17. 206 27. 21 37. 0
8. 296 18. 57 28. 21 39. 71
9 296 20. 452 29. 14 40. 1380 RAW WATER
Treatment blocks:
waste (10 Ib/hr)
sludge or
C/Hr 10 Btu/hr dry solution
LiM-Soda Softening - No. 1 2,170 1.3 6.5
Lime-Soda Softening - No. 3 NOT USED
Ion Exchange - Scheme 2_ 5,640 52
Phenol Extraction 7,220 35.5
Ammonia Separation 6,960 60.4
Biotreatment 3,630 5.8 0.2 1.0
Filter 15
Acid addition to cooling water NOT USED
Other chemicals to cooling water B73
Total 26,500 102
Flow Diagram Figure A11-1A
Flow rates by stream number (10 Ib/hr} E
1. 1742 10. 293 21. 0 31. 53
3. 1742 11. 293 22. 8 32. 847
4. 1735 14. 203 24. 868 33. 200
5. 867 15. 52 25. 868 34. 200
6. 815 16. 104 26. 0 36. 0
7. 1015 17. 55 27. 21 37. 53
8. 296 IB. 49 28. 21 39. 105
9. 296 20. 945 29. 14 40. 1750 RAW WATER
Treatment blocks:
waste (103 Ib/hr)
6 sludge or
C/hr 10 Btu/hr dry solution
Lijne-Soda Softening - No. 1 2,220 13 65
Lime-Soda Softening - No. 3 392 n.3 0 15
Ion Exchange - Scheme Jฃ 5,640 52
Phenol Extraction 7,220 35.5
Ajrenonia Separation 6,960 60.4
Biotreatment 3,630 5.8 0.2 1.0
Filter 70
Acid addition to cooling water NOT USED
Other chemicals to cooling water 1,500
Total 28,100 102
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. HATER TREATMENT PLANTS
Hyqas
Flow Diagrajn Figure A11-1A
Flow rates by stream number (]
1.
3.
4.
5.
6.
7.
O
O 9.
1893
1893
1704
867
BIS
1015
296
296
10.
11.
14.
15.
16.
17.
18.
20.
293
293
226
27
81
14
67
938
Treatment blocks:
Site
Decker. Mont.
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Electrodialysis*
Ion Exchange - Scheme _ 3_
Phenol Extraction
Biotreatment
Filter
Acid addition to cooling water
Other chemicals to cooling water
Total
.b/hr) :
21. 0 31. 77
22. 7 32. 816
24. B37 33. 200
25. 837 34. 200
26. 0 36. 0
27. 21 37. 77
28. 21 39. 104
29. 14 40. J900 RAW WATER
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
NOT USED
696 0.05 0.25
9,720 25.5 189
9,970 52
7,220 35.5
6,960 60.4
3,630 5.8 0.2 1.0
77
1,200
1,660
41.300 127
Flow Diagram Figure A11-1A
Flow rates by streaa number (10 Ib/hr) ,
1. 1258 10. 293 21. 0 31. 0
3. 1258 11. 293 22. 5 32. 364
4. 1252 14. 147 24. 385 33. 200
5. 867 15. 62 25. 385 34. 200
6. 815 16. 160 26. 0 36. 0
7. 1015 17. 65 27. 21 37. 0
8. 296 18. 95 28. 21 39. 62
9. 296 20. 449 29. 14 40. 1263 RAH WATER
Treatment blocks:
waste (103 Ib/hr)
. sludge or
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Hygas
Colstrip, Hont.
Hygas
Site
El Paso, N.M.
o
Flow Diagram Figure All-LA
Flow rates by stream number (10 Lb/hr):
1. 1301 10. 293 21. 434 31. 3
3. 867 11. 293 22. 5 32. 413
4. 867 14. 150 24. 0 33. 200
5. 867 15. 53 25. 434 34. 200
6. 815 16. 157 26. 0 36. 0
7. 1015 17. 84 27. 21 37. 3
8. 296 18. 73 28. 21 39. 56
g 296 20. 507 29. 14 40. 1306 RAW WATER
Treatment blocks:
waste (103 Lb/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 3 885 0.003 0.02
Ion Exchange - Scheme _1 9,100 52
Phenol Extraction 7,220 35.5
Ajunonia Separation 6,960 60.4
Biotreatment 3,630 5.8 0.2 1.0
Filter 51
Acid addition to cooling water 192
Other chemicals to cooling water 913
Total 29'ฐฐฐ 102
Flow Diagram Figure All-LA
Flow rates by stream number (10 Lb/hr) :
1. 1428 10. 293 21. 561 31. 0
3. 867 11. 293 22. 8 32. 491
4. 867 14. 122 24. 0 33. 200
5. 867 15. 153 25. 561 34. 200
6. 815 16. 184 26. 49 36. 0
7. 1015 17. 100 27. 21 37. 0
8. 296 18. 84 28. 21 39. 153
9. 296 20. 460 29. 14 40. 1436 RAW WATER
Treatment blocks:
waste (103 Lb/hr)
, sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Lime-Soda Softening - No. 3 MOT USED
Ion Exchange - ScheJne _1 9,100 52
Phenol Extraction 7,220 35.5
Anmonia Separation 6,960 60.4
Biotreatment 3,630 5.8 0.2 1.0
Filter 58
Acid addition to cooling water 229
Other chemicals to cooling water 2,190
Total 29,400 102
-------
TABLE All-4. HATER TREATMENT PLANTS
Process Hyqas
Site Gallup, N.H.(ground water)
Flow Diagram Figure A11-1A
Flow rates by stream number (10 Ib/hr)t
O
to
1. 1404
3. 1004
4. 867
5. 867
6. 815
7. 1015
8. 296
9. 296
10. 293
11. 293
14. 168
15. 31
16. 138
17. 74
18. 64
20. 460
21. 400
22.8
24.0
25.400
26. 37
27. 21
28. 21
29. 14
31. 20
32. 342
33. 200
34. 200
36. 0
37. 20
39. 51
40. 1412
RAH HATER
Treatment blocks:
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Electrodialysis*
Ion Exchange - Scheme j
Phenol Extraction
Airoonia Separation
Biotreatoent
Filter
Acid addition to cooling water
Other chemical! to cooling water
C/hr 10 Btu/hr
NOT USED
900
6,530
9,970
7,220
6,960
3,630
58
410
730
15.4
35.5
60.4
5.8
Total 36,400 117
* located roughly in place of ปof tซning Ho. 1.
waste (10 Ib/hr)
drj-
0.02
0.2
sludge or
solution
0.11
137
52
1.0
-------
BIGAS
403
-------
Process Blg^s
Flow Diagram Figure A11-1C
Flow rates by stream nuinber (1
1. 2151
3. 187
4. 187
5. 187
6 . 1 ^6
s
^ 8. 890
10. 880
11. 0
Treatment blocks:
12.
14.
15.
16.
17.
18.
20.
21.
22.
14
0
49
14
146
106
1338
1646
0
TABLE All-4. WATER TREATMENT PLANTS
Site Bureau, 111. (Illinois River water)
TABLE All-4. HATER TREATMENT PLANTS
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Ion Exchange - Scheme . 2
Ammonia Separation
Acid addition to cooling watar
Other chemicals to cooling water
Total
Flow Diagram Figure All- 1C
'/hr) i
24. 0 34. 234
25. 1646 35. 138
27. 21 36. 1198
28. 21 37. 238
29. 14 38. 100
30. 1625 39. 149
31. 100 40. 2151 RAH WATER
32. 1487
33. 318
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
NOT USED
899 0.06 0.3
1,220 11
13,040 181
1,830
939
Flow rates by stream
1. 2152
3. 1834
4. 1833
5. 187
6. 176
'7. 410
8. 890
10. 880
11. 0
Treatment blocks:
Lime-Soda Softening -
Lime-Soda Softening -
Ion Exchange - Scheme
Ammonia Separation
number (10
12. 14
14. 0
15. 49
16. 14
17. 146
18. 106
20. 1338
21. 0
22. 0
No. 1
No. 3
2
Acid addition to cooling water
Other chemical* to cooling water
Ib/hr) :
24. 1646 34. 234
25. 1646 35. 138
27. 21 36. 1198
28. 21 37. 238
29. 14 38. 100
30. 1625 39. 149
31. 100 40. 2152 RAW WATER
32. 1487
33. 318
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
' 1,930 0.9 4.5
900 0.06 0.3
1,220 11
13,040 181
NOT USED
1.830
17,900
181
Total
18,900
-------
TABLE All-4. HATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Bigas
Site
Shelby, 111.
Bigas
Site Vigo, Ind.
Flow Diagram Figure A11-1C
Flow rates by stream number (10 Ib/hr? 3
1. 1355
3. 187
4. 187
S. 187
6. 176
410
980
12.
14.
15.
16.
17.
IB.
20.
21.
22.
14
0
100
14
155
Ill
503
866
0
7.
8.
10.
11.
Treatment blocXst
Lime-Soda Softening - No. 1
Lime-SocLa Softening - No. 3
Jon Exchange - Schejne 1
Ammonia Separation
Acid addition to cooling water
Other chemicals to cooling water
Total
24. 0
25. 866
27. 21
28. 21
29. 14
30. 845
31. 0
32. 603
33. 302
34. 234
35. 242
36. 1273
37. 242
38. 0
39. 100
40. 1355 RAW WATER
C/hr 10 Etu/hr
NOT USED
NOT USED
1,960
14,400 200
163
1,230
17,800 200
waste (10 Ib/hr)
dry.
sludge or
solution
Flov Diagram Figure A11-1C
Flow rates by streajn number (10
1. 2092 12. 14
3. 1778 14. 0
4. 1777 15. 48
5. 187 16. 14
6. 176 17. 97
'7. 410 18. 100
8. 841 20. 1338
10. 833 21. 0
11. 0 22. 0
Treatment blocks t
Lime- Soda Softening - No. 1
Lime-Soda Softening - No. 3
Ion Exchange - Scheme 2
Ammonia Separation
Acid addition to cooling water
Other chemicals to cooling water
Total
Ib/hr) i
24. 1590 34. 234
25. 1590 35. 82
27. 21 36. 1147
28. 21 37. 183
29. 14 38. 101
30. 1569 39. 149
31. 101 40. 2092 RAH WATER
32. 1487
33. 314
waste (103 Ib/hr)
, sludge or
ซ/hr 10 Btu/hr dry solution
'1,790 0.7 3.7
980 0.06 0.3
1,220 11
12,300 172
NOT USED
1,830
18,100 172
-------
TABLE All-4. HATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Biqas
Site Kemmerer/ Hyp.
o
Plow Diagram Figure A11-1C
Flov rates by stream number {10"* Ib/hr)
1.
3.
4.
5.
6.
7.
8.
10.
11.
1308
187
187
187
176
410
863
855
0
12.
14.
15.
16.
17.
18.
20.
21.
22.
14
0
51
14
111
42
597
808
4
24.
25.
27.
28.
29.
30.
31.
32.
33.
0
808
21
21
14
787
0
648
313
Treatment blocks:
24. 0
25. 808
27. 21
28. 21
29. 14
30. 787
31. 0
32. 648
33. 313
g
ir 10 Btu/hr
34. 234
35. 139
36. 1168
37. 139
38. 0
39. 51
40. 1308 HAH HATER
waste (103 Ib/hr)
sludge or
dry solution
Process
Bigas
Site Slope, N.D.,
Lime-Soda Softening - No. 1
Lima-Soda Softening - No. 3
Ion Exchange - Schema 1
Ammonia Separation
Acid addition to cooling water
Other chemicals to cooling water
Total
NOT USED
NOT USED
1,960
12,600 176
450
630
15,600 176
11
Flow Diagram Figure All-1C
Flow rates by stream number (10 Ib/hr) ;
1.
3.
4.
5.
6.
7.
a.
10.
11.
1405
486
486
486
457
691
1478
1464
40
12.
14.
15.
16.
17.
18.
20.
21.
22.
54
0
85
54
129
146
592
919
5
24.
25.
27.
28.
29.
30.
31.
32.
33.
0
919
21
21
14
898
0
677
0
Treatment blocks:
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Ion Exchange - Scheme 1_
Ammonia Separation
Acid addition to cooling water
Other chemicals to cooling water
Total
34. 234
35. 221
36. 1424
37. 221
38. 0
39. 85
40. 1410 RAW WATER
C/hr 10" Btu/hr
NOT USED
NOT USED
5,100
21,650 302
241
1,050
28,000 302
waste (10J Ib/hr)
sludge or
dry solution
29
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT'PLANTS
Bigas
Site
Center. N.D.
Bigas
Sits
Scranton, N.D.
Flow Diagram Figure A11-1C
Plow Diagram Figure A11-1C
Flov rates by stream number (_10 Ib/hr);
Flow rates by stream number (10 ib/hr) i
1. 1397
3. 466
4. 486
5. 486
6. 457
7. 691
8. 1368
10. 1355
11. 0
Treatment blocks:
12. 14
14. 0
15. 90
16. 14
17. 83
18. 119
20. 590
21. 889
22. 4
Lime-Soda Softening - No. 1
Liire-Soda Softening - No. 3
Ion Exchange - Scheme 1
Ammonia Separation
Acid addition to cooling water
Other chemicals to cooling water
Total
24. 0 34. 234
25. 889 35. 188
27. 21 36. 1377
28. 21 37. 186
29. 14 38. 0
30. 868 39. 90
31. 0 40. 1401 RAW WATER
32. 680
33. 22
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
NOT USED
NOT USED
5,100 29
20,040 279
1,200
1,110
27,500 279
1. 1415
3. 1386
4. 1385
3. 486
6. 457
7. 691
8. 1338
10. I"*
11. 0
Treatment blocks i
12. 14
14. 0
15. 83
16. 14
17. 91
18. 126
20. 592
21. 0
22. 4
Lime-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Ion Exchange - Scheme 2
Ammonia Separation
Acid addition to cooling water
Other chemicals to cooling water
Total
24. 899 34. 234
25. 899 35. 203
27. 21 36. 1355
28. 21 37. 203
29. 14 38. 0
30. 878 39. 83
31. 0 40. 1419 RAW WATER
32. 675
33. 29
waste (103 Ib/hr)
sludge or
i/hr 10 Btu/hr dry solution
1,420 0.3 1.4
NOT USED
3,160 29
19,600 273
NOT USED
1,020
25,200 273
-------
TABLE All-4. HATER TREATMENT PLANTS
Process
Biqaa
Site
Chupp Mine, Mont.
Flow Diagram Figure A11-1C
Flov rates by stream number (10 Ib/hr) :
O
00
1.
3.
4.
5.
6.
7.
a.
10.
11.
2215
486
486
486
457
691
1307
1295
0
12.
14.
15.
16.
17.
IB.
20.
21.
22.
14
0
78
14
47
104
1433
1669
9
24.
25.
27.
26.
29.
30.
31.
32.
33.
0
1669
21
21
14
1648
0
1511
60
34.
35.
36.
37.
3B.
39.
40.
234
137
1355
137
0
78
2224 RAW WATER
Treatment blocks:
C/hr
106 Btu/hr
waste
dry
(103 Ib/hr)
sludge or
solution
Line-Soda Softening - No. 1
Lime-Soda Softening - No. 3
Ion Exchange - Scheme 1
Ammonia Separation
Acid addition to cooling water
Other chemicals to cooling water
Total
NOT USED
NOT USED
5,100
19,200 267
725
960
24.0OO 267
29
-------
SYNTHOIL
409
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. HATER TREATMENT PLANTS
Process Synthoil
Sita Jefferson, Ala.
Process Synthoil
Site Gibson. Ind.
Flow Diagram Figure All-ID
Flow rates by stream number (10'' Ib/hr) :
Flow'Diagram Figure All-ID
Flow rates by stream number (10 Ib/hr):
1. 2237 14. 0 23. 0 31. 60
3. 247 15. 121 24. 0 32. 1814
4. 247 16. Ill 25. 1990 33. 140
5. 247 18. Ill 26. 0 35. 15
7. 232 19. 75 27. 21 39. 181
8. 23 20. 1633 28. 21 40. 2237 RAH HATER
9. 23 21. 1990 29. 14
10. 22 22. 0 30. 1829
Treatment blocks:
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Ion Exchange - Scheme 1_ 2,350 15
Phenol Extraction 526 2.7
Aimonia Separation (-581) 4.7
Biotreatment 760 1.4 0.04 0.18
Filter NOT USED
Acid addition to cooling water 289
Other chemicals to cooling water 2,230
Total 5,570 8.8
1. 2028 14. 0 23. 91 31. 124
3. 2028 15. 50 24. 1797 32. 1735
4. 2025 16. 116 25. 1797 33. 132
5. 229 18. 116 26. 0 35. 0
7. 215 19. 33 27. 21 39. 174
8. 71 20. 1562 28. 21 40. 2028 RAH HATER
9. 71 21. 0 29. 14
10. 69 22. 0 30. 1735
Treatment blocks i
waste (103 Ib/hr)
6 sludge or
C/hr 10 Btu/hr dry^ solution
Lime-Soda Softening - No. 1 1,700 0.6 3
Ion Exchange - Scheme 2 1,490 14
Phenol Extraction 1,620 8.5
Ammonia Separation (-1,850) 14.5
Biotreatment 2,380 4.5 0.11 0.57
Filter NOT USED
Acid addition to cooling water NOT USED
Other chemicals to cooling water 2, 140
Total 7,470 37.5
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Synthoil
Site Harrick, Ind.
Flow'Diagram Figure All-ID
Flow rates by stream number (10 Ib/hr) :
Process Synthoil
Flow Diagram Figure All-ID
Flow rates by stream number (10 Ib/hr) ;
Site Harlan, Ky.
1. 2126 14. 0 23. 48 31. 112
3. 224 15. 68 24. 0 32. 1800
4. 224 16. 46 25. 1902 33. 129
5. 224 18. 46 26. 0 35. 0
7. 211 19. 64 27. 21 39. 180
8. 99 20. 1620 28. 21 40. 2126 RAW WATER
9. 99 21. 1902 29. 14
10. 96 22. 0 30. 1800
Treatment blocks :
waste (103 Ib/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Ion Exchange - Scheme 1 2,130 13
Phenol Extraction 2,260 11.9
Amonia Separation (-2,630) 20.2
Biotreatment 3.310 6.3 0.02 0.08
Filter NOT USED
Acid addition to cooling water 489
rr*-Y,<*r r+iomica]ซ to coolina water 2,210
Total 7-770 38-4
1. 1406 14. 0 23. 38 31. 69
3. 243 15. 26 24. 0 32. 948
4. 243 16. 102 25. 1163 33. 137
5. 243 18. 102 26. 0 35. 0
7. 228 19. 31 27. 21 39. 95
8. 59 20. 853 28. 21 40. 1406 RAW WATER
9. 59 21. 1163 29. 14
10. 57 22. 0 30. 1043
Treatment blocks:
vaste (103 Ib/hr)
aludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Ion Exchange - Schenw 1 2,310 15
Phenol Extraction 1,350 7.1
Ainnonia Separation (-1,530) 12.0
Biotreatment 2,040 3.9 0.01 0.05
Filter NOT USED
Acid addition to cooling water 250
Other chemicals to cooling water 1, 170
Total 5,590 23.0
-------
TABLE All-4. HATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process Synthoil
Flow'Diagram Figure All-ID
Flow rates by stream number (10 llj/hr) :
Site Pike, Ky_.
Process
Synthoil
Site Tuacaravaa, Ohio (surface water)
Flow'Diagram Figure All-ID
1. 1359 14. 41 23. 71 31. 71
3. 244 15. 32 24. 0 32. 993
4. 244 16. 37 25. 1115 33. 172
5. 244 18. 37 26. 0 35. 0
7. 229 19. 0 27. 21 39. 103
8. 66 20. 931 28. 21 40. 1359 RAH HATER
9. 66 21. 1115 29. 14
10. 64 22. 0 30. 993
Treatment blocks:
waste (103 Ib/hr)
sludge or
ซ/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Ion Exchange - Scheme 1_ 2,320 15
Phenol Extraction 1,510 7.9
Anraonia Separation (-1,720) 13.5
Biotreatront 2,210 4.2 0.01 0.05
Filter 14
Acid addition to cooling water 265
Other chemicals to cooling water 1,270
Total 5,870 25.6
1. 1493 14. 0 23. 47 31. 73
3. 1493 15. 42 24. 1256 32. 1148
4. 1489 16. Ill 25. 1256 33. 134
5. 233 18. Ill 26. 0 35. 0
7. 219 19. 26 27. 21 39. 115
8. 73 20. 1033 28. 21 40. 1493 RAW HATER
9. 73 21. 0 29. 14
10. 71 22. 0 30. H48
Treatment blocks:
waste (103 Ib/hr)
g sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 1,800 0.8 4.3
Ion Exchange - Scheme 1 2,210 14
Phenol Extraction 1,670 8.8
Anraonia Separation (-1,920) 14.9
Biotreatnent 2.4SO 4.7 0.01 0.06
Filter NOT USED
Acid addition to cooling water NOT USED
Other chemical! to cooling water 1,420
Total 7,63O 28.4
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process Synthoil
Flow'Diagram Figure All-ID
Flow rates by stream number (10 Ib/hr)
Site Tuscarawag, Ohio (ground water)
Process Synthoil
Site Jefferson, Ohio
1. 1493
3. 1493
4. 1489
5. 233
7.
219
73
14. 0
15. 42
16. Ill
18. HI
19. 26
20. 1033
21. 0
22. 0
8.
9. 73
10. 71
Treatment blocks:
Lime-Soda Softening - Ho. 1
IOD Exchange - Scheme 2
Phenol Extraction
Ammonia Separation
Bio treatment
Filter
Acid addition to cooling water
Other chemicals to cooling water
Total
/hr) :
23. 47 31. 73
24. 1256 32. 1148
25. 1256 33. 134
26. 0 35. 0
27. 21 39. 115
28. 21 40. 1493 RAW WATER
29. 14
30. 1148
waste (103 lb/hr)
sludge or
C/hr 10 Btu/hr dry solution
1,750 0.7 3.5
1,520 I4
1,670 8.8
(-1,910) 14.9
2,450 4.7 0.01 0.06
NOT USED
NOT USED
1,420
6,900 28.4
Flow' Diagram Figure All-ID
Flow rates by stream number (10 Ib/Oir) :
1. 2064 14. 11 23. 103 31. 103
3. 239 15. 75 24. 0 32. 1767
4. 239 16. 42 25. 1825 33. 140
5. 239 ig. 42 26. 0 35. 0
7. 225 19. 0 27. 21 39. 178
8. 40 20. 1600 28. 21 40. 2064 RAW WATER
9. 40 21. 1825 29. 14
10. 39 22. 0 30. 1767
Treatment blocks:
waste (103 li>/hr>
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Ion Exchange - Scheme 1 2,270 14
Phenol Extraction 914 4.8
Ammonia Separation (-1,020) 8.2
Biotreatment 1,350 2.6 0.01 0.03
Filter 4
Acid addition to cooling water 486
Other chejaicala to cooling water 2,190
Total 6,190 15.6
-------
TABU; Ail-4. HATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Process Svnthoil
Site Minqo. W. Va.
Synthoil
Site Somerset, Fa.
Flow'Diagram Figure A11-1D
Flow-Diagram Figure All-lD
Flow rates by stream number (10 Ib/hr) t
J^
x 1352 14. 15 23. 70 31. 70
3 243 15- 33 24. 0 32. 1019
4 243 16- 37 25. 1109 33. 139
5 243 18. 37 26. 0 35. 0
7 228 19. 0 27. 21 39. 103
fl 40 20. 931 28. 21 40. 1352 RAW WATER
9. 40- 21. 1109 29. 14
10. 38 22. 0 30. 1019
Treatment blocks:
waste (103 Ib/hr)
sludge or
^/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Ion Exchange - Scheme 1 2,310 15
Phenol Extraction 914 4.8
Aaroonia Separation (-1,020) 8.2
Biotreatrent 1.310 2.5 0.01 0.03
Filter 5
Acid addition to cooling water 180
Other chemicals to cooling water 1.270
Total "-970 15'5
1. 1581 14. 0 23. 0 31. 11
3. 261 15. 98 24. 0 32. 1091
.4. 261 16. 107 25. 1320 33. 139
5. 261 18. 107 26. 0 35. 69
7. 245 19. 80 27. 21 39. 109
8. 13 20. 982 28. 21 40. 1581 RAW WATER
9. 13 21. 1320 29. 14
10. 13 22. 0 30. 1160
Treatment blocks:
waste (103 Ib/hr)
, sludge or
*/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Ion Exchange - Scheme 1 2,480 16
Phenol Extraction 297 1.6
Amnonia Separation (-326) 2.7
Biotreatment 449 0.9 0.002 0.01
Filter NOT USED
Acid addition to cooling water 68
Other cheaicals to cooling water 1,340
Total 4,310 5.2
-------
TABLE All-4. WATER TREATMENT PLANTS
TABLE All-4. WATER TREATMENT PLANTS
Synthoil
Site Lake de Smet, Wyo.
Synthoil
Site Jim Bridger, Wyo.
Flow-Diagram Figure All-ID
Flew'Diagram Figure All-ID
Flow rates by stream number (10 Lb/hr) :
Flow rates by stream number (10 Lb/hr) i
1. 1797 14. 130 23. 57 31. 57
3. 210 15. 112 24. 0 32. 1559
4. 210 16. 82 25. 1587 33. 64
5. 210 18. 82 26. 0 35. 0
7. 197 19. 0 27. 21 39. 169
8. 206 20. 1520 28. 21 40. 1805 RAW WATER
9. 206 21. 1587 29. 11
10. 200 22. 8 30. 1559
Treatment blocks:
waste (103 lb/hr)
sludge or
C/hr 10 Btu/hr dry solution
Lime-Soda Softening - No. 1 NOT USED
Jon Exchange - Scheme 1 2,000 I3
Phenol Extraction 4,710 24.7
Ammonia Separation (-7,090) 42.0
Biotreatrant 6,910 13.2 0.33 1.7
Filter 1ฐ
Acid addition to cooling water 1,180
Other chemicals to cooling water I/ 330
Total 9,080 79.9
1. 1200 14. 129 23. 11 31. u
3. 227 15. 91 24. 0 32. 889
4. 227 16. 78 25. 973 33. 74
5. 227 IB. 78 26. 0 35. 0
7. 213 19. 0 27. 21 39. 102
8. 201 20. 916 28. 21 40. 1205 RAW WATER
9. 201 21. 973 29. 14
10. 195 22. 5 30. 889
Treatment blocks:
waste (10 lb/hr)
sludge or
C/hr 10 Btu/hx dry solution
Lime-Soda Softening - No. 1 NOT USED
Ion Exchange - Scheme 1 2,160 14
Phenol Extraction 4,590 24.1
Aaraonia Separation (-6,900) 41.0
Biotreatment 6,730 12.8 0.32 1.6
Filter 40
Acid addition to cooling water 489
Other chemicals bo cooling water 1,250
Total 8,360 77.9
-------
TABLE AJ.1-4. WATER TREATMENT PLANTS
Process Synthoil
Flow"Diagram Figure All-ID
FIov rates by stream number^ ^10 i_lb/hr)_i
Site Gallup, N.M.
1.
3.
4.
5.
7.
B.
9.
10.
1305
1305
1175
210
197
115
115
112
14.
15.
16.
18.
19.
20.
21.
22.
42
43
83
83
0
863
0
8
23.
24.
25.
26.
27.
28.
29.
30.
53
965
965
48
21
21
14
878
31.
32.
33.
35.
39.
40.
53
878
119
0
96
1313 RAW HATER
Treatment blocks:
waste (10 Ib/hr)
Lime-Soda Softening - No. 1
Electrodialysis*
Ion Exchange - Scheme 3
Phenol Extraction
Anmonia Separation
fliotreatment
Filter
Acid addition to cooling water
Other chemicals to cooling water
Total
*/hr 10 Btu/hr dry
NOT USED
6,230 14.7
2,420
2,630 13.8
(-3,780) 23.5
3,870 7.4 0.19
10
1,050
1,180
13,600 59.4
Bludge or
solution
130
13
0.95
Located roughly in place of Softening No. 1
-------
APPENDIX 12
CALCULATIONS ON OIL SHALE
Oil shale conversion plant designs are required at Parachute Creek,
Colorado for both directly and indirectly heated retorts. The Paraho Direct
and Indirect processes and the TOSCO II process illustrate the basic types of
surface retorting procedures. They were selected based not only on the
commercial potential of the process, but also on the availability of published
information. The Paraho designs for an integrated oil shale plant are given
in Ref. 1 while the TOSCO II design is given in Refs. 2 and 3. These designs
have been summarized in Ref. 4. The calculations presented in this section
are for an integrated plant designed to produce 50,000 barrels/day of synthetic
crude plus any by-products not utilized as plant fuel. The total heating
value of the synthetic crude is 2.9 X 10 Btu/day. If the by-products are
taken together with the synthetic crude, the output is directly comparable to
the output of 3.1 X 10 Btu/day for the standard size coal liquefaction
plants examined in Appendix 2. Table 12A-1 gives the net input and output
quantities for a 50,000 barrels/day plant based on the designs given in Refs.
1 and 3. The properties of the raw shale and the products are given in Table
12A-2 ' . Part of the difference in the mining rates between the Paraho and
TOSCO II processes is a consequence of the difference in the grade of shale
assumed to be mined. The Paraho designs use 30 gal/ton shale while the TOSCO
II design uses 35 gal/ton shale. In addition, since the Paraho retort cannot
accept fines, about 5 percent more shale must be mined than can be used .
A flow diagram for the surface processing of oil shale is shown in Figure
12A-1. All surface processing operations involve mining, crushing and then
retorting to produce the shale oil. The product of the retorting is generally
too viscous to be piped and is put through an upgrading process to remove
nitrogen and sulfur. The spent shale from the retorting must be disposed.
Figures 12A-2, 12A-3 and 12A-4 show the three different retorts considered in
this section. Figure 12A-5 is a diagram of the upgrading process slightly
modified from the commercial plant design suggested for a commercial plant
employing the TOSCO II retort .
417
-------
TABLE A12-1. NET INPUT AND OUTPUT QUANTITIES FOR AN INTEGRATED
OIL SHALE PLANT PRODUCING 50,000 BARRELS/DAY OF SYNTHETIC CRUDE
Raw shale grade (gal/ton)
Mined shale (tons/day)
Sized shale (tons/day)
Purchased power (megawatts)
Liquified petroleum gas (barrels/day)
Coke (tons/day)
Ammonia (tons/day)
Sulfur (tons/day)
Paraho Direct Paraho Indirect TOSCO II
3
30
92,000
88,000
0
-
*
170
80
30
105,000
100,000
0
1970
430
190
90
35
73,000
73,000
95
3300
890
170
200
^Specified as the sum of heat output of coke and low-Btu gas equal to
54 x 10 Btu/day.
TABLE A12-2. RAW SHALE AND PRODUCT OUTPUT PROPERTIES
Material
Raw shale
Raw shale
Crude shale oil
Synthetic crude
Liquified petroleum gas
Coke
Ammonia
Property
30 gal/ton
35 gal/ton
0.928 spec. grav.
0.825 spec. grav.
0.900 spec. grav.
Heating Value
(Btu/lb)
2,750
3,208
18,550
20,150
21,200
13,850
8,620
418
-------
MINING
OIL SHALE
CRUSHING
CRUSHED SHALE
RETORTING
EXCESS GAS
SHALE OIL
UPGRADING
AND
CLEANING
FUEL GAS
FEEDSTOCK &
LIQUID FUELS
DUST AND FINES
SPENT SHALE
DUST AND
FINES
DISPOSAL
BYPRODUCTS
SHALE
DISPOSAL
COKE,
SULFUR
3'
Figure A12-1. Flow diagram for surface processing of oil shale. (Reprinted from
Ref. 4 with the permission of the MIT Press, Copyright 1978 by the
Massachusetts Institute of Technology)
-------
t\J
O
FEED SHALE
ROTATING SPREADER
SHALE VAPOR
COLLECTING TUBES
DISTRIBUTORS
DISTRIBUTORS
MOVING GRATES
OIL MIST
REMOVAL
T
RECYCLE
GAS BLOWER
SHALE OIL
& RETORT WATER
DILUTION GAS
DILUTION GAS v
COOL RECYCLE GAS
PRODUCT
GAS
AIR
AIR BLOWER
RETORTED SHALE
Figure A12-2. Paraho retorting process - direct mode. (Reprinted from Ref. 4
with the permission of the MIT Press, Copyright 1978 by the
Mss sa.cn vis etts Institute of Technolocrvl _
-------
FEED SHALE
ROTATING SPREADER
SHALE VAPOR
COLLECTING TUBES
DISTRIBUTORS
DISTRIBUTORS
MOVING GRATES
OIL MIST
REMOVAL
RECYCLE
GAS BLOWER
SHALE OIL
& RETORT WATER
HOT GAS
HOT GAS
COOL RECYCLE GAS
PRODUCT
GAS
RETORTED SHALE
Figure A12-3.
Paraho retorting process - indirect mode. (Reprinted from Ref. 4
with the permission of the MIT Press, Copyright 1978 by
the Massachusetts Institute of Technology).
-------
FLUE GAS TO ATMOSPHERE
i
MINUS 1/2"
RAW SHALE
BALLS-
_
PYROl YQic
DRUM
900ฐF 7-
~l
lh
r
ACCUMU-
LATE R
"ROMMEL
k
-RESID.
OIL
HOT
SPENT
SHALE
SPENT SHALE
COOLER
EC
o
<
CO
-200 MESH
SPENT SHALE
TO DISPOSAL
WATER STEAM
Figure A12-4. TOSCO II retorting process.
-------
PLANT FUEL
RETORT ,
VAPORS '
FUEL GAS/LIQUEFIED GAS
NAPTHA/GAS OIL
SOUR WATER
SULFUR
PLANT FUEL
SYNTHETIC CRUDE
COKEV
PLANT FUEL
Figure A12-5.
Shale oil upgrading plant. (Reprinted
from Ref. 4 with the permission of the
MIT Press, Copyright 1978 by the
Massachusetts Institute of Technology)
423
-------
The water streams for retorting and upgrading are summarized in Table
12A-3 for a 50,000 barrel/day synthetic crude output. The different quantities
of water streams are related to whether pyrolysis is a result of direct heating
4
in an inert atmosphere or indirect heating by combustion gases . The TOSCO II
process is a net consumer of water compared to the Paraho processes because
the particular design uses wet venturi scrubbers for off-gas cleaning. In the
upgrading section of the plant, the makeup water is the water consumed in the
hydrogen plant as well as the water consumed in gas treating, in coking and in
other process steps. The foul water, from which ammonia and hydrogen sulfide
are stripped out, is made up principally of the retort water and the foul
water from the gas treating unit and the coker. Most of the designs have
assumed that this foul water will be used for spent shale disposal. The water
requirements for upgrading operations are fairly close for the three designs
because of the similar nature of the pre-refinery upgrading processes. The
Paraho Direct process is a net producer of water for both the retorting and
upgrading sections, while the TOSCO II water consumes the most water. However,
in any event, the process water requirements are very small compared to both
the cooling water and shale disposal water.
The thermal balances for each of the three 50,000 barrel/day oil shale
plants are shown in Table 12A-3 for the retort and in Table 12A-4 for the
4
integrated plant . The highest retort efficiency is attained by the direct
combustion process where no intermediate medium is used to transfer heat for
the pyrolysis. The slightly higher efficiency for the TOSCO II process is the
result of solid-to-solid heat transfer as compared to the less efficient gas-
to-solid heat transfer used in the Paraho Indirect retort. The thermal efficiency
to produce crude shale oil is quite high. However, the thermal efficiency for
the integrated plant is of primary interest since the important product is
upgraded synthetic crude. The thermal efficiency and evaporated water of the
Paraho Indirect process are comparable with coal liquefaction. However, the
fraction of unrecovered heat dissipated by wet cooling in the indirect process
is somewhat lower because part of the unrecovered heat is lost up a furnace
stack, which is not lost that way in the direct process.
The underground mining of shale is similar to that for coal. Table 12A-6
summarizes the water consumed for dust control in the underground mining of
1,2
shale . Since the Paraho designs do not differentiate between the requirements
for mining and crushing , we have assumed, based on the requirements as given
424
-------
TABLE A12-3.
t\J
Ln
RETORTING AND UPGRADING PROCESS WATER STREAMS FOR OIL SHALE PLANTS
PRODUCING 50,000 BARRELS/DAY OF SYNTHETIC CRUDE
RETORTING
IN
Water addition to shale
Water into venturi scrubbers
OUT
Water out in effluent sludge
Water of retorting
Net water product
UPGRADING
IN
Retort water
Makeup water
OUT
Foul water for reuse
Boiler blowdown
Net water consumed
Net water consumed in
retorting and upgrading
Paraho Direct
28
28
._
272
272
244
272
378
650
439
83
522
128
(116)
103 Ib/hr*
Paraho Indirect
32
32
159
159
127
159
433
592
350
95
445
147
20
TOSCO II
50
172
222
53**
83
136
(139)
83
444
527
266
119
385
142
281
* 5 6
10 Ib/hr = 1 gal/10 Btu of synthetic crude output.
**This water is assumed lost from the plant and is not counted as a product.
-------
TABLE A12-4. RETORT THERMAL BALANCES FOR
50,000 BARREL/DAY OIL SHALE PLANTS
9
10 Btu/hr
Heating Value Paraho Direct Paraho Indirect TOSCO II
Sized shale feed 20.0 22.9
Retorting heat - 1.8
Power for retorting* 0.4 0.5
Crude shale oil (14.5) (16.6)
Untreated product gas ( 3.1) ( 1.9)
Unrecovered heat 2.8 6.7
Overall conversion efficiency 86% 73% 76%
* 10,000 Btu/kwh (34% conversion efficiency).
426
-------
TABLE A12-5. THERMAL BALANCES, UNRECOVERED HEAT REMOVED BY WET COOLING AND
WATER EVAPORATED IN 50,000 BARREL/DAY OIL SHALE PLANTS
Heating Value
Sized shale feed
Purchased electricity*
Power to mine and size*
Synthetic crude
Liquefied gas
Coke
Ammonia
Unrecovered heat
10 Btu/hr
Paraho Direct Paraho Indirect
20.0
0.3
(12.1)
( 2.3)
( 0.1)
5.8
22.9
0.3
(12.1)
( 0.6)
( 0.5)
( 0.1)
9.9
TOSCO II
19.6
0.9
0.2
(12.1)
( 0.9)
( 1-0)
( 0.1)
6.6
Overall conversion efficiency
Fraction of unrecovered heat
to evaporate water
Water evaporated for cooling
(103 Ib/hr)
71%
28%
1,160
57%
19%
1,330
68%
18%
850
* 10,000 Btu/kwh (34% conversions efficiency).
Heating value of coke and low-Btu gas.
427
-------
2
in the TOSCO II design that 70 percent of the dust control water is for the
mine and the remaining 30 percent is for crushing and other dust control
operations. There is about a 30 percent difference in the unit water require-
ments between the two designs, although the absolute requirements are about
the same. Table 12A-6 also summarizes the water requirements for dust control
in preparing the shale for delivery to the conversion plant and for storage
within the mine.
Approximately 80-85 percent of high grade raw shale remains as spent shale
after retorting. If the oil shale grade is specified, the fraction of the raw
shale to be disposed may be estimated from the following equation.
Yield (gal/ton) = 1.97 x Organic Matter (wt %) - 2.59
Table 12A-6 summarizes the quantities mined, retorted and disposed for a 50,000
barrels/day integrated mine-plant complex. The processed shale from the TOSCO II
2
retorting process is a fine, black, sandy material , while the processed shale for
the Paraho retorts are lumps .
Different procedures with considerably different water needs have been
proposed for the disposal of the TOSCO and Paraho spent shales. In the TOSCO
II design shown in Figure 12A-7, the spent shale leaving the cooler is moisturized
to approximately 15 percent moisture content in a rotating drum moisturizer. Steam
and processed shale dust produced in the moisturizing procedure are passed through
a venturi wet scrubber to remove the dust before discharge to the atmosphere.
The moisturized spent shale is transported by a covered conveyor belt to the
disposal area, and then spread and compacted to a density of about 90 pounds of
dry spent shale per cubic foot. During the transport, spreading and compaction
operations, about 13 percent of the added moisture evaporates. This leaves about
a 13 percent in-place moisture content, defined as an optimum for compaction and
6
setting purposes .
The importance of the moisturizing is that the addition of the water to
the TOSCO II type processed shale, at a predetermined shale temperature, leads
to cementation of the shale after compaction. This cemented shale appears to
permanently "freeze in" the moisture that was added , much of which was dirty
process water. Moreover, the shale becomes effectively impermeable and resists
428
-------
TABLE A12-6. WATER CONSUMED IN DUST CONTROL FOR MINING AND FUEL PREPARATION
FOR UNDERGROUND SHALE MINES INTEGRATED WITH SHALE OIL PLANTS
PRODUCING 50,000 BARRELS/DAY OF SYNTHETIC CRUDE
Paraho Direct Paraho Indirect TOSCO II
Shale mined (tons/day)
Water consumed in mining
103 lb/hr
Ib water/10 Ib shale
Water consumed in fuel
preparation
103 lb/hr
Ib water/10 Ib shale
92,000J
176^
23
76
10
105,000*
202+
23
87
10
73,300
195
32
83
14
* 5 percent more than used
Based on 70 percent to mining, 30 percent to crushing
'TABLE A12-7 OIL SHALE QUANTITIES IN TONS/DAY FOR INTEGRATED PLANTS
PRODUCING 50,000 BARRELS/DAY OF SYNTHETIC CRUDE
Process
TOSCO II
Paraho Direct
Paraho Indirect
Grade
(gal/ton)
35
30
30
Mined
73,000
92,000
105,000
Fines
4,000
5,000
Spent Shale
60,000
71,000
85,000
Disposal
60,000
75,000
90,000
429
-------
600 GPM
MOISTURIZER
SCRUBBER
STACK
HOT
SPENT
SHALE
18 GPM
WATER
-200 MESH
SPENT
SHALE
U)
o
SPENT
SHALE
COOLER
MOISTURIZER
VENTURI WET
SCRUBBER
SLUDGE
6 GPM
200 GPM
EVAPORATED IN TRANSPORT
i
I MOISTURIZED SPENT SHALE
TO DISPOSAL (200ฐF)
COVERED SPENT
SHALE CONVEYOR
-K 1,500 GPM IN SHALE
60,000 TPD DRY SHALE
Figure A12-6. TOSCO II spent shale disposal process with
quantities appropriate to an integrated plant producing
50,000 barrels/day of synthetic crude. (Reprinted from
Ref. 4 with the permission of the MIT Press, Copyright
1978 by the Massachusetts Institute of Technology).
1,300 GPM IN
COMPACTED
SHALE PILE
-------
percolation so that soluble salts cannot be leached out Processed shale
piles in a TOSCO II commercial embankment are designed for a maximum depth
of 700 to 800 ft and an average depth of about 250 ft.
In the TOSCO II design of Ref. 2 the spent shale is to be disposed of in
a canyon. The shale is compacted into a shallow embankment and benched to
decrease erosion. A flood control reservoir is located above the canyon to
divert water from the canyon. Any runoff from the embankment is diverted back
to the plant for use as moisturizer water.
After 20 years of operation of a 50,000 barrel/day plant the compacted
2
spent shale would cover an area of approximately 800 acres . This is an average
of about 40 acres/yr and for a compaction density of 90 Ibs/ft would correspond
to a mean height of 250 ft. Irrigated revegetation will be undertaken as permanent
surfaces are created by the fill. Prior to revegetation, water spraying will be
used to control dust.
In the Paraho design concept for spent shale disposal , an "earth"' dam
constructed of retorted shale would be built at the mouth of a valley selected
for a disposal area. The valley itself would be lined with a heavy compacted,
impervious layer of retorted shale. By adding about 20 weight percent water prior
to compaction, the shale cements up and the shale layer would thus be made
impermeable. The valley would then form a lined basin ("bath tub") into which
the retorted shale could be deposited. It is assumed that any precipitation
leaching through the spent shale would be held within the basin. The important
point here is that the spent shale would be compacted but not be wetted down,
except for controlling dust and for revegetation. Tests have shown a compaction
density of about 90 Ibs/ft can be obtained, which is similar to that obtained
for spent shale that has been wetted down. It is estimated that less than one
percent of the total volume of the shale disposed would have to be wetted to
obtain a material of high strength and low permeability. Such a disposal scheme
would substantially reduce the water requirements for oil shale plants. On the
other hand, the TOSCO procedure, although more water consuming, has had sufficient
long-term testing to be reasonably assured that serious environmental problems
will not be encountered.
431
-------
Estimates of the water needed to revegetate and to control dust prior to
revegetation must rely solely on results of tests on the specific processed
shale in the particular disposal area. In any case, the amount of water
required will be relatively large compared, for example, to reclaiming strip
mined coal lands in an arid region. At least 4 ft of water are required for
leaching the salt from the spoils. Additionally, two to three times this
amount could be required over, say, a five year period to ensure a successful
cover. To some extent, the amount of water needed for dust control will depend
on how rapidly a vegetative cover is established.
Table 12A-8 summarizes the reported data on the water requirements for
spent shale disposal. The Paraho requirements as reported did not distinguish
between that water needed for dust control and that for vegetation. The estimate
for the revegetation water for the TOSCO II spent shale piles was derived from
averaging 78 gal/min for years 1 to 11 of the plant and 780 gal/min for years
12 to 20. These figures have been scaled upward somewhat from the values quoted
for the plant size in Reference 2.
There are within an integrated mine-plant synthetic fuel complex a number
of consumptive uses of water other than those already considered which should
be considered in any water balance. These uses include sanitary, potable, service
and fire water needs in both the plant and the mine, water for dust control within
the boundaries of the conversion plant itself and evaporation from on-site
reservoirs and settling basins. The calculation of these consumptive water uses
is given in Appendix 9 for coal conversion. Table 12A-9 summarizes these
requirements for integrated oil shale plants.
Table 12A-10 summarizes the net water consumed and wet-solid residuals
generated for all three processes for integrated oil shale plants producing
50,000 barrels/day of synthetic crude. The absolute quantities have also been
normalized with respect to the heating value of the product fuel.
432
-------
TABLE A12-8. WATER REQUIREMENTS FOR SPENT SHALE DISPOSAL FROM
INTEGRATED PLANTS PRODUCING 50,000 BARRELS/DAY OF SYNTHETIC CRUDE
Water (10 Ib/hr)
Dust Control & Ib water per
Process Moisturizing Revegetation Total 10 Ib spent shale
TOSCO II 1,003
Paraho Indirect -
Paraho Direct -
336*
1,160
443
1,389
1,160
443
278
155
71
*Dust control 139 X 10 Ib/hr. Revegetation of 197 X 10 Ib/hr is 20 year average
TABLE A12-9. SERVICE AND OTHER WATER REQUIREMENTS FOR INTEGRATED OIL
SHALE PLANTS PRODUCING 50,000 BARRELS/DAY OF SYNTHETIC CRUDE
(103 Ib/hr)
Purpose Paraho Direct Paraho Indirect TOSCO II
Sanitary, potable, service
usage 10 13 10
Plant dust control 30 32 60
Evaporation 10 18 17
Total 50 63 87
433
-------
TABLE A12-10. SUMMARY OF WATER CONSUMED AND WET SOLIDS RESIDUALS
GENERATED FOR INTEGRATED OIL SHALE PLANTS PRODUCING
50,000 BARRELS/DAY OF SYNTHETIC CRUDE
Paraho Direct Paraho Indirect TOSCO II
Net water consumed in retorting
and upgrading (10 Ib/hr) (116)
Water evaporated for cooling
(103 Ib/hr) 1160
Water consumed for dust control
in mining (10 Ib/hr) 176
Water consumed for dust control
in fuel preparation (10 Ib/hr) 76
Water consumed for spent shale
disposal (103 Ib/hr) 443
Water consumed for other plant
uses (103 Ib/hr) 50
Total water consumed (10 Ib/hr)
Total water consumed (gal/10 Btu)
Spent Shale (tons/day)
Water (tons/day)
Total wet-solids residuals
(tons/day) 75,000
Total wet-solids residuals
(lb/105 Btu) 520
20
1330
202
87
1160
63
90,000
620
281
850
195
83
1389
87
1789
18
75,000
*
2862 2885
28 29
90,000 60,000
* 7,800
60,000
470
*Negligible
434
-------
REFERENCES - APPENDIX 12
1. 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_ (4), 49-64, Oct 1976.
2. Colony Development Operation, "An Environmental Impact Analysis for a
Shale Oil Complex at Parachute Creek, Colorado, Part I - Plant Complex
and Service Corridor," (also corrected water system flow diagram, personal
communication), Atlantic Richfield Co., Denver, Colorado, 1974.
3. Whitcombe, J.A. and Vawter, R.G., "The TOSCO-II Shale Process," Paper
No. 40a, AIChE 79th National Meeting, March 1975.
4. Probstein, R.F. and Gold, H., Water in Synthetic Fuel Production - The
Technology and Alternatives. The MIT Press, Cambridge, Mass., 1978.
5. Development Engineering, Inc., "Field Compaction Tests, Research and
Development Program on the Disposal of Retorted Oil Shale Paraho Oil
Shale Project," Report No. OFR78-76, Bureau of Mines, Dept. of the
Interior, Washington, D.C., Feb 1976.
6. Metcalf & Eddy Engineers, "Water Pollution Potential from Surface Disposal
of Processed Oil Shale from the TOSCO II Process," Vol. I, Report to Colony
Development Operation, Atlantic Richfield Co., Grand Valley, Colorado,
Oct 1975.
435
-------
APPENDIX 13
WATER AVAILABILITY AND DEMAND IN EASTERN AND CENTRAL REGIONS
Resource Analysis, Inc., under subcontract to Water Purification Assoc-
iates, prepared a general assessment of the water resources data in the major
coal and oil shale bearing regions of the United States. Water resources data
was collected and used as a basis for determining the availability of surface
and groundwater resources at specific coal and oil shale conversion plant
sites in the Eastern and Central coal bearing regions and the Western coal
and oil shale bearing regions. The draft report on the Eastern and Central
regions that was submitted as part of their study is included in its entirety
in this Appendix.
436
-------
Resource Analysis, Inc.
1050 MASSACHUSETTS AVENUE
CAMBRIDGE, MASSACHUSETTS 02138
617-354-1 922
EAST/CENTRAL WATER SUPPLY DATA
FOR
A STUDY OF WATER RELATED SITE AND PLANT
DESIGN CRITERIA TO DETERMINE FEASIBILITY OF SYNTHETIC FUEL
PLANT SITING AND LOCAL ENVIRONMENTAL IMPACTS
Prepared under subcontract to
WATER PURIFICATION ASSOCIATES
238 Main Street
Cambridge, Massachusetts 02142
August,1978
437
-------
TABLE OF CONTENTS
Section Page
1 INTRODUCTION 441
1.1 Study Objectives 441
1.2 Scope of Studies 442
1.3 Study Region and Specific Sites 443
2 SUMMARY OF RESULTS AND CONCLUSIONS 449
3 SURFACE WATER RESOURCES 454
3.1 General 454
3.2 Water, Supply Availability 455
3.3 Surface Water Doctrines 460
3.4 Competing Water Use 464
3.5 Surface Water Quality 467
4 GROUNDWATER RESOURCES 472
4.1 General 472
4.2 Groundwater Availability 473
4.3 Groundwater Doctrines 481
4.4 Groundwater Quality 483
5 POTENTIAL ENVIRONMENTAL IMPACTS 487
5.1 Impacts on the Land 487
5.2 Water Quality Impacts 487
5.3 Impacts on Groundwater Systems 489
6 SITE SPECIFIC SUMMARY 493
REFERENCES AND DATA SOURCES 502
438
-------
LIST OF TABLES
Table No. Title Page
1.1
1.2
3.1
3.2
3.3
3.4
3.5
4.1
4.2
4.3
5.1
5.2
6.1
6.2
6.3
6.4
6.5
6.6
6.7
List of Primary Coal Conversion Plant Sites
for Eastern and Central Study
List of Additional Coal Conversion Plant Sites.
Assessment of Surface Water Sources for Primary
Sites
Assessment of Surface Water Sources for
Additional Sites .
Consumptive Water and Surplus Supplies in the
Ohio River Basin for 1975 and 2000
Significance of the Relevant Chemical and
Physical Properties of Water
Chemical Characteristics of the Surface Water
Sources
Assessment of Groundwater Availability at Sites
with Insufficient Surface Supplies
Assessment of Groundwater Availability for the
Secondary Sites .
Chemical Characteristics of Groundwater
Sources
Assessment of Potential Impacts at Designated
Groundwater Sites
Assessment of Potential Impacts at Supplemental
Groundwater Sites
Water Resources Summary for Alabama
Water Resources Summary for Illinois
Water Resources Summary for Indiana
Water Resources Summary for Kentucky
Water Resources Summary for Ohio
Water Resources Summary for Pennsylvania . . .
Water Resources Summary for West Virginia . . .
444
445
457
459
466
469
470
477
482
486
491
492
495
496
497
498
499
500
501
439
-------
LIST OF FIGURES
Figure No. Title Page
1.1 Coal Conversion Site Locations and Surface
Water Features 447
4.1 High Yield Sources of Groundwater 475
440
-------
1. INTRODUCTION
1.1 Study Objectives
This draft report presents a general assessment of the water
resources data that has been reviewed as a part of the East/Central
synthetic fuel plant siting study being performed under subcontract
to Water Purification Associates, Cambridge, Massachusetts for the
Energy Research and Development Administration. The objective of
the water resources portion of the overall study is to define the
availability of surface and groundwater resources at each specific
site in terms of other competing water users.
In order to investigate water related aspects of the feasibility
of synthetic fuel plant siting in the Eastern and Central states,
Water Purification Associates selected approximately 30 primary
specific site locations throughout the region, each having sufficient
coal reserves in the immediate area to justify a conversion plant.
These sites were selected in such a way as to cover a diverse mix of
geographical and climatological characteristics of the coal producing
regions.
Sufficient and reliable water supplies are essential to the
siting and operation of the synthetic fuel production processes under
study. Significant quantities of water are consumed as a raw material
on a continuous basis in the liquefaction and the gasification processes
441
-------
Where the wet cooling process is used,large amounts of water are lost
to evaporation. Large quantities of water can also be required where
slurry pipelines are used to transport coal from the source to the
actual conversion site. The supply of water for these purposes 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. This report presents
the basic water resources information that can be used as a basis for
determining the feasibility in terms of water availability at the
specific sites under study.
1.2 Scope of Studies
The water resources information included in this report consists
of the data necessary to establish the surface and groundwater supplies
actually available for use in the coal conversion process at each
prospective site. Factors entering into this determination are the
extent and variability of nearby streamflows or groundwater aquifers,
legal institutions regulating the use of these waters, and the implica-
tions of competing users for 1imited supplies in certain areas. Data
on the quality of water in terms of constitutents detrimental to the
coal conversion process have been compiled for each water source for
which such data was available. Also included is a general assessment
of potential environmental impacts of energy development in the Eastern
and Central coal regions. These potential impacts fall into two general
442
-------
categories: the environmental impacts due to the actual coal mining
or conversion activities, and the hydrologic impacts associated with
the withdrawal of surface or groundwater supplies.
In assessing the water resources situation at each designated
site, no attempt has been made to generate new field data. All data
used in the investigations was previously collected by various
Federal and state governmental agencies, universities, or local
groups. 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. During this process all data used was
reviewed for consistency with other data or basic hydrologic principles.
Conclusions were then drawn from the available data as to the existence
of favorable or unfavorable water resources conditions at the various
locations under consideration as synthetic fuel plant sites.
1.3 Study Region and Specific Sites
The specific sites selected for detailed feasibility analysis are
located in seven states in the Eastern and Central coal resource
regions of the United States. The site locations were specified as
county-sized areas in the states of Alabama, Illinois, Indiana,
Kentucky, Ohio, Pennsylvania, and West Virginia. The matrix of primary
site locations, type of mining activity, and designated water source pre-
sented in Table 1.1 is intended to cover a representative sampling of the
geographic location, coal reserve characteristics, climate, and
topography likely to be used as sites for synthetic fuel plants. A
number of secondary sites as shown in Table 1.2 were also considered to
determine the overall water availability in the coal regions as a whole,
but were not considered per se in the detailed analysis of specific
443
-------
Table 1.1
LIST OF PRIMARY COAL CONVERSION PLANT
SITES FOR CENTRAL AND EASTERN STUDY
STATE
Alabama
Illinois
Indiana
Kentucky
Ohio
Pennsylvania
West Virginia
COUNTY
Jefferson
Morengo
Bureau
Shelby
St. Clair
White
Bureau
Fulton
St. Clair
Saline
Gibson
V i go
Sullivan
Warrick
Floyd
Harlan
Henderson
Muhi enberg
Pike
Gallia
Tuscarawas
Tuscarawas
Jefferson
Allegheny
Somerset
Fayette
Kanawha
Marshall
Monongalia
Preston
Mingo
MINING
U
S
U
U
U
U
S
S
S
S
U
U
S
S
U
U
S
S
S
U
U
U
S
U
U
U
U
U
U
U
S
1
COAL'
B
L
B
B
B
B
"B
B
B
-B
B
B
B
B
B
B
B
B
B
B (HV)
B (MV,LV)
B (MV,LV)
B (HV)
B (HV)
B (HV)
B (HV.MV.LV)
B (HV)
WATER SOURCE
Coosa River
Tombigbee River or
Groundwater
Ground Water
Kaskaskia River
Mississippi River
Wabash River
Illinois River
Ground Water
Mississippi River
Saline River
White River
Wabash River
Wabash River
Ohio River
Big Sandy River
Cumberland River
Ohio
Green River
Surface Water
Ohio River
Tuscarawas River
Ground Water
Ohio River
Allegheny River
Surface Water
New River
Kanawha River
Ohio River
Monongahela River
Cheat River
Big .Sandy River
1
U = underground mining; S = surface mining.
>
"A = Anthracite; B = bituminous; HV = high volatility, MV = medium volatility,
LV = low volatility; L = lignite.
444
-------
Table 1.2
LIST OF ADDITIONAL COAL CONVERSION PLANT SITES
State
Alabama
County
Fayette
Marion
Jackson
DeKalb
Water Source
Warrior (R)
Tennessee (R)
Tennessee (R)
Tennessee (R)
II1inois
Mercer
McLean
Mississippi (R)
Illinois (R)
Kentucky
Hopkins
McCreary
Lee
Lawrence
Green (R)
Cumberland
Kentucky
Big Sandy (R)
Ohio
Pennsylvania
Morgan
Venango
Clearfield
Cambria
Muskingum
Allegheny (R)
West Branch
Conemaugh
West Virginia
Randolph
Greenbrier
Tygart
Greenbrier
445
-------
sites. Figure 1 .1 shows the primary and secondary site location with
respect to the coal reserves and major water resources features of the
study region.
Several aspects of the actual design and operation of a coal
conversion plant are of importance in evaluating the relationship
of the plant to the water resources of the area. It has been assumed
for the purposes of this study that the consumptive use requirement
for process and cooling water, and all associated uses at each plant
would be about 4500 gallons per minute or an equivalent streamflow
of about 10 cfs. In order to provide a stand-by water supply for
times of water shortage, a holding pond system having a reserve supply
of one week's water requirement was assumed to be typical. It was
also assumed that water treatment costs are such that lower quality
water supplies such as brackish groundwater or municipal treatment
plant effluents would be acceptable water sources. Conversion plants
are expected to be designed to make maximum use of water recycling within
the plant and return no flows or waste residues to the receiving waters.
The coal conversion plants under consideration,in some instances
where terrain and water supplies permit, may be located at the mine
mouth. Water use regulations prohibiting non-riparian"1"water use as
discussed in this report, or adverse terrain features may at many
locations require the actual conversion plant to be located some
distance away from the mine. Unit train or coal slurry transport of
the coal from mine to conversion plant will be required in these
instances.
A Riparian water right is defined as a right derived from ownership
of land adjacent to a natural watercourse.
446
-------
1
SITE LDCAT10N:
U PRIMARY SITES
D SECONDARY SUES
ILLINOIS BASH
Figure 1.1 Coal Conversion Site Locations and
Surface Water Features(continued)
447
-------
O CLEARIELD
CAMBRIA
D
GHENY
SOMERSET
RANDOLPH
OGREENBRIER
MORENGO
SITE LOCATIONS
PRIMARY SITES
D SECONDARY SITES
APPALACHIAN BASIN
Figure 1.1 Coal Conversion Site Locations and
Surface Water Features
448
-------
2. SUMMARY OF RESULTS AND CONCLUSIONS
The most significant findings of the water resources investigations
to-date may be summarized as follows.
1. Surface water supply sources were specified for most of the
sites to be studied. Sufficient reliable supplies to support one or
more coal conversion plants exist close to many of the sites, especially
those with a major regulated river flowing through or adjacent to the
study area. This applies to all sites in the vicinity of the following
major rivers:
Mississippi
Ohio
Wabash-White
Kanawha-New
Allegheny
Tennessee
Tombigbee
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 conversion plant demand is
generally in the order of less than one percent of the seven-day,
twenty-year low-flowt Uses of this magnitude would appear to safely
satisfy the common law requirement of being reasonable relative to
other users.
2. Surface water supplies are much less reliable in the smaller
streams in the upper water courses. The eastern Kentucky and adjacent
The seven day, twenty-year low flow is defined as the minimum average
flow over seven consecutive days that is expected to occur with an
average frequency of once in twenty years.
449
-------
West Virginia coal regions in the Big Sandy River Basin; the upper
Cumberland, Kentucky, and Green River basins in eastern Kentucky, and
the northern West Virginia coal region in the Monongahelia Basin fall
into this category. In these areas extreme low-flows are practically
zero. A coal conversion plant demand could easily represent a very
significant portion of the seasonal low-flow in many of these areas,
and therefore be judged to be an unreasonably large use. In order for
a plant to be sited in these regions an alternative or supplemental
supply to streamflows must be assured. In some cases the construction
of sizable surface water impoundments may be practical, while in other
cases this would be prohibited by topographical constraints. Ground-
water supplies to supplement surface supplies during times of scarcity
look favorable in several cases as described below.
3. The riparian land requirement in many instances will discourage
the transfer of surface water over even a short distance from small
streams to coal reserves on a non-riparian'site. Historically industries
using significant amounts of water have located on major rivers with
surplus water supplies for this very reason. Although several states
are presently considering statutory modifications to the Riparian
Doctrine which might eventually allow users (including non-riparian
users) to reserve definite supplies of surface flows, none of the seven
states in the study region have enacted an effective permit system to-
date. A non-riparian use of large volumes of water would currently be
feasible from an institutional point of view only from a major river
(those cited in item 1) with large water surpluses.
450
-------
4. In addition to the 30 or so primary plant sites, several
other regions were considered to determine the overall water avail-
ability of the coal regions as a whole. These regions were not
considered as such in the detailed analysis of specific sites. Locations
considered in this vein found to have surface supplies generally
favorable for energy development include: several potential sites in
northern Alabama supplied from the Tennessee River, in north-
central Illinois supplied from the Mississippi or Illinois Rivers, in
Kentucky from the mid-Green River, in Ohio from the Lower Muskinghum
River, and additional sites in northwest Pennsylvania from the Allegheny
River. Groundwater supplies in west-central Alabama also appear to
be favorable. Regions generally found to have limited water supplies
for energy development include: the upper watersheds of the Cumberland,
Kentucky, Green, and Big Sandy Rivers in eastern Kentucky; the coal
areas of western Pennsylvania except those that carTbe supplied from the
Allegheny, Ohio, or Susquehanna Rivers; and the east-central West
Virginia region.
5. Groundwater was specified as a primary source of supply at
a few locations which include Bureau and Fulton Counties in Illinois
and Tuscarawas County, Ohio. Indications are that there would be no
problem in developing the many high-yield wells that would be required
to provide the reliable supplies at these sites. Groundwater also
looks promising as a conjunctive supply in certain areas where surface
supplies are seasonally questionable. Unfortunately, the groundwater
situation is most favorable from alluvial aquifers recharged by major
streams in the valley bottoms where surface supplies are best, and
451
-------
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.
6. Since the rights of a landowner to use groundwater are
generally more absolute than those concerning surface water use, the
development of groundwater supplies as a primary or supplemental source
for energy-related uses requiring large capital investments may be
preferable to surface water on the basis of institutional feasibility.
7. Water quality data on a number of constituents having poten-
tially detrimental effects on coal conversion processes were compiled
for many water supply sources. In surface waters, concentrations of
various constituents were found to vary from location to location
depending on the local geology, population density, and industrial
development. Even more significant variations over time are evident at
certain locations with major sources of industrial pollution or where the
effects of varying dilution rates are particularly severe. The Muskingum,
White, and Illinois Rivers exhibit this tendency. The quality of
groundwater supplies is similar to that of surface waters where alluvial
aquifers are used as a source. Groundwater from deep consolidated
aquifers on the other hand may be brackish and highly mineralized. The
chemical composition of water from a given well at a particular location
generally will show very little variation over time, as compared to a surface
water source.
8. Potential hydrologic impacts are associated with both the
coal mining operation and the process of converting the coal to synthetic
fuels The mining operation, whether it be underground or strip mining,
452
-------
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 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 evaporation 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. Because this problem is
very localized and site dependent the problem must be considered on a
site by site basis at a much smaller scale than present site definitions
allow.
The synthetic fuel conversion process has several potential hydro-
logic impacts associated with it as well. Since no return flows or
waste residues are to be returned to the receiving waters the potential
for environmental degradation are minimized. The major potential impact,
therefore,is that associated with the use of groundwater as a source of
water supply. The feasibility of using groundwater as a water supply
source must be 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.
453
-------
3.2 Water Supply 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 is
described more fully in Section 3.3., the Riparian Doctrine governing
water use in the Eastern States requires that 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:
1) Favorable. Site use is less than about 5 percent of the
estimated seven-day, twenty-year low-flow
2) Questionable. Site use is about 10 percent of the estimated
seven-day, twenty-year low-flow
3) Unreliable. Site use is more than 20 percent of the estimated
seven-day, twenty-year low-flow.
In this analysis the water use associated with a typical plant was
assumed to be approximately 4,500 gpm (about 10.0 cfs, or 7,000 acre-ft/
year).
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
455
-------
seven-day water supply. Low-flow values were determined from Stream-
flow Data Program Reports for each state (USGS, 1970), various state
or regional agencies, or were estimated from historical low-flows at
nearby gauging stations. Low-flows from major streams affected by
regulation are very difficult to establish accurately. In many of
these instances, however, flows are relatively high and the objective of
regulation is to achieve higher low-flows.
Table 3.1 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. These
include all of the sites having the following rivers as designated
sources:
Mississippi
Ohio
Kanawha-New
Wabash-White
Allegheny
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 abundant supplies at hand where meeting the water requirements
456
-------
TABLE 3.1
ASSESSMENT OF POTENTIAL SURFACE WATER SOURCES
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
Morengo Tombigbee 5,900 4450 8,631 165
Bureau Groundwater
Bureau Illinois 12,040 - 12,500(E) l.BOO(E)
Fulton Groundwater
St. Clair Mississippi (R) 700,000 0100 177,000 18,000 10
Saline Saline None 10(E)
Shelby Kaskaskia(R) 1,054 5920 788 0
White Wabash 28,635 3775 27,030 1,650
Gibson White(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
Warrick Ohio(R) 107,000 3220 113,700 NA 2
(13
Floyd Levisa Fork 1,701 2098 2,104 20
Harlan Cumberl and(R) 374 4010 689 3
Henderson Ohio(R) 107,000 3220 133,900 NA 15
Muhlenburg Green Pond(R) 6,182 3165 9.201 250
Pike Levisa Fork 1,237 2015 1,458 2
Galia Ohlo(R) --- --- 77,600 8
Jefferson Oh1o(R) --- 40,900 --- 5
Tuscarawas Tuscarawas(R) 2,443 1290 2,453 170
Tuscarawas Groundwater
Allegheny Allegheny(R) 12,500 19,500(E) 900(E)
Somerset Casselroan 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
Mingo 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: FปFavorable, QปQuest1onable, U-Unrel 1able
(2) Low-flow (1 day, 50 year) data from Illinois State Water Survey (1975)
(3) Estimated from nearby gauges
(4) Estimated using regression equations 1n Streamflow Data Program Reports
(5) Low flow (7 day, 10 year) from ORBC Table of Instream Flows
(6) Pennsylvania Department of Forests and Haters, 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
See
800(2)
See
,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)
See
(NA)
12(4)
,184
,750
,600(5)
30
248
95
(USGS, 1970)
F
F
Table 4.1
F
Table 4.1
F
U Ohio or Prop. Res.
U Lake Shelbyvllle
F
F
F
r
F
U Dewey Lake
U Surface Storage
F
Q Groundwater
U Flshtrap Lake or Groundwater
r
f
Q Groundwater
Table 4.1
F
U Quemahonlng Res.
f
f
F
U Groundwater
Q Surface Storage
U Lake Lynn or Groundwater
(NA) Data not available at present, or nonapplIcable
-------
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 alterna-
tive or supplemental source 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 in the future. Following a discussion of institutional factors
controlling the use of surface supplies, the available data on present
uses and projected future demand is presented in Section 3.4.
As indicated earlier, in addition to the 30 or 50 primary specific
sites, additional sites in several other regions were considered in a
general sense 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 3.2 with
their associated water source and a general assessment of the water
supply availability at each site. These results indicate that several
sites in northern Alabama could be supplied from the Tennessee River;
that sites in north-central Illinois could be supplied from either the
Mississippi or Illinois Rivers; and that additional sites could be
supplied from the Green River in Kentucky, the Muskingum River in Ohio,
or the Allegheny River in Pennsylvania. The region found to have the least
favorable water supplies for coal conversion is that at the upper
reaches of the Cumberland, Kentucky and Big Sandy Rivers in Kentucky.
458
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TABLE 3.2
ASSESSMENT OF ADDITIONAL SURFACE WATER SOURCES
State
Al abama
Illinois
Kentucky
Ohio
Pennsylvania
W. Virginia
County
Fayette
Marlon
Jackson
De Kalb
Mercer
McLean
Hopkins
McCreary
Lee
Lawrence
Morgan
Venango
Clearfield
Cambria
Randolph
Greenbrier
Drainage
Source Area
(SM)
Warrior(R)
Tennessee(R)
Tennessee(R)
Tennessee(R)
Mississlppi(R)
Ill1no1s(R)
Green(R)
Cumberland
Kentucky
B1g Sandy(R)
Musr.ingum
Allegheny(R)
West Branch
Conemaugh
Tygart
Greenbrier
4828
30810
25610
25610
119000
15819
7564
1977
2657
2143
7422
5982
1462
715
408
1835
(1) Situation assessment: F-Favorable
(2) Low-Flow (1 day, 50 year)
(3) Estimated using regression
(4) Pennsylvania Department of
(5) Ohio
(R) River
Department of Natural
from 111
USGS Mean Historical
Gauge No. Flow Low Flow
(CFS) (CFS)
4650
5895
5755
5755
4745
5685
3200
4045
2820
2150
1500
02550
5425
04150
0510
1835
7822
51610
43760
43760
62570
14529
10960
3199
3638
2480
7247
10330
2467
1269
800
1980
; Q=Questionable; U=Unrel
inols State
equations 1n USGS
Forests
and Waters
Resources Bulletin
substantially regulated from
Water Survey
37
105
400
400
5000
1810
280
4
4
8.4
218
334
100
105
0.1
24
(able
Report No.
Streamflow Data Program
Bulletin No.
40 (1965)
1 (1966)
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.
source location
(NA) Data not available at present or non-applicable
-------
3.3 Surface Water Doctrines
Most regions in the east and centra] portions of the United States
receive sufficient rainfall, so that surface supplies in many areas are
plentiful. Relatively high population densities in certain areas,
and great seasonal variabilities in runoff rates, however, result in
many situations where the demand for the use of water creates competition
for the available supplies. The industrial use of water for energy
development is often, one of many competing uses to which limited water
supplies must be allocated.
The majority of the sites under consideration in this study involve
river or stream flow as a primary source of water for the conversion
process. Where such supplies are somewhat limited, the required water
may be available from existing or future reservoirs or from groundwater
systems . Each of these potential sources is
subject to general legal principles as to how the water may be used.
Local statutory enactments may also affect use in several states. For
the purposes of this report, the general aspects of water use regula-
tions were reviewed primarily as applicable to the surface water supply
assessments described in the previous Section. Specific state qualifica-
tions are also discussed.
The use of surface flows in the Eastern United States has tradi-
tionally been subject to a judicially developed set of legal principles
known as the Riparian Doctrine which define water rights as an incidence
of ownership of land that adjoins or is traversed by a natural stream
(Cox_, 1975). Two separate applications of the doctrine have been
recognized at one time or another. The natural flow concept is the
460
-------
older of these and has been replaced generally by the concept of
reasonable use. The natural flow concept was based on the theory
that the objective of water use regulations was to maintain the
natural flow in a stream and was more restrictive, particularly for
industrial applications involving the consumption of water. The
reasonable use interpretation of the Riparian Doctrine is now widely
accepted and states that 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 statement of the reasonable use concept of the doctrine suggests
three important considerations related to the use of water for energy
development:
1) Reasonable Use. The question of reasonableness is a rather
vague requirement primarily determined by the impact of the use in
question on other valid users. This is a relative matter dependent on
a particular set of circumstances and generally more dependent on the
magnitude of the proposed use than the nature of it. The basic require-
ment 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 where energy reserves are located some distance
461
-------
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 satisfieda very restrictive condition (Cox, 1975). Only
the major rivers of the region such as the Kanawha, Allegheny, and
Ohio 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 1 imitation in the
doctrine to significant users requiring dependable, ;long-term avail-
ability such as synthetic fuel plants is that a reasonable use at
one point in time may become unreasonable at some unknown future time.
Other riparian owners do not lose their 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 uses 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 modifica-
tions to the Common Law Doctrine that allow some degree of water
appropriation by permit. These states are Kentucky, Indiana, Iowa,
and North Carolina. Since a number of other states are considering
462
-------
or moving towards similar enactments the nature of these statutes is
discussed below even though only Indiana and Kentucky are actually
included in this study.
Kentucky: Statutes have been enacted which cover water use
throughout the state. The impact of these statutes has been very
limited since they do nothing to either regulate water use or assure
a reliable supply to users. Basically anyone requesting a permit to
use water has been able to obtain one whether or not sufficient water
is available. The right by permit to use water is not assured during
times of reduced supplies.
Indiana: Present statutes regulate the use of groundwater only.
Under these laws the Department of Conservation seeks to restrict
withdrawals where other users would be affected. New users of more
than 100 gpd must obtain a permit.
Iowa: Forceful statutes are in effect which allow the allocation
of water through an effective permit system.
North Carolina: Statutes have been enacted to control water use
in designated problem areas only. Other states are considering this
approach.
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 significant water using industries to locate primary on the
major rivers of the region that have surplus flows.
463
-------
According to a recent survey (Ausness, 1976) of legal aspects of
water use in the East the states of Alabama, Illinois, Ohio, Pennsylvania,
and West Virginia, among others, currently adhere to the Common Laws of
water use with no significant statutory modifications. Although future
legislation may eventually alter this situation, present planning for
major new water use should be in accordance with existing laws.
3.4 Competing Water Use
Previous sections have discussed overall surface water availability
at the specific study sites arid the legal considerations that have an
effect on the manner in which the water supplies can be used. Throughout
the East/Central study region an essential determinant of a given user's
right to a certain quantity of water is whether or not that use would be
reasonable with respect to other users. An assessment of surface water
sources in terms of the relative amount of streamflow at low-flow condi-
tions that would be required for a coal conversion plant was presented
in Section 3.2 and Tables 3.1 and 3.2. 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
reasonableness of a typical conversion plant use, another factor that
might be considered in plant siting is the amount of competing use in a
464
-------
particular 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 the other uses.
This information would be of particular importance where coal resources
are located some 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, some preliminary, unpublished data compiled by the Ohio River
Basin Commission (1977) 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 3.3.
465
-------
TABLE 3.3
ESTIMATED CONSUMPTIVE WATER USE AND SURPLUS SUPPLIES IN THE OHIO RIVER BASIN FOR 1975 AND 2000
Location
Low Flow Estimated Available Quantity Estimated Available Quantity
Mean 7 Day, 20 Yr Present With Present Future With Future
Annual(4) Except as 1975 Use at Low 2000 Use At Low
Flow Noted Use (5) Flow Conditions Use (5) Flow Conditions
(cfs) (cfs) (cfs) (cfs) (cfs) (cfs)
Allegheny R.
(Allegheny Co. Pa.) 19,500 1,000(1) 280
Monongahela R.
(Monongalia Co. W. Va.) 8,137 248 110
Ohio R.
(Jefferson Co. Ohio) 40,900 5,600 (2) 695 4
Ohio R.
(Marshall Co. W. Va.) 40,900 5,600 (2) 700 4
Muskingum (Tuscarawas)
R. (Tuscarawas Co. Ohio) 2,453 215 45
Kanawha R.
(Kanawha Co. W. Va.) 14,480 1,750 130 1
Ohio R.
(Gallia Co. Ohio) 77,600 8,600 (2) 1,010 7
Ohio R.
(Warrick Co. Ohio) 113,700 13,000 (2) 1,420 11
Green R.
(Muhlenburg Co. Ky. ) 9,201 500(1) 55
Ohio R.
(Henderson Co. l(y.) 133.900 15,400(2) 1,500 13
Wabash R.
(White Co. 111.) 11,540 610 (3) 330
NOTES: (1) Estimated from available information
720
138
,905 1
,900 1
170
,620
,590 1
,580 3
445
,900 3
280 1
350
310
,129
.306
85
240
.980
.220
60
,310
.120
650
-62
4.471
4,294
130
1.510
6,620
9,780
440
12,090
-510
(2) Ohio River Basin Commission (1977) estimates
(3) Low-flow (1 day, 50 year) from Illinois State Water Survey
(4) Mean flow from U.S.G.S. Data
(5) Estimated uses are accumulated consumptive
its tributaries, use at the named location
basin use from the ratio of drainage areas
use for the Ohio
determined from
(ORBC 1977)
Report No.
Main Stem
the total
4 (1975)
, or on
tributary
466
-------
It is apparent from these results that significant water surpluses
exist even at low-flow conditions all along the Ohio main stem both now
(1975) and in the future. In fact at least some surplus under present
use conditions exists at all sites listed. Under future (2000) condi
tions 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.
3. 5 Surface Water Quality
Water quality data on a number of chemical properties having
potentially detrimental effects on coal conversion processes were compiled
for many of the designated water supply sources. This information is
of interest to provide some indication of the type and extent of pre-
treatment facilities that must be installed at the plant sites. The
properties considered in this analysis,generally because of their ten-
dency to contribute to fouling or corrosion of the process equipment,
are the following:
Silica Si02
Calcium - Ca
Magnesium - Mg
Bicarbonate - HC03
Sulfate - S04
Sodium Na
Chloride Cl
Total Dissolved Solids - TDS
Carbonate Hardness
467
-------
Non-Carbonate Hardness
Hydrogen Ion Concentration - pH
The significance of these properties and their source or cause are
described more fully in Table 3.4,
U.S. Geological Society water quality data was obtained for
stations on many of the rivers specified as water sources for coal
conversion sites. Up to 10 years of this data, generally monthly
samples, for each water property was stored on computer files and then
processed to determine the average value and range (minimum and maximum
observed values) of each property at each location. The results of
this analysis are given in Table 3.5. The number of samples used in
these determinations and therefore the accuracy of the results in repre-
senting the actual average and expected range varied from site to site.
Several years of data were used and therefore the stated values are
most accurate for the following sources:
Tombigbee River, Alabama
Ohio River, Illinois
Muskingum River, Ohio
Allegheny River, Pennsylvania
Monongahelia River, West Virginia
Only one year of data was used for the following sources:
Illinois River, Illinois
White River, Indiana
Green River, Kentucky
Ohio River, Kentucky
Kanawha and New Rivers, W. Virginia
468
-------
TABLE 3.4
SIGNIFICANCE OF THE CHEMICAL AND PHYSICAL PROPERTIES OF WATER
CONSTITUENT OR
PHYSICAL PROPERTY
SOURCE OR CAUSE
SIGNIFICANCE
Silica (S102)
Calcium (Ca) and
Magnesium (Mg)
Sodium (Na) and
Potassium (K)
Bicarbonate (HCO-i)
and Carbonate (CO,)
Sulfate (S04)
Chloride (Cl)
Dissolved Solids
Hardness as CaCO,
Hydrogen 1on
Concentration (pH)
Dissolved from practically all
rocks and soils, usually 1n small
amounts up to about 25 ppm.
However water draining from
deposits high 1n silicate minerals
particularly feldspars often
contain up to 60 ppm.
Dissolved from practically all
rocks and soils, but especially
from limestone, dolomite, gypsum,
and gypsiferous shale.
Dissolved from practically all
rocks and soils. Found also in
sewage Industrial waste and waste
brines.
Action of carbon dioxide 1n water
on carbonate rocks and soil
minerals such as limestone and
dolomite.
Forms hard scale in pipes and boilers. Carried
over in steam of high pressure boilers to form
deposits on blades of steam turbines. Inhibits
deterioration of zeolite-type water softeners.
Dissolved from rocks and soils
containing gypsum, iron sulfides,
and other sulfur compounds.
Usually present 1n drainage from
mines and in some Industrial
wastes.
Dissolved from rocks and soils.
Present 1n sewage and found 1n
large amounts 1n waste brines and
some other Industrial wastes.
Chiefly mineral constituents
dissolved from rocks and soils.
Includes any organic matter and
some water of crystallization.
In most waters nearly all the
hardness 1s due to calcium and
magnesium. All of the metallic
cations other than the alkali
metals also cause hardness.
Adds, acid-generating salts, and
dissolved carbon dioxide lower
the pH. Carbonates, bicarbonates
hydroxides, phosphates, silicates
and borates raise the pH.
Causes most of the hardness and scale-forming
properties of water; soap consuming (see
hardness).
Moderate quantities have little effect on the
usefulness of water for most purposes. Sodium
salts may cause foaming In steam boilers.
Bicarbonate and carbonate produce alkalinity.
Bicarbonate of calcium and magnesium decompose
in steam boilers and hot water facilities to form
scale and release corrosive carbon-dioxide gas.
In combination with calcium and magnesium cause
carbonate hardness.
Sulfate 1n water containing calcium forms hard
scale 1n steam boilers. In large amounts, sulfate
in combination with other ions gives a bitter
taste to water. Federal drinking water standards
recommend that sulfate content should not exceed
250 ppm.
In large quantities increases the corroslveness
of water. Federal drinking water standards
recommend that the chloride content should not
exceed 250 ppm.
Federal drinking water standards recommend that
the dissolved solids should not exceed 500 ppm.
Waters containing more than 1,000 ppm of dissolved
solids are unsuitable for many purposes.
Hard water forms scale 1n boilers, water heaters,
and pipes. Hardness equivalent to the bicarbonate
and carbonate 1s called carbonate hardness. Any
hardness in excess of this is called noncarbonate
hardness. Waters of hardness up to 60 ppm are
considered soft; 61 to 120 ppm, moderately hard;
121 to 200 ppm, hard; more than 200 ppm, very hard.
A pH of 7.0 indicates neutrality of a solution.
Values higher than 7.0 denote increasing alkalin-
ity; values lower than 7.0 indicate increasing
acidity. pH is a measure of the activity of the
hydrogen ions. Corrosiveness of water generally
increases with decreasing pH. However, exces-
sively alkaline waters may also attack metals.
469
-------
Table 3.5
CHEMICAL CHARACTERISTICS OF THE SURFACE WATER SOURCES
(Average Concentration and Range 1n mg/1)
o
Source
Location
Al abama
Tombigbee R. at
Jackson, Ala.
1 1 1 1 noi s
11 linols R. at
Marseilles 111.
Ohio R. at
Grand Chain 111 .
Indiana
White R. at
Hazleton, Ind.
Kentucky
Green R. at
Beech Grove
-------
For these sources although the tabulated values give some indication
of levels of the various constituents to be expected the true range
of values that could occur might be quite different.
No data is reported for surface water quality from the Coosa
(Alabama), Mississippi and Kaskaskia (Illinois), or Wabash (Indiana)
Rivers. U.S.G.S. chemical quality monitoring stations apparently
have not or have only recently been installed at these locations.
The scarce quality data located in other governmental or regional
reports for these sources was not suitable for inclusion with this data
either because the properties of interest were not sampled or the
sampling was not done on a systematic basis.
471
-------
4. GROUNDWATER RESOURCES
4.1 General
Groundwater was specified as a primary supply for certain
sites located in Illinois and Ohio. In several other regions, condi-
tions appear to be favorable for the development of groundwater as an
alternative source to unreliable surface supplies or as a supplemental
source. As further described in Section 4.3, groundwater sources may
have institutional advantages in some instances even though they would
generally be more expensive to develop than surface supplies.
Situations favorable to groundwater development as supply sources
for coal conversion plants generally meet the following
conditions: expected well yields of 500 gpm or more; extensive, highly
permeable aquifers; or recharge occurring through induced infiltration
from nearby rivers. Rather extensive and costly well fields will
normally have to be developed where groundwater is considered as a primary
supply source. In order to provide the typical plant water requirement
of 4000 gpm, a field consisting of at least 8 wells would have to be
provided, even in areas producing high well yields of 500 gpm. The
spacing of wells in such a field will have to be carefully controlled
depending on the aquifer extent and permeability characteristics to
avoid impacts on other local users through drawdown of the water table.
In many areas having seasonally questionable surface water resources,
development of less extensive or lower yielding wells may be important
as a supplemental source.
472
-------
4.2 Groundwater Availability
Groundwater in the East/Central coal region states is a large
and important water resource that may have a significant role in
development of the coal resource. 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 (U.S.G.S. 1974) 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 reco-
verable or located so as to be of value in energy development, much
of it is.
Alluvium, outwash, and glaciofluvial deposits constitute the most
productive part of the region's groundwater system. Well sorted
glacial sediments redeposited by streams above the southernmost glacial
encroachment (roughly along the path of the Allegheny-Ohio Rivers),
have helped to create highly permeable aquifers in widespread parts of
the region. Alluvial deposits consisting of silt, sand, and gravel,
present in the major tributary valleys south of the Ohio River,generally
are finer grained and less permeable than the glaciofluvial deposits.
Alluvial aquifers are usually shallow and unconfined. As a result
drilling for alluvial groundwater is relatively inexpensive and simply
drilled through the unconsolidated medium of gravel and/or sand.
473
-------
In consolidated aquifers (limestone, sandstone, etc.) the
ability of water to flow through is reduced as permeability decreases.
Although high porosities may be present as in clays, the very low
permeabilities prevent movement of water down the hydraulic gradient
to a well. Therefore, even if large quantities of water are available
the yields may be low due to the low rate of replenishment of water
through the aquifer.
Therefore, in a consolidated aquifer yields exceeding 100
gpm are considered very good. Solution cracks which occur in limestones
can greatly increase permeabilities, effectively forming an underground
conduit where discharges can reach 2,500 gpm (as in, for example, certain
areas in Pennsylvania). The incidence of such yields is, however,
rare.
Figure 4.1 shows the general locations of high-yield sources of
groundwater in the region.
Primary groundwater sources and all surface sources classified
as unreliable in the assessment of surface supplies (Table 3.1) 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 ground-
water as sources of supply. The following criteria were used in
assessing the situation at each site:
474
-------
90ฐ00
oo' T~
86ฐ00'
82ฐOO'
.WISCONSIN
ILLINOIS
oo'~r
VIRC1NI*
NORTH CAROLINA
50 100
I I
\ I
20O MILES
0 50 100
20O KILOMETERS
From: Bloyd (1974)
EXPLANATION
Potential yields to individual wells
Unconsolidated aquifers, greater than 500 gpm
Unconsolidated aquifers, 100-500 gpm
fx'-.-:-X:'4 Consolidated aquifers, 100-500 gpm
Figure 4.1 High-yield Sources of
Groundwater
475
-------
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 4.1 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 (USGS, 1974) 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 follows.
476
-------
Table 4.1
Assessment of Groundwater Availability at Sites with Insufficient Surface Supplies
State
Alabama
11 1 inois
Indiana
Kentucky
County
Jefferson
Bureau
Fulton
Sal ine
Shelby
Floyd
Harlan
Muhlenberg
Pike
Presently
Designated
Source
Coosa
Groundwater
Groundwater
Sal ine
Kaskaskia
Levisa Fork
Cumberland
Green
Levisa Fork
Potential
Groundwater
Yield*
Favorable
Favorable
Favorable
Unfavorable
Possible
Unfavorable
Unfavorable
Possible
Favorable
Groundwater
Accessibil ity
On-Site
On-Site
On-Site
Near by
Distant
Distant
Distant
Near by
On-Site
Groundwater
Feasibility
Yes
Yes
Yes
No
Possi
No
No
Possi
Yes
ble
ble
Ohio
Pennsylvania
West Virginia
Tuscarawas
Somerset
Mingo
Monongalia
Preston
Tuscarawas &
Groundwater
Casselman
Tug Fork
Monongahela
Cheat
Favorable
Favorable
Favorable
Unfavorable
Favorable
*Favorable = >100 gpm and likely to approach or exceed 500 gpm
Possible = generally >100 gpm
Unfavorable = <50 gpm
On-Site
On-Site
On-Site
Distant
On-Site
Yes
Yes
Yes
No
Yes
-------
Bureau County, Illinois
The county sits on perhaps the most productive aquifer of the
state. This aquifier is composed of coarse glacial outwash material
along the Illinois River and spreads well laterally from the river
channel. Due to the consistency of the aquifer material, transmissivity
and rate of recharge are very high. Expected yields are in excess of
500 gpm (72 mgd).
Fulton County, Illinois
The squifer is of the same geologic age as that in Bureau County
(Quarternary glacial deposits); however, it is of finer consistency and
better sorted. As a result recharge rates and consequently the
available well yields are lower. Its suitability for development is,
therefore, not as great as in Bureau County.
Large yields are available in Mason County across the Illinois
River. It is conceivable that this source could be used as a supply
in conjunction with the available yields in Fulton County of more than
250 gpm.
Tuscarawas County, Ohio
The Muskingham River glacial outwash deposits form the aquifer
in this area. It has been exploited for a considerable time. Outwash
deposits, which are not directly recharged by the Muskingum and its
tributaries, exist and are potentially good high yield aquifers.
Yields of greater than 500 gpm are available in the valley train
deposits of the Muskingum and potential for further development is good.
Competing users, however, have large developments at the present time.
478
-------
Marengo County, Alabama
Marengo County aquifers are extensive and consolidated. The
structure is Cretaceous in age consisting of sands, marls, chalks
and clays. None of these form excellent aquifers with only a few
areas providing high yields. The majority range in yield from 25
to 100 gpm.
Serious drawdown has occurred in the city of Demopolis where
yields of 400 gpm are maintained for the municipal water supply.
Therefore, it is obvious that further exploitation of high yield
aquifers may cause serious damage to the county's groundwater supplies
In a number of other areas having questionable surface supplies,
groundwater many serve as a supplementary source or a temporary source
to augment surface supplies during low flow. The general situation
at these sites is as follows:
Saline County, Illinois
Conditions are unfavorable for groundwater development with
highest yields of about 20 gpm from either the unconsolidated aquifer
or from the consolidated limestone aquifers.
Shelby County, Illinois
Sandy aquifer along the Kaskaskia has predicted yields of 100
gpm but reliable long term yields may be less because the available
recharge is restricted by the limited extent of the aquifer. However,
the suitability for augmentation of low flows is favorable.
479
-------
Floyd, Harlan, and Pike Counties, Kentucky
Sediments in the Levisa Fork Basin have low yields ranging
from 10-25 gpm. The consolidated rocks of the county yield little
water (< 25 gpm) and are brackish at shallow depths. These low
yields are due in part to the incision of the area by a high density
of valleys, consequently, breaking potential aquifiers and causing
them to drain.
1 ' i ' - v , i
Somerset County, Pennsylvania
Yields as great as 1000 gpm are available in the limestone
structures of Somerset County. However, the majority of wells
yield 25-50 gpm. Due to the extreme variability of the consolidated
aquifer yields in the limestone, it is difficult to reliably comment
on its use for supplemental supplies without on-site test wells.
Mingo County, West Virginia
Within this county the best potential for groundwater sources
exists in the valley deposits of the Tug Fork. Yields approach
50 gpm but the suitability as a continuous supply to augment surface
supplies may be poor because of the restricted recharge characteristics
of the relatively limited aquifers.
Monongolia and Preston Counties, West Virginia
The Monongahela River sediments have reasonable aquifers
yielding as much as 75 gpm. Typical yields are 25 gpm for the majority
of the consolidated aquifer, however, the deep sandstone aquifer
have yields as high as 400 gpm. It is apparent that detailed surveying
is needed to assess if well densities can provide the required yields
for supplemental supplies.
480
-------
An assessment of the additional secondary sites is given in
Table 4.2. 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, develop-
ment is a possibility at the other sites, depending on actual location.
4.3 Groundwater Doctrines
The principal groundwater doctrines affecting the use of ground-
water involve the concepts of absolute ownership and that of reasonable
use. Absolute ownership (or the English Rule) 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 (or American Rule) 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 in Section 3.3. As applied to groundwater,
any reasonable use in connection with the land from which the ground-
water 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.
481
-------
Table 4.2
Assessment of Groundwater Availability
at the Secondary Sites
State
County
Present Source
Potential Ground-
water Yield*
Groundwater
Accessibility
Preliminary
Groundwater Feasibility
Alabama
Fayette
Marion
Jackson
DeKalb
Warrior
Tennessee
Tennessee
Tennessee
Favorable
Possible
Possible
Possible
On-Site
On-Site
On-Site
On-Site
Yes
Possible
Possible
Possible
Kentucky
03
KJ
Penn.
McCreary
Lee
Clearfield
Cambria
Cumberland
Kentucky
West Branch
Conemaugh
Unfavorable
Unfavorable
Possible
Possible
Distant
Distant
On-Site
On-Site
No
No
Possible
Possible
W. Va.
Randolph
Greenbrier
Tygart
Greenbrier
Possible
Possible
On-Site
On-Site
Possible
Possible
*Favorable
Possible
Unfavorable
= >100 gpm and
= generally
= < 50 gpm
likely to approach or exceed 500 gpm
00 gpm
-------
As discussed in Section 3.3 certain Eastern states are beginning
to depart from strict adherence to the common laws of water use by
considering statutory modifications to, in some way? regulate use. Of
the states included in this study, only Kentucky and Indiana have
enacted such statutes to-date. In Indiana where statutes involve only
groundwater use, the Department of Conservation has authority to restrict
withdrawals where other users would be affected. New users of more than
100 gpd are required to obtain a permit. Other states, North Carolina
for example, have moved to control groundwater use in designated problem
areas only.
Although disruption of groundwater systems by valid users is in
some instances allowable from a purely legal point of view, minimizing
impacts by use or mining operations should be an important consideration
in the siting, design, and/or operation of conversion plants. The
potential effects of mining and water withdrawal on groundwater systems
are discussed in Section 5 of this report.
4.4 Groundwater Quality
As discussed earlier in Section 3.5, data on the chemical quality
of water to be supplied to conversion plants is of interest due to the
detrimental effects certain constituents can have on the process equip-
ment. The properties of interest and the reasons for their importance
are shown in Table 3.4.
The effects of man-made pollutants or constituents on the variability
of groundwater quality is generally considerably less than for surface
waters. From location to location, however, groundwater quality can vary
483
-------
greatly due primarily to geologic differences. The influence of anhydrite
and calcareous lenses, and fractured planes of various other minerals
can alter the physical properties of groundwater significantly over
small distances. Throughout the region of interest, brackish water
(high total Dissolved Solids) exists generally within 500 feet of the
surface and closer in many instances.
The valley fill or unconsolidated alluvial aquifers are products
of the last ice age being derived mainly from outwash material off of
the retreating ice sheets. The material in the valleys along the
Ohio River and mouth of it is considerably coarser and of greater
extent than the deposits to the south. In general, the coarser deposits
are more readily recharged and give higher yields and better quality
than the fine sands and gravels of some valley fill deposits.
Consequently, the yields are greater and the quality is better on the
northern side of the Ohio River Valley.
The sedimentary rocks of the Appalachian Chain (consolidated
aquifers) contain vast quantities of potable (non brackish) water.
Yields from these aquifers rarely exceed 100 gpm and are, therefore,
of limited use for coal conversion purposes. The density of wells needed
to provide the required yields from consolidated aquifers may be
restrictive. In some cases yields as great as 2,500 gpm occur in
consolidated aquifers in the region but are not near proposed
sites for coal conversion plants. Such high yields eminate primarily
from limestone solution cracks (caves) where the entire flow of an
aquifer becomes concentrated at one point.
484
-------
The quality of consolidated aquifers is generally better than
that of unconso]idated aquifers, particularly from sandstone beds.
As a result they could become important as supplemental suppliers
during periods of low flow.
Alluvial aquifers rarely have brackish conditions. This is
primarily due to direct recharge from the valley stream or
from rainfall infiltration. The recharge contribution to alluvial
aquifers from consolidated aquifers is small compared to these sources
Because groundwater quality is so spacially variable in most
areas, the chemical properties of water from a given location are
rather unique to the well from which the sample was taken. It is
therefore meaningless to present extensive groundwater sampling data
as an indication of what conditions might be like in any particular
county in the study area. The groundwater quality data in Table 4.3
is presented simply to illustrate the conditions at a few selected
sites.
485
-------
Table 4.3
CHEMICAL CHARACTERISTICS OF GROUNDWATER SOURCES
(Source: U.S.G.S. Well Records)
Aquifer Location and Type
Property'*'
Fe
F
Si02
Ca
Ma
Na
HC02
so4
Cl
T.D.S.
Hardness
co3
Hardness
Non C03
PH
Muhlenburg, Tuscarawas,
Marengo, Al . Jefferson, Al . Bureau, 111. Ky. Oh.
Consolidated Consolidated Alluvial Alluvial Alluvial
1.1 < 0.3 3.3
0.4
3.7-22
2.4 - - 41-152 75
0.4 - - 5.8-50 20
3.8-88
489 - - 104-639 217
< 17 0.2 8-155
58 - 1.6 2.1-84 6.7
120-210 360 174-691 363-
8 - 263 126-564 275
0-209
8-3 - - 6.4-8.0 7.5
Concentration in mg/1.
486
-------
5. 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 potential impacts due to either action generally fall into
three categories: impacts on the land, impacts on surface water quality,
and impacts on groundwater systems. In many instances these effects
can be minimized or avoided through controlled siting, design and
operation of the facilities. Some impacts, at least temporary, can
be expected simply due to the large scale of the operation.
5.1 Impacts on the Land
Potential impacts on the land are the result of the massive earth-
moving operation involve in coal mining, particularly strip mining.
The problems of erosion resulting from land clearing and grading acti-
vities may be effectively handled by measures taken to control surface
drainage on the site. A major concern about strip mining has been the
scaring of the land that has often resulted in the past. Modern
mining techniques and tough new Federal and State reclamation standards
should reduce this problem.
5.2 Water Quality Impacts
A water quality problem associated with the erosion effects mentioned
above, is that of sediment loadings and siltation of stream channels.
487
-------
Effective control of these problems depends on proper handling of
mine spoils and overburden to prevent surface drainage from flowing
down steep slopes over loose exposed earth.
Synthetic fuel plants may produce a number of waste residues
that could be detrimental to water quality if discharged into
surface waters. Planning for the safe disposal of all waste residues
is an important consideration of plant development and design.
In many instances, where the plants consume all water taken in and no
return flow possibly contaning residues is returned to the receiving
waters, the potential for environmental degredation is minimized.
In certain coal mining areas, particularly the northern Appalachian
region of West Virginia and eastern Pennsylvania, acid mine drainage is
a significant problem. Acid water conditions are most likely to occur
where a combination of three factors exists:(1) extensive surface or
subsurface mining in strata which contain iron sulfide minerals, (2)
abundant rainfall and runoff on steep slopes; and (3) low natural
alkalinity in natural watersheds. The results of acid water conditions
may be corrosive damage to concrete and metals, increased treatment
costs for municipal and industrial supplies, altered ecological systems,
and reduced recreational values. Although no single procedure has been
developed to effectively deal with the acid mine drainage problem, a
variety of corrective measures are being promoted by State and Federal
agencies. These measures generally fall into the following categories
(USGS, 1965):
488
-------
1) minimizing the contact between water and acid-
producing materials,
2) regulating the flow of mine wastewater to nearby
streams,
3) neutralizing acid wastewater with Alkaline
compounds, and
4) protecting acid-producing materials from weathering
and erosion at the end of mining operations.
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.
5.3 Impacts on Groundwater Systems
A 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 way be created which can significantly lower the hydraulic
gradient (i.e., water table) of the aquifer in the vicinity of the
mine.
489
-------
Typically unconsolidated deposits lie on the surface and extend
to a few hundred feet (at most) below the surface. Potentially
unconsol idated aquifers offer large yields (in excess of 500 gpm) in
Bureau County, Illinois and along the Muskingum River in Tuscarawas
County, Ohio. In Tuscarawas County the aquifer would be unaffected
as the coal is located at higher elevations than the river recharge area.
In Bureau County, however, the present potential aquifer lies above
the coal and would thus be regarded as "overburden" and consequently
removed. The local effects in Bureau County could be, for example,
significant local lowering of the water table. Because this problem
is very localized and dependent on the underlying aquifer structure,
the situation can only be accurately evaluated on a site by site basis
at a much smaller scale than 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 transmissibi1ity rates, they to 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 ground-
water supply sites and several other sites where groundwater looks
promising as a supplemental source. These assessments are presented in
Tables 5.1 and 5.2.
490
-------
TABLE 5.1
ASSESSMENT OF POTENTIAL IMPACTS AT DESIGNATED GROUNDWATER SITES
Site
Location
Mining
Type
Aquifers Disturbed
Problems
Marengo, Al. Surface
Bureau, 111.
Surface/
Underground
Fulton, 111. Surface
Tuscarawas,
Ohio
Underground
Sandstone above coal. Our source is cretaceous
sandstone aquifers and may be unaffected.
Lignite (paleocene) overlies main aquifers --
no problem for supply to coal conversion plants.
Unconsolidated glacial outwash aquifers
considered as source of water. Significant
disturbance if a strip mine, less of a problem
if an underground mine.
Structure very similar to Bureau Company. Aqui-
fer disturbance could be greater here as it is
a proposed surface mining area,
Deep mining will have little affect on alluvial
aquifers along Muskingum River. Aquifers above
coal will be disturbed.
Acid mine drainage; lowering of local
well levels; possible aquifer destruc-
tion.
Large volumes of drainage from over-
lying aquifer. Aquifer material would
be overburden to a strip mine. Subse-
quent high discharges into mine would
be an operational problem. Underground
mine preferable here if possible.
Large volumes of drainage from over-
lying aquifer. Aquifer material would
be overburden to a strip mine. Subse-
quent high discharges into mine would
be an operational problem. Underground
mine preferable here if possible.
Mine drainage from sandstone aquifers
above coal. Little affect as few users
of this water.
-------
TABLE 5.2
ASSESSMENT OF POTENTIAL IMPACTS AT SUPPLEMENTAL GROUNDWATER SITES
S i te
Location
Sal ine,
Shelby,
111.
111.
Mining
Type
Surface
Underground
Only
High
Aqui
unconsol idated
disturbance.
Unconsolidated aqui
fers Di
sturbed
aquifer in area. Low
fer of
Kaskaskia River
Problems
yields.
Basin
Definite
users.
No signi
probl
f icant
em to
probl
present
ems.
Floyd & Harlan, Underground
Ky.
Pike, Ky.
Somerset, Pa.
Surface
Underground
unaffected, aquifers in coal series less than
20 gpm. No problem
All aquifers are brackish at shallow depth.
Impact on present aquifers small as they are near
surface. Very low yield aquifers only provide
domestic water.
Likely removal and consequent drainage of shallow
sandstone. Aquifers of low yield.
Good aquifers in sandstone, are below coals.
Aquifers above coal subject to drainage.
Mingo, W. Virginia Surface Valley deposits will be unaffected.
Monongalia &
Preston, Ky.
Underground Main coals at top of Pennsylvanian. High yield
aquifers below coals. Domestic aquifers of
Permian (above coal) will be affected.
No significant problems.
Domestic users heavily affected
since deeper sypplies would be
brackish.
Alternative domestic supplies
might have to be provided for
aquifers disturbed.
No significant problems.
Alternative domestic supplies
might have to be provided for
aquifers disturbed.
-------
6. SITE SPECIFIC SUMMARY
This section presents a general summary of the water resources
situation at the proposed coal conversion plant sites in each state.
Separate tables for each state list first 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 plant requirements
with low streamflow conditions and other considerations as described
fully in the earlier text.
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 ground-
water may be considered as a supplemental or conjunctive supply in
many instances, groundwater availability in the vicinity of each site
is rated based on the general aquifer 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
493
-------
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 con-
siderations that may enter into the final selection of the water
supply make-up 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 environ-
mental impacts based on the factors discussed in Section 5 and the
general area of the site. It must be emphasized that actual environ-
mental effects associated with coal mining and conversion are very
site and design/operation dependent, and can not be reliably evaluated
without specific site and design data.
494
-------
Table 6.1
WATER RESOURCES SUMMARY FOR ALABAMA
Location
Primary Sites
Jefferson
Marengo
Secondary Sites
Fayette
S Marion
Jackson
DeKalb
Designated Adequacy of Alternate Adequacy of
Source Source Source Alternate
Coosa R.
Tombigbee R.
Warrior R.
Tennessee R.
Tennessee R.
Tennessee R.
Good
Fair Groundwater Fair
Fair Groundwater Fair
Good
Good
Good
Groundwater Recommended
Availability Supply
Fair Coosa
Fair Tombigbee & G.W.
Augment
Fair Warrior & G.W.
Fair Tennessee
Fair Tennessee
Fair Tennessee
Environmental
Impact
Moderate
Significant
Moderate
Minimal
Minimal
Minimal
-------
Table 6.2
WATER RESOURCES SUMMARY FOR ILLINOIS
Location
Primary Sites
Bureau
Ful ton
St. Clair
Sal ine
Shelby
White
Secondary Sites
McLean
Mercer
Designated
Source
Illinois R.
Groundwater
Mississippi
River
Saline R.
Kaskaskia R.
Wabash R.
Illinois R.
Mississippi
R.
Adequacy of
Source
Fair
Good
Very Good
Very Poor
Poor
Good
Fair
Very Good
Alternate
Source
Groundwater
-
Groundwater
Ohio
Lake
Shelbyville
-
Groundwater
Groundwater
Adequacy of
Alternate
Very Good
-
Very Good
Good
Fair
-
Fair
Very Good
Groundwater
Availabil i ty
Very Good
Good
Very Good
Very Poor
Fair
Fair
Fair
Very Good
Recommended
Supply
Groundwater
Groundwater
Mississippi R.
Ohio R.
Kaskaskia & G.W.
Wabash
Illinois & G.W.
Mississippi
Environmental
Impact
Moderate
Moderate
Minimal
Significant
Moderate
Moderate
Moderate
Minimal
-------
Table 6,3
WATER RESOURCES SUMMARY FOR INDIANA
Location
Primary Sites
Gibson
Sul 1ivan
.ฃ
VD
Designated
Source
White R.
Adequacy of Alternate Adequacy of Groundwater Recommended
Source Source Alternate Availability Supply
Good
Wabash R. Good
Groundwater Fair
Groundwater Good
Fair
Good
White & G.W.
Wabash R.
Vigo Wabash R. Good Groundwater Good Good Wabash R.
Warrick Ohio R. Very Good Groundwater Very Good Very Good Ohio R.
Environmental
Impact
Moderate
Moderate
Moderate
Minimal
-------
Table 6.4
WATER RESOURCES SUMMARY FOR KENTUCKY
Location
Primary Sites
Floyd
Marian
Henderson
Muhlenburg
Pike
Secondary Sites
CO
Hopki ns
Lawrence
Lee
McCreary
Designated
Source
Levisa Fork
Cumberland R.
Ohio R.
Green R.
Levisa Fork
Adequacy of
Source
Very Poor
Very Poor
Very Good
Fair
Very Poor
Alternate Adequacy of
Source Alternate
Unknown
Surface
-
Groundwater Fair
Unknown
Groundwater
Availabil ity
Very Poor
Very Poor
Good
Fair
Very Poor
Recommended
Supply
Unknown
Unknown
Ohio R.
Green & G.W.
Unknown
Environmental
Impact
Significant
Significant
Minimal
Moderate
Significant
Green R. Fair
Big Sandry R. Fair
Kentucky R. Poor
Cumberland R. Poor
Groundwater Fair
Groundwater Fair
Unknown
L. Cumberland Good
Fair
Fair
Poor
Poor
Green & G.W.
Big Sandy & G.W. Moderate
Unknown
Unknown
-------
Table 6.5
WATER RESOURCES SUMMARY FOR OHIO
Location
Primary Sites
Galia
Jefferson
Tuscarawas
Designated Adequacy of
Source Source
Ohio R. Very Good
Ohio R. Very Good
Tuscarawas Fair
Alternate Adequacy of Groundwater
Source Alternate Availability
Very Good
Very Good
Groundwater Very Good Very Good
Recommended Environmental
Supply Impact
Ohio R. Minimal
Ohio R. Minimal
Groundwater Moderate
Secondary Sites
Morgan
Muskingum
Good
Groundwater Very Good Very Good Muskingum & G.W. Moderate
-------
in
O
O
Table 6,6
WATER RESOURCES SUMMARY FOR PENNSYLVANIA
Location
Primary Sites
Al legheny
Luzerne
Schuylkill
Somerset
Secondary Sites
Venango
Clearfield
Cambria
Designated Adequacy of Alternate Adequacy of Groundwater Recommended
Source Source Source Alternate Availability Supply
Allegheny R.
Susquehanna R.
Susquehanna R.
Casselman R.
Allegheny R.
West Branch
Conenaugh R.
Good
Good
Good
Poor Quemahoning
Res.
Good Unknown
Fair Unknown
Poor Unknown
Good
Good
Good
Good
(Highly
Fair
Fair
Poor
Allegheny
Susquehanna
Susquehanna
Casselman & G.W.
Variable)
Allegheny
Unknown
Unknown
Environmental
Impact
Moderate
Moderate
Moderate
Significant
Moderate
-
-
-------
Preston
Table 6.7
WATER RESOURCES SUMMARY FOR WEST VIRGINIA
Location
Primary Sites
Fayette
Kanawha
Marshal 1
Mi ngo
Monongal ia
Designated
Source
New R.
Kanawha R.
Ohio R.
Tug Fork
Monongahela
Adequacy of
Source
Good
Good
Very Good
Poor
R. Fair
Alternate
Source
-
-
Groundwater
Groundwater
Adequacy of
Alternate
-
-
Fair
Fair-Good
Groundwater
Avail abi 1 ity
Poor
Fair
Good
Fair
Fair-Good
Recommended
Supply
New
Kanawha
Ohio
Tug & G.W.
Monongahela &
Environemtnal
Impact
Moderate
Moderate
Minimal
Moderate
Moderate
Cheat R.
Poor
Groundwater
Poor
Secondary Sites
Randolph Tygart R. Poor Unknown
Greenbrier Greenbrier R. Fair-Poor Unknown
Poor
Very Poor
Very Poor
Groundwater
Unknown
Unknown
Unknown
Significant
-------
REFERENCES AND DATA SOURCES
References
Ausness, R., Legal Institutions for the Allocation of Water and their
Impact on Coal Conversion Operations In Kentucky., Research Report No.
95, University of Kentucky Water Resources Research Institute, 1976.
Bloyd, R.M., Jr., Summary Appraisals of the Nation's Ground-Water
Resources-Ohio Region, U.S.G.S., Professional Paper 813-A, 1974.
Cox, W.E., and Walker, W.R., Energy Self-sufficiency: Are Eastern
Water Rights a Serious Constraint?, 1975.
Illinois State Water Survey, Coal and Water Resources for Coal Conversion
in Illinois, Cooperative Resources Report, No. 4, 1975.
Ohio River Basin Commission, Preliminary Unpublished Data on - Ohio
River Instream Flows and Consumptive Water Use, 1977.
Schneider, W.J., et. al., Water Resources of the Appalachian Region,
Pennsylvania to Alabama, USGS, HA 198, 1965.
U.S.G.S., Proposed Surface Data Programs in (each state), 1970.
Data Sources
Geological Survey of Alabama, Water Availability of Jefferson County,
Alabama, 1976.
Geological Survey of Alabama, Newton J.G., et. al., Geology and Ground-
Water Resources of Marengo County, Alabama, County Report 5, 1961.
Carlston, C.W., Groundwater Resources of Monongalia County, West Virginia,
USGS, Bull. 15, 1958.
Doll, W.L., Water Resources of Kanawha County, West Virginia, USGS,
Bull. 20, 1960.
Hyman, D.J., and Pettijohn, R.A., Wabash River Basin Comprehensive Study.
1971.
Maxwell, B.W. and Devaul , R.W., Reconnaissance of Groundwater Resources
in the Western Coal Field Region, Kentucky, USGS, Water Supply Paper
1599, 1962.
502
-------
McGuinness, C.L., The Role of Ground Water In the National Water
Situation, USGS, Water Supply Paper 1800, 1963.
Ohio Department of Natural Resources, Low Flow Frequencies and Storage
Requirements for Selected Ohio Streams, Bull 37, 1963; Bulletin 40,
1965.
Price, W.E., et. al. , Reconnaissance of Ground-Water Resources in the
Eastern Coal Field Region, Kentucky. U.S.G.S., Water Supply Paper 1607,
1962.
Resource Analysis, Inc., Hydrologic Analysis of Low-Flow Conditions for
Water Quality Management in the Kanawha River Basin, 1976.
U.S.G.S., Availability of Groundwater in McLean and Muhlenburg Counties,
Kentucky, 1962.
U.S.G.S., Availability of Groundwater in Floyd, Harlan, Pike (and others]
Counties, Kentucky. HA-36, 1962.
LI.S.G.S. , Water Resource Investigations (each state) Maps.
U.S.G.S., Water Resources Data for (each state), Water Year 1975.
Ward, P.E. and Wilmouth, B.M., Ground-Water Hydrology of the Honongahela
River Basin in West Virginia, U.S.G.S., River Bull. 1, 1968.
503
-------
APPENDIX 14
WATER AVAILABILITY AND DEMAND IN WESTERN REGION
Resource Analysis, Inc., under subcontract to Water Purification Assoc-
iates, prepared a general assessment of the water resources data in the major
coal and oil shale bearing regions of the United States. Water resources data
was collected and used as a basis for determining the availability of surface
and groundwater resources at specific coal and oil shale conversion plant
sites in the Eastern and Central coal bearing regions and the Western coal and
oil shale bearing regions. The draft report on the Western region that was
submitted as part of their study is included in its entirety in this Appendix.
504
-------
Resource Analysis, Inc.
235 WYMAN STREET
WALTHAM, MASSACHUSETTS02154
617-890-1201
WATER SUPPLY DATA FOR THE
WESTERN COAL AND OIL SHALE REGION
FOR
AN ASSESSMENT OF WESTERN REGIONAL WATER SUPPLY
AND DEMAND REQUIREMENTS FOR SYNTHETIC FUEL PRODUCTION
Prepared under subcontract to
WATER PURIFICATION ASSOCIATES
238 Main Street
Cambridge, Massachusetts 02142
August, 1978
505
-------
TABLE OF CONTENTS
1. INTRODUCTION 509
1.1 Study Objectives
1.2 Study Region and Specific Sites - . . bl1
1.3 Scope of Studies 511
2. SUMMARY OF RESULTS AND CONCLUSIONS 516
3. WATER RESOURCES OF THE REGION 520
3.1 Climate and Physiography 520
3.2 Surface Water Resources 524
3.3 Groundwater Resources 538
4. WATER USE CONSTRAINTS 543
4.1 Codes of Water Law 543
4.2 Administrative Procedures 546
4.3 Interstate Compacts 551
4.4 Federal Water Policy 561
5. COMPETING WATER DEMANDS 563
5.1 General 563
5.2 Present Water Use 570
5.3 Demand Variability 575
5.4 Potential Demand Changes ..... 577
5.5 Future Demand Scenarios , 580
6. WATER SUPPLY AVAILABILITY FOR ENERGY DEVELOPMENT ... 584
6.1 Regional Water Availability 584
6.2 Energy Development Scenarios 588
6.3 Alternative Water Supply Sources 593
6.4 Conclusions on Water Supply Availability 603
7. REFERENCES AND DATA SOURCES 605
APPENDIX A SUMMARY OF STATE WATER CODES 607
506
-------
LIST OF FIGURES
Figure No. Title Page
1.1 Specific Site Locations . . . . .513
3.1 Average Annual Precipitation ........... 522
3.2 Average Annual Lake Evaporation 523
3.3 Sub-Basin Boundaries - Upper Missouri Basin .... 525
3.4 Annual Runoff Characteristics -
Upper Missouri Basin ..... 527
3.5 Sub-Basin Boundaries - Upper Colorado Basin .... 532
3.6 Annual Runoff Characteristics -
Upper Colorado Basin ............... 534
3.7 Regional Groundwater Supply Availability ..... 539
507
-------
LIST OF TABLES
Table No. Title Page
1.1 List of Specific Study Sites 512
3.1 Annual Water Yield - Upper Missouri Basin .... 528
3.2 Annual Water Yield - Upper Colorado Basin .... 535
5.1 Present Water Use - Upper Missouri Basin .... 572
5.2 Present Water Use - Upper Colorado Basin .... 574
5.3 Projected Future Depletions - Upper Missouri
Basin 581
5.4 Projected Future Depletions - Upper Colorado
Basin 583
6.1 Projected Future Water Availability - Upper
Missouri Basin 585
6.2 Projected Future Water Availability - Upper
Colorado Basin 586
6.3 Energy Water Requirement Scenarios - Upper
Missouri Basin 589
6.4 Energy Water Requirement Scenarios - Upper
Colorado Basin 590
6.5 Summary of Energy Water Requirements 592
6.6 Summary of Water Supply Alternatives - Upper
Missouri Basin 595
6.7 Summary of Water Supply Alternatives - Upper
Colorado Basin 596
508
-------
1. INTRODUCTION
1.1 Study Objectives
This draft report presents the results of an evaluation
of water supply availability for synthetic fuel production in the easily
mined coal and oil shale regions of the Western United States. This
study is being performed under subcontract to Water Purification
Associates, Cambridge, Massachusetts, as a part of an investigation
entitled, "An Assessment of Western Regional Water Supply and Demand
Requirements for Synthetic Fuel Production" for the U.S. Environmental
Protection Agency .
The need for such an assessment exists because of the limited
water supplies that are available throughout much of the area in
which the vast coal and oil shale reserves are located. An adequate
and dependable water supply is essential to the siting and operation
of the synthetic fuel production processes under study. Significant
quantities of water are consumed as a raw material on a continuous
basis in the liquefaction and the gasification processes of converting
the raw material into more easily used forms. Water may also be
required for cooling, land reclamation, and a variety of ancilliary
uses. Large quantities of water are also required where slurry
pipelines are used to transport coal from the source to the actual
conversion site.
Prior studies of the water situation in the West have generally
indicated that either on a regional basis there is enough water to
509
-------
meet the projected needs, or that on a specific local basis there
exists over-commitments and shortages. The fact is that although
surface and groundwater supplies vary tremendously with location and
complex regulations may govern the use of water, significant water
sources exist within reasonable distances to most coal reserves.
The overall objectives of the water resources portion of this
study are therefore to identify reliable surface and/or groundwater
supplies that would be available or could be made available for
future energy development at each site under study. Potential water
supply sources for each site are evaluated on a site specific basis
in terms of the total available water supply, the needs and rights
of other competing water users, and the quality of the alternative
water supplies. This report presents some of the water availability
data that can serve as a basis for determining the relative feasibility
of certain specific sites that were selected for study.
510
-------
1.2 Study Region and Specific Sites
The specific sites selected for detailed feasibility analysis
with regard to water availability and requirements are located in
the six western states having the most readily accessible coal and
oil shale deposits.
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 1.1
presents a list of 32 specific site locations that were selected
for study based on their proximity to readily developable energy
reserves. The locations of these sites with respect to the major
energy reserves and the primary water resources characteristics are
shown in Figure 1.1.
1.3 Scope of Studies
The approach taken in this study was to first conduct a review
of existing literature on the water situation in the West to develop
a thorough qualitative understanding of the water resources and
hydrology of the regions of interest; regulations effecting the
allocation of water among competing users; present water use; and
projections of future needs for existing users and energy development
During the course of this review these issues were discussed at
length with numerous local, state, and federal planners and officials
511
-------
Table 1.1
PLANT SITE LOCATIONS IN THE WESTERN STUDY REGION
State
Mine
Deposit
Hydrologic
Sub-Region
UPPER MISSOURI RIVER BASIN
Wyoming
Montana
North Dakota
UPPER COLORADO
Wyoming
Colorado
Utah
New Mexico
Gillette
Spotted Horse
Belle Ayr
Antelope Creek
Lake de Smet-Banner
Hannah Coal Field
Decker
Otter Creek
Pumpkin Creek
Moorhead
Foster Creek
U.S. Steel-Chupp
Coal ridge
Colstrip
Slope
Dickenson
Bently
Seranton
Mil 1 iston
Knife River
Underwood
Center
RIVER BASIN
Kemmerer
Jim Bridger
Rainbow #8
Tract W-9/W-b
Tract C-a/C-b
Colony Development
Tract U-a/U-b
El Paso
Wesco
Gallup
Campbel 1
Campbel 1
Campbel 1
Converse
Johnson
Carbon
Big Horn
Powder River
Powder River
Powder River
Powder River
Dawson
Sheridan
Rosebud
Slope
Stark
Hettinger
Bowman
Will iams
Mercer
McLean
01 i ver
Lincol n
Sweetwater
Sweetwater
Sweetwater
Rio Blanco
Garfield
Unitah
San Juan
San Juan
McKinl ey
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Subbituminous
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Subbituminous
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Lignite
Bi tuminous
Subbituminous
Bituminous
Oil Shale
Oil Shale
Oil Shale
Oil Shale
Subbituminous
Subbi tuminous
Subbi tuminous
Belle Fourche-Cheyenne
Powder
Belle Fourche-Cheyenne
Belle Fourche-Cheyenne
Powder
North Platte
Tongue-Rosebud
Tongue-Rosebud
Tongue-Rosebud
Powder
Tongue-Rosebud
Missouri Mainstem
Missouri Mainstem
Tongue-Rosebud
Heart-Cannonbal 1
Heart-Cannonbal 1
Heart-Cannonbal 1
Heart-Cannonbal 1
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
512
-------
NORTH DAKOTA,
dL '
MONTANA
DECKER/ WOO"HHEAD
Cฃ V ml asPOTTEQ HORSE
>, I LAKE DE SMET
BANNER-/, / -
HEALY <,y/OL. H BELLE AYR
'
RIVER BASIN
HANNAH COAL FIELD
JIM BRIDGER
TRACT W-a/W\ WYOMING
COLORADO
TRACT U-a/U-b V
ฎ TRACT Cpa/C-^ .-
LONY DEVELOPMENT
^/l.
UPPER COLORADO'^x.
RIVER BASIN
WESCO
JEL PAS^O.
GALTL'P
NEW MEXICO
FIGURE
SPECIFIC SITE LOCATIONS
513
-------
The information gained from this continuing review process
formed the basis for a quantitative assessment to establish the
areas where water availability and energy reserve deposit locations
are most conducive to conversion plan siting. A summary of the
results of these findings are given in Section 2 of this report.
The data leading to these conclusions is then presented in Sections
3 through 6.
Section 3 discusses the overall water supply situation in the
study area in terms of the total quantities of surface and groundwater
available to all users. The constraints of how these basic supplies
may be used are considered in Section 4. In a region where water
scarcity is often a limiting growth factor, a very explicit set of
priorities has evolved over the years to regulate how and by whom
the water can be used. Section 5 discusses the present water use
situation and the factors that may alter these uses or otherwise
effect water demands in the future.
This information and data is all brought together in Section 6
to estimate the levels of water availability for future energy
development at the sites in question. This is accomplished by
comparing the basic water yields on a sub-regional basis with present
and projected future demands exclusive of the desired water needs
for synthetic fuel production. This indicates the extent if any
to which energy development can occur at various locations without
further water resources development projects or disruption of the local
way of life due to transfers of water rights to energy development
use from other sectors of demand. Based on several scenarios of
future energy development published by different sources, alternative
514
-------
methods of meeting the water supply needs for energy may be identified.
Finally, some conclusions can be made on a site specific basis as to
the relative costs and socio-economic impacts associated with supplying
various levels of water for energy needs at different sites.
515
-------
2. SUMMARY OF RESULTS AND CONCLUSIONS
This report presents the results of investigations to establish
water availability for synthetic fuel production in the major hydro-
logic sub-regions of the Western U.S. which have significant recoverable
energy reserves. Associated with this use in the same general areas
are projections of significant increases in conventional thermal
power generation. Water requirements and water availability for this
total future energy development need is therefore considered in this
report for each of the study sub-regions.
In the West the adequacy of a water supply can be evaluated on
the basis of two factors - the total water supply produced, and the
extent to which the water is used (or committed to use through a prior
appropriation). On a sub-regional basis, total average annual water
yields often greatly exceeds actual use. In many cases, however,
legally recognized rights to use water (in many cases the right granted
is not fully utilized) exceed the available supplies during low flow
periods. Supplying water for future energy use in these many of these
cases will require the 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.
516
-------
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.
4. Development of the region's extensive fresh and brackish
groundwater resources.
The results and recommendations of these investigations are
discussed briefly below for each of the major sub-regions in terms
of three levels (low, most likely, and high) of energy development
scenarios.
Powder River Basin. A low level energy demand of 40,000 AF/yr
could be met locally through either the purchase of existing agricul-
tural rights or the development of one of several proposed storage
reservoirs. Higher energy demands of up to 230,000 AF/yr would best
be met by a comprehensive transbasin diversion plan from the Bighorn
or Yellowstone Rivers.
Tongue-Rosebud Basins. High energy demands in relation to the
available supplies indicate that all of the future scenarios can best
be supplied by diversions from the Yellowstone.
Yellowstone and Missouri River Mainstems. Future energy develop-
ment sites in the mainstem sub-regions of the Northern Plains can
easily be met by the abundant supplies available from the mainstem
rivers and reservoirs.
517
-------
Belle Fourche/Cheyenne. The low energy demand scenario of
20,000 AF/yr can be met locally by a program of conjunctive surface
and groundwater development. High level demands of up to 50,000
AF/yr would be difficult to meet without comprehensive program of
agricultural right aquisitions and/or transbasin diversions.
Institutional constraints presently favor a diversion from the Green
River basin via the Platte River.
North Platte Basin. Small energy demands relative to the
overall supply situation are projected for the North Platte basin,
although the supply is already fully allocated, primarily for agri-
cultural uses. Development of additional surfaces supplies within
the basin is difficult due to institutional constraints. The modest
energy demand requirements can be met in any of the following three
ways:
1. Purchase of existing agricultural rights.
2. Development of the extensive favorable groundwater
reserves.
3. Importation from the Green River basin.
Heart/Cannonball Basins. The low level energy demand scenarios
of 10,000 AF/yr can be satisfied locally by developing several proposed
storage reservoirs. Higher demand levels can best be met by multi-
purpose diversions from the Missouri mainstem reservoirs.
518
-------
Upper Green Basin. Little development in the Upper Green River
basin leaves much of Wyoming's allotment under the Upper Colorado
Compact unused and available for future energy development. The
existing storage capacity of Fontenelle and Flaming Gorge reservoirs
is sufficient to supply all projected energy development scenarios.
Lower Green. Extensive developable oil shale deposits in the
Uintah and Piceance basins could lead to very significant water re-
quirements for synthetic fuel production in this region. The Uintah
portion of this requirement can readily be satisfied from the Green
River by Utah's Colorado River opportionment. Developments in the
Piceance Creek basin can best be supplied from the White River which
presently has adequate supplies in relation to development.
Upper Colorado Mainstem. Abundant flows from the headwater of
the Colorado River are sufficient to supply the water requirements
projected for oil shale developments in the western Colorado portion
of the sub-basin. At some locations the purchase of existing water
rights may be desirable to achieve the necessary dependability. Rapidly
increasing water demand in this region may alter this situation in the
not too distant future.
San Juan Basin. Major supplies from Navajo Reservoir which have
been allotted for industrial purposes could used low and moderate energy
development scenarios. The high development scenarios would require
the transfer of Indian water allocations to industrial uses and/or
extensive local groundwater development.
519
-------
3. WATER RESOURCES OF THE REGION
3.1 Climate and Physiography
The water resources aspects of this study may be conveniently
separated for consideration into the two major watershed regions
shown previously in Figure 1.1. The climate of these regions
is somewhat different due to differences in longitude and orientation
with respect to the mountains of the Continental Divide.
The Upper Missouri River Basin, on the eastern slopes of the
Rocky Mountains, has two major sub-regions with respect to climate.
The mountanous 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 12 to 24 inches. Throughout the basin most of the
precipitation occurs as snowfall during the winter as the 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 evaporation rates range from about 28 inches at the
higher elevations to about 44 inches on the plains (NOAA, 1977)
520
-------
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 western portion of the basin does not benefit
from the orographic precipitation caused by the Rockies, the seasonal
distribution 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 elevations in portions of north eastern
Utah. Most of the annual surface runoff results from melting mountain
snow-packs in the spring and early summer 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, (NOAA, 1977).
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. The variation of average annual precipitation in both
study regions is shown in Figure 3.1. 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. Figure 3.2 .shows the geographic
variation of lake evaporation over the study area.
521
-------
I"' UPPER MISSOURI
RIVER BASK
UPPER COLORADO
RIVER BASIN
Figure 3.1 Average Annual Precipitation
(Contours of Precipitation in
inches)
522
-------
34 32 30 28 26
UPPER COLORADO
RIVER BASIN
523
Figure 3.2 Average Annual Lake Evaporation
(Contours of Evaporation in inches'
-------
3.2 Surface Water Resources
Upper Missouri River Basin
The Upper Missouri River Basin may be divided into several
hydrologic sub-regions of interest with respect to water availability
for energy development. As shown on Figure 3.3, these study regions
may be identified as follows:
1. Upper Missouri River Mainstem (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)
This section discusses these sub-regions with respect to the
total surface water resources generated with the regions that is
available to all users. Subsequent sections discuss the nature of
the groundwater resources and how the total supply is distributed
among the competing demands.
Most of the annual runoff produced in the Upper Missouri Basin
originates in the mountainous headwaters of the Yellowstone and Missouri
sub-regions 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 basin,
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
524
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LA
to
MONTANA
NORTH DAKOTA
UPPER MISSOURI
RIVER MAINS
\ HEART-CANNON
1 v QAI i BASINS (
-J
I
/TONGUE-
/ROSEBUD
YELLOWSTONE RiyfeR /BASINS ^
JIAINSTEM ( /
/ BELLE
FOURCHE=
WYOMING
! CHEYENNE BASINS SOUTH DAKOTA
FIGURE 3.3 SUB-
BOUNDRIES- UPP
MISSOURI BASIN
-------
border. At their confluence the Yellowstone yields an annual flow
of about 9.5 million acre-feet/year which is 22 percent more than the average
flow than the Missouri, although it drains 14 percent less area
(Montana DNRC, 1976). 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 general
geographical variability of water yield within the basin is shown
in Figure 3.4. The total water yields on a sub-regional basis are
shown in Table 3.1.
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 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 input. 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 for more water availability for irrigation during the growing season
526
-------
0.25
0.5
Source: USGS, 1974
\
Figure 3.4 Annual Runoff Characteristics - Upper Missouri
River Basin (Contours of Runoff in inches)
-------
Table 3.1
AVERAGE ANNUAL WATER YIELD - UPPER MISSOURI BASIN
Sub-Region
Tongue-Rosebud
Powder
Drainage
Area
(sg. nil)
6,660
13,420
Average
Water Yield
in Sub-Region1
(AF/year)
467,000
501,900
Average
Area
Yield
(AF/year/sq. mi)
70
37
Yellowstone Mainstem
Belle Fourche-Cheyenne
(Wyoming Only)
50,040
11,000
10,488,100
182,400
210
17
Heart-Cannonbal 1
Upper Missouri Mainstem
(At Oahe Dam)
7,620
185,840
337,500
23,625,000
44
127
North Platte
(Colorado & Wyoming Only)
26,660
1,223,100
46
i
Sources: Wyoming State Water Plan, 1972.
Critical Water Problems Facing the Eleven Western States, 1975
U.S. Geological Survey, 1964
528
-------
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 13,700,000 AF
South Dakota
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.
The quality of surface waters in the Upper Missouri River Basin
may be categorized as being from good to excellent and suitable for
most uses. In general, the highest quality water is found at the
headwaters of the streams near the mountain divides. As the streams
progress downstream, the quality generally deteriorates somewhat
due to a variety of natural processes such as erosion and leaching,
and man-made influences such as agricultural practices and waste
discharges. Throughout the region except in a few localized areas
529
-------
the quality is satisfactory for most irrigation, stock watering,
recreation, fish and wildlife, and municipal and industrial purposes.
Water quality data for the streams in this region are generally
analyzed to establish the physical characteristics such as pH,
temperature, color, etc. and the chemical characteristics such as
salinity, alkalinity, trace elements, etc., of the water. This
data is available at selected locations and for selected parameters
from the U.S. Geological Survey, the Environmental Protection Agency,
and various state agencies. Unfortunately, the present distribution
of measuring stations is not sufficient to adequately establish the
current water quality situation in all areas.
One of the few water quality parameters for which substantial
amounts of data has been taken for a number of years is total dissolved
solids (IDS). This has long been used as a measure of water salinity
which is a parameter that is important in the use of water for irri-
gation. Another parameter that is of particular significance in the
region is suspended sediment levels. Although TDS concentrations
are lowest during the high flow periods of the year when dilution
effects are most significant, sediment levels due to erosion tend to
be highest during these periods.
Water quality in the headwaters of the Yellowstone and Missouri
River Basins is generally excellent with only localized or seasonal
problems involving sedimentation, heavy metals and acidity (Montana
DNRC, 1976). Water chemistry which began as sodium bicarbonate in
the mountains soon changes to calcium bicarbonate. In central
530
-------
Montana the presence of the sulfate ion becomes more important except
during the high flow period from May through July. In the lower
reaches of these basins near the confluence of the Yellowstone with
the Missouri, median IDS and sulfate concentrations sometimes exceed
the recommended guidelines of 500 mg/1 and 250 mg/1 for drinking water
during the low flow period from November to April. These levels are
not however high enough to interfere with most beneficial uses of the
water in the mainstems.
Water quality in the eastern Wyoming and western North Dakota
tributaries that lie entirely on the high plains and derive their flows
mainly from rainfall or groundwater rather than snowmelt have somewhat
poorer water quality. Dissolved solids near the mouth of the Yellow-
stone, for example, range from about 230 mg/1 to 660 mg/1 with an
average of 460 mg/1, whereas solids in the Powder River at Moorhead,
Montana average 1550 mg/1 with a range of 680 to 4080 mg/1 (NGPRP, 1974)
Upper Colorado River Basin
The Upper Colorado River basin may also be divided into several
hydrologic sub-regions with respect to water availability for energy
development. As shown in Figure 3.5, these study regions may be
identified as follows:
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)
531
-------
UPPER COLORADO
MAINSTEM
LOWER
COLORADO
MAINSTEM
AR/ZONA
FIGURE 3.5 SUB-BASIN BOUNDRIES
UPPER COLORADO BASIN
532
-------
5. San Juan River (Colorado, New Mexico, Utah and Arizona)
As with the Upper Missouri Basin, this section discusses these
sub-regions only with respect to the total water generated that
is available to all users.
Most of the annual runoff produced in the Upper Colorado River
originates in the western slope mountain headwaters of the basin
in Colorado. The mainstem 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 theColorado 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. This geographic variability of
water yield is shown in Figure 3.6 which shows water yields ranging
to over 20 inches in the high mountain regions, but consisting of
less than 0.5 inches over most of the basin. The total water yields
on a sub-regional basis are shown in Table 3.3.
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 regions economy, water resources developments
have been developed over the years to more evenly distribute the
53;
-------
NEW MEXICO
ARIZONA
Source: USGS, 1964
Figure 3.6 Annual Runoff Characteristics - Upper Colorado
River Basin (Contours of Runoff in inches)
534
-------
Table 3.2
AVERAGE ANNUAL WATER YIELD - UPPER COLORADO BASIN
Sub-Region
Upper Green
Lower Green
Drainage
Area
(sq. mi)
14,300
29,700
Average
Water Yield
in Sub-Region1
(AF/year)
1,926,000
3,534,000
Average
Area
Yield
(AF/year/sq. mi
135
119
Upper Ma instern 26,000
Lower Mainstem 20,500
San Juan
23,000
6,838,000
451,000
2,387,000
263
22
104
Sources: Wyoming State Water Plan, 1972
Critical Water Problems Facing the Eleven Western States, 1975
Upper Colorado Region Comprehensive Framework Study, 1971
U.S. Geological Survey, 1964
535
-------
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:
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. These factors are considered in detail in Sections 4 and 5.
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 mineral pollution, commonly
known as salinity. Salinity of surface waters refers to their content
of soluble salts which include mainly chlorides, sulfates, and bicarbonates
of calcium, magnesium, and sodium. Salinity is often measured in terms
of total dissolved solids (TDS) without further identifying the levels
of specific constituents.
536
-------
As water flows downstream in the Colorado River Basin, salt con-
centrations increase due to a variety of natural and man-made influences.
Throughout most of the length of the river, salinity has also been in-
creasing with time. The factors that cause the salinity problems in
the basin may be classified into two basic categories. These may be
referred to as salt loading and salt concentrating effects. Salt
loading refers to the addition of mineral salts into a stream from
natural sources (runoff, springs, etc.) or from man-made causes such as
industrial wastes or leaching of salts from soils during irrigation.
Salt concentrating effects involve no change in the amount of salt
present, but result in higher concentrations as a consequence of removal
of water from the stream system through consumptive use, or transfers of
high quality water out of the basin.
The salinity problem is presently most severe in the Lower Colorado
Basin. It has been estimated annual economic losses of $230,000 per
mg/1 increase in salinity at Imperial Dam just above the Mexican border
(Dept. of Interior, 1974). Although the problem is less critical in
the Upper Colorado Basin, changes in water use here can effect salinity
levels in both the upper basins streams and in the lower Colorado River.
Surface water quality in the Upper Colorado Basin will be an im-
portant 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
source 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.
537
-------
3.3 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-feet of water stored in
natural underground reservoirs at depths within only 200 feet of the
surface (Dept. of Interior, 1975). This volume is several times the
storage capacity of all of the surface reservoirs in the region, yet
present groundwater useage accounts for only a relatively small per-
centage 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. Groundwater supplies may however have
certain advantages over surface supplies in that they are 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 cate-
gories. Shallow (tributary) aquifers consist of coalbeds, sandstones,
and the unconsolidated alluvium along major rivers and their principle
tributaries in buried preglacial valleys. Deeper strata (non-tributary
aquifers) 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 3.7.
The lack of wide-spread groundwater data at a sufficient level of
detail has limited the analyses that could be carried out on a site
538
-------
EXPLANATION
Ouo n 1 ily ge neroily ovoiloble per
*ell, in gollons per minute
SUBREGlON
1. Uppfcf Miisoun River 1 r i foul o ne&
2.Y*I low stone River
3 Western Ootolo tributaries
4.Norlh Plotle - NiobrapQ Riซerg
5.5oglh Plotte - Aritorco Rivers
I 0 a h o
Uloh
100 150 WiLtป
! 'r 1 1 r
0 50 IOO 150 200 250R1LOWETHES
1 Wyoming
Uloh ~! Coloroflo
Source:USGS,1975a
WESTERN MISSOURI RIVER REGION
Figure 3.7 Groundwater Supply Availability(continuecT
539
-------
110*
EXPLANATION
Quantity generally available per
well, in gallons ptr minute
Less than 50
More than 50
Subreqion boundary
Flaming Gorge
Reservoir
Wyoming
ff pJrjTnjosour Notional
Mojnument *?,-^
*/> ' "" *"
.0 '
! SUBREGIOF^^^
G le n wood
Springs
SAN JUAN- COLORADO
SUBREGION
0
1
50 10
i i i j
100 MILES 108"
-r-1
50 100 150 KILOMETRES
UPPER COLORADO RIVER BASIN
Source: USGS, 1975a
Figure 3.7 (concluded^
540
-------
specific basis in this report. It is recognized however that ground-
water will be important as a primary or conjunctive supply in several
areas and that further field study is necessary to identify local
availability. Some general characteristics of these supplies in the
region of interest are given in the following paragraphs.
Upper Missouri River Basin
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
(Dept. of Interior, 1976). 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
high yielding 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. Significant studies of the Madison aquifer
are presently being carried out by the U.S. Geological Survey.
540a
-------
Upper Colorado River Basin
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 (Dept. of Interior, 1975) that the volume of
recoverable groundwater within 200 feet of the surface is about 38
million acre-feet which is nearly three times the active storage in
all 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-
feet of groundwater recharge occurs annually (USGS, 1974) 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.
Groundwater Quality
The general chemical quality of groundwater with regard to its
dissolved solids content according to a classification system used by
the U.S. Geological Survey (1974) is as follows:
541
-------
Class TDS (rng/1)
Fresh <1000
Slightly Saline 1000-3000
Moderately Saline 3000-10,000
Very Saline 10,000-35,000
Briny >35,000
Fresh water is generally found in shallow aquifers of most rock
units in areas above an elevation of about 7000 feet and in certain
sandstones and carbonate rocks which have good hydrologic connection
with the principle recharge areas in the mountains. The chemical
quality in most shallow and alluvial aquifers is slightly to moderately
saline with dissolved solids ranging from about 1000 mg/1 to 5000 mg/1.
In general salinity increases with depth beneath the surface,
except as noted where the aquifer has a good connection with its re-
charge area. The Madison aquifer for example shows very good quality
in certain locations, considering its depth. Dissolved solids in this
aquifer varies from less than 1000 mg/1 near the Black Hills to about
2000 mg/1 throughout the Powder River Basin, but is known to exceed
100,000 mg/1 in some areas of western North Dakota (Dept. of Interior,
1975).
542
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4. WATER USE CONSTRAINTS
4.1 Codes of Water Law
There are two major doctrines of water law found in the United
States, each stemming from a different background and used to different
extents in areas with differing hydrologic characteristics. They are
known as the Riparian Code and the Appropriation Doctrine, and in order
to understand them it is necessary to review the circumstances and
conditions in which they were formed. With this knowledge, it will be
possible to assess on an institutional basis the water supply conditions
found in the western states for energy development.
The Riparian Code descends from English Common Law developed in
the relatively water-rich English Isles. It is based on two princi-
ples - that of "reasonable use"; and the notion that the only person
with any water rights are those who own property adjacent to the
watercourse. The idea of "reasonable use" is relatively ill-defined;
in many cases this has been understood to mean that any use of the
water is permissible so long as no other user of the water is harmed.
Clearly, the Riparian Code is the result of experience gained from
areas in which water is relatively plentiful, and, in its present form,
is suited only to areas with those characteristics. It is practiced
in the states east of the Mississippi River, although certain charac-
teristics of the Riparian Code are found in some other states as well.
543
-------
The Appropriation Doctrine differs significantly in both back-
ground and purpose from the Riparian Doctrine. Used to some extent
in most of the relatively arid western states, where water is fre-
quently a limiting factor, it has evolved since the time of the first
development of the areas in approximately the middle of the 19th
century. It is based on the seniority principle of "first in time,
first in right." This means 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.
Most systems have two important requirements which must be met
before any water right can be established. These are (1) diversion of
the water from the stream, and (2) application of the water to bene-
ficial use. In some of the states these requirements are being altered;
this is discussed in greater detail in the Appendix on the water
administration systems of the, individual states.
It is important to note the difference in the original intention
of the two doctrines. The Riparian Code tends to have as its purpose
the maintenance of satisfactory conditions in the river for all
adjoining landowners, and often has the effect of discouraging out-
of-stream diversions. The Appropriation Doctrine on the other hand
encouragements the use of water, often at the expense of satisfactory
streamflow conditions. It was established to assure the senior appro-
priator that he has a reliable supply of water, inasfar as no other
water user is permitted to take any action which could in any way injure
544
-------
the senior appropriator. Thus, the 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 their junior
appropriation was granted.
The basic concepts enumerated above form the foundation for the
water administration found in each of the states which concern this
discussion. The manner of administration differs considerably from
state to state, but the concepts are found in each of them.
545
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4.2 Administrative Procedures
This section discusses the administrative procedures that generally
must be followed and problems which may be encountered in attempts to
supply water from alternative sources, without respect to the use for
which it is intended.
Typically, each state has a water administration system with
characteristics distinct from those in the other western states. A
characteristic common to all of the systems of the states under con-
sideration 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.
There has been considerable pressure from a variety of sources to
alter administrative procedures in order to make them more responsive
to changes in both economic and socio-political priorities, and major
changes appear possible in the next few years. From many points of
view, stability is a positive aspect of the system: a slow response
implies that matters are much more predictable, permitting much more
certainty in prognostications for olanning aspects. Also, however, the
546
-------
feeling of many of those concerned with water resources management are
that of the goal of efficiency is not served by relatively slow-moving
administrative efforts. Some of the proposals voiced have centered
upon the possibility of having an annual rent to be paid to the state,
as owner of all waters flowing within the state. In some cases, the
rate might be set at the maximum price at which water could be used by
anybody, thus ensuring the maximum return per unit of water, and the
maximum efficiency of water use. However, legislation and administrative
changes based on these concepts is not likely in the near future.
The appropriation system finds its apotheosis in the water admini-
stration practices used in the states of Colorado, New Mexico, Utah,
and Wyoming. Typically, many of the water administration schemes are
extensions of systems started from a number of different sources. These
include early Spanish and Mexican law codes, Mormon water codes, as well
as mining codes developed at the time of the first gold rushes which
were the original impetus for migration of large numbers of people into
part of the area in the second half of the nineteenth centry.
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 transferred 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 on other water uses, junior and senior, is of paramount
importance. In fact, this is, in most cases, the only restriction on
transfers of water on an individual basis. It is typically the case
547
-------
that the burden of proof lies upon those wishing to effect
the transfer, whether the change must be adjudicated, or approved
by an administrator.
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.
Transbasin diversions can be handled in many ways as simply a
conventional change in use and location. However, the consequences
of transbasin diversions tend to have somewhat greater impact on the
hydrologic regimes of rivers; hence, they are much more complicated in
the political aspects. This is largely a result of the interstate
compacts which exist on most of the major interstate rivers. These
548
-------
compacts will be individually discussed later. Generally, the inter-
state 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, trans-basin diversions
concerning these streams, conditions for which are customarily included
in the compact, must satisfy very stringent conditions.
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, e.g., the cone of
depression may not extend beyond the boundaries of the land owned by
the divertor for alluvial systems. In most cases the deep, i.e., non-
alluvial, aquifers with limited recharge capabilities may only be
"mined" at a rate usually set by the state administrator responsible
for such matters.
For large diversions from tributary alluvial aquifers, augmentation
arrangements are frequently necessitated for the surface waters affected.
The augmentation plans are, however, quite subjective on the part of the
State Engineers Office, due to the lack of information available on most
specific surface-ground water interactions.
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 rela-
tively short, significant changes have been made in several states in
549
-------
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 system and the
groundwater management systems.
The procedure by which water can be allocated from the dif-
ferent possible sources to energy uses is, in the eyes of existing
law, exactly the same as procedures followed by allocation to any
other use. It should be kept in mind, however, that because of the
nature and extent of energy conversion activities, the political
and social forces extent will necessarily have some bearing on the
manner in which the development proceeds.
550
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4.3 Interstate Compacts
One of the most important institutional considerations affecting
the utilization, administration, and management of the water resource
in the area of concern lies in the effects of interstate water compacts.
These compacts came about as a result of the need for clarification of
the amounts of water each state could rely upon from shared water
sources. Since most of the important rivers flow through two or more
states, there are a number of interstate river compacts, which allocate
the river's water among the signatory states. Because they are inter-
state, they must be approved by the president and the U.S. Congress
before they become effective. Typically, the negotiations involved in
these compacts involve many years and much discussion, and are jealously
guarded by the states involved.
Yellowstone River Compact
In the three northern states of the study area, Wyoming, Montana,
and North Dakota, an interstate compact of major importance is the
Yellowstone River Compact. Since the Yellowstone River and its tri-
butaries represent the largest potential source of water in much of the
Northern Great Plains Coal Area, the stipulations of this Compact
signed in 1950, provide important guidelines for water supply possibil-
ities. Four articles of this compact have particular bearing on the
question of water supply and are worth enumerating. These are Articles
V, VII, VIII, and X.
Article V is concerned with the allocation of Yellowstone tributary
water between Wyoming and Montana. This is performed on a percentage
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of available flow basis, and is relatively uncontroversial. Rights
and diversions existing at the date of compact signing were
recognized.
Articles VII and VIII deal with the permissibility of facility
construction in one state for use of water in another state.
Article X is important because it treats the question of out-of-
basin transfers of water from any of the Yellowstone River Drainage
Basin. Essentially, it requires unanimous consent from the three
signatory states before any out-of-basin diversions. This is a serious
constraint on water resource development in the area, for the reason
that some of the major easily-retrievable coal lies just outside the
Yellowstone Drainage Basin, in the area near Gillette, Wyoming of the
Belle Fourche River Basin. As water supplies are particularly limited
in the Belle Fourche River Basin, a likely possibility for a source
of large-scale water importations would have been the tributaries of
the Yellowstone River. However, the problems associated with gaining
the requisite unanimous approval of the signatory states are sufficient
to cause a serious (some believe insurmountable) obstacle to trans-
ferring the water from this source. This is currently being tested in
court by the Intake Water Company vs. Yellowstone River Compact
Commission case, mentioned elsewhere. Provision does exist in the Yellow-
stone River Compact for the transfer of water from one tributary of
the Yellowstone River to another tributary, such that the water is not
exported from the Yellowstone Basin.
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Belle Fourche River Compact
The Belle Fourche River Compact concerns the entire drainage basin
of the Belle Fourche River in Wyoming and South Dakota. The two states
are participants in the compact, which divides the limited quantity of
water in the basin between Wyoming and South Dakota.
While recognizing the existing water rights on the river, it
strictly controls what use and facilities may occur in Wyoming after
the signing of the pact. Generally, the Belle Fourche Compact does not
appear to affect water development plans significantly, as it deals with
relatively small amounts of water.
Platte River
No Platte River Compact as such exists. Several court cases have
been decided in the Supreme Court regarding the division of the North
Platte River and its tributaries between Wyoming and Colorado. These
decisions presently constitute the guidelines by which the North Platte
River is divided between Wyoming and Colorado. There also exists a
stipulation, approved by the Supreme Court, between the states of
Nebraska, Colorado, and Wyoming regarding the allocation and use of
Platte River water between them.
These documents result in a situation such that the water of the
Platte River is almost fully allocated. This implies the potential
sources of water required for energy use will be the following:
1. Purchase of existing agricultural rights, 2. Construction of new
storage facilities, 3. Importation of water to the Platte River Basin.
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Because of the long history of litigation between Wyoming,
Colorado, and Nebraska, each of the states guards its water carefully.
In the past the downstream states have often sued the upstream states
to prevent actions which might remove too much water from the stream.
Thus Nebraska might be expected to be the plaintiff in any action
resulting from the construction of additional storage capacity in
Wyoming for energy use.
Colorado River Basin Institutional Aspects
The Colorado River, the most important river in its region, has had
its water allocated among the seven states of the Colorado River Basin
and Mexico by a series of compacts, following lengthy and acrimonious
discussions. In 1922, the Colorado River Compact was concluded; in
essence, this divided the river into an Upper Basin consisting of
Colorado, Wyoming, Utah, New Mexico, and a small area of Arizona. The
lower Basin was made up of the remainder of Arizona, California and
Nevada, and the dividing point between the Upper and Lower Basin is at
Lee's Ferry, Arizona, directly below the Glen Canyon Dam. With this
compact, it was decided that the lower basin was to receive 75 million
acre-feet every ten years, or an average of 7.5 million acre-feet per
year. At that time, it was thought that the average annual flow of
the Colorado River was 15 million acre-feet per year, so the flow was
intended to be evenly split between the Upper and Lower Basins.
In 1928, the Boulder Canyon Act was concluded by the Lower Basin
States, in order to proceed with the construction of Hoover Dam and the
All-American Canal. This Act apportioned water between the Lower Basin
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States on the basis of 4.4 million acre-feet per year to California,
0.8 million acre-feet to Arizona, and 0.3 million acre-feet for
Nevada.
In 1945, as part of a treaty between the U.S. and Mexico appor-
tioning water of the Rio Grande, Tijuana, and Colorado Rivers, it was
agreed that Mexico would receive 1.5 million acre-feet annually from
the Colorado River. This was to be increased to 1.7 million AF/yr in
years of surplus and decreased in proportion to the decrease of con-
sumptive use in the United States. It was later determined that the
1.5 million acre feet annually owed to Mexico was a burden to be
shared equally by the Upper and Lower Basins.
In 1949 the Upper Colorado Basin Compact was concluded, resulting
in apportionment of the Upper Basin Allotment of Colorado River water.
These are as follows: (in terms of total beneficial consumptive use
of available water to the Upper Basin):
Arizona: 50,000 AF/yr
Colorado: 51.75%
New Mexico: 11.25%
Utah: 23%
Wyoming: 14%
The apportionments were made in terms of flow percentage in part, be-
cause of the awareness of the variation in river flows, combined with
the Lower Basin commitment of a fairly constant amount. Included in
this Compact were the details of how state water apportionment cutbacks
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are to be determined, with respect to the existing interstate river
compacts on the San Juan and other tributaries of the Colorado,
if a "compact call" occurs under the terms of the Colorado River
Compact.
The Upper Colorado River Storage Project Act of 1956 had the
construction of water storage facilities in the Upper Basin of the
Colorado River as its purpose. Most of these projects are presently
completed with a storage capacity of over 24 million acre-feet. This
means that the flow at Lee's Ferry can now be completely controlled,
thus allowing the Upper Basin to make efficient use of their allotment.
A later development on the Colorado River was Minute 242 of the
International Boundary Waters Commission, in which the U.S. agreed
to deliver water of a certain quality (in terms of Total Dissolved
Solids (TDS)) to Mexico, as part of the conditions by which the water
would be delivered to Mexico. This was significant change in the
administration of water in the Colorado Basin, as quality, although
long recognized as a problem in the Basin, had never been covered in
any sort of compact or treaty.
The problem of salt loading is severe in the Colorado River for
a variety of causes. There are many natural sources of salt in the
basin, taking the form of springs and salt beds, and they contribute
a high percentage of the total salt load. However, the problem is
magnified because of the purposes for which the water is used. The
greatest use is for irrigation, in which water is diverted from the
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river and applied to land. Generally, a return flow to the river
results from irrigation, and the return flow tends to have a higher
IDS concentration than the original water for two reasons: a portion
of the water is lost to evapotranspiration, thus leaving a greater
concentration of salt in the remaining water, and the return flow
then travels through the soil and rock, dissolving and carrying away
the salt in the soil and rocks. A consequence of the salt loading
from both natural and artificial causes in such high concentrations
of IDS in the lower Colorado is to make the water worth much less for
practically all purposes. There is currently some uncertainty in the
Colorado River Basin about the measures which will be taken about the
salt loading. A large portion of the salt loading in the river from
both natural and artificial causes occurs in the Upper Basin. One
problem lies in the fact that the water from high on the river is
typically quite pure, thus diluting the concentration of IDS in the
lower portions. Any decrease in the flow of this due either to out-of-
basin diversions or consumptive use has the effect of increasing the
IDS concentration in the lower part of the basin. Since much of the
salt load caused by irrigation also occurs in the Upper Basin, and
because almost every water development has the effect of increasing
IDS concentrations, those involved with water use in the upper basin
are understandably concerned about the measures taken to alleviate the
problem. One action which has already begun is the construction of a
large desalination plant at Yuma, Arizona, near the Mexican border.
This facility is being constructed for the purpose of improving the
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quality of water delivered to Mexico, and is only part of a larger
plan to control salinity. The EPA is also currently being sued to
play a greater role in the water quality management of the Colorado
River, which may have significant consequences in development and
water supply situations in the area.
Although the 1922 Colorado River Compact had intended to divide
the available Colorado River Water evenly between the Upper and Lower
Basin, the result has not met the intention. This is because, in the
years since 1922, the flow of the Colorado has been considerably less
than 15 million acre feet per year. Since the language of the compact
guaranteed the Lower Basin States an average of 7.5 million acre-feet
per year, without regard to the flow, the Upper Basin has received
correspondingly less water. Until the present this has not been a problem,
because the entire allotment to the Upper Basin has not been used.
With new developments, there will be increasing dissatisfaction with
this situation, for which no immediate resolution is likely. There
is some pressure in the Upper Basin to seek a real location of Colorado
River water between the Upper and Lower Basins for this reason.
Another aspect of water management in the Colorado River Basin
lies in the controversy surrounding out-of-basin diversions. There
currently are a number of these in Colorado, transporting water from
the Colorado or its tributaries to the Rio Grande, South Platte, or
Arkansas River basins on the Eastern slope. Since these diversions
take very high quality water far up in the river basin, they have the
result of contributing to the salinity problem in the lower reaches of
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the Colorado River, because of the removal of what is largely dilution
water. Although there is sentiment against the out-of-basin diversions
for this reason, as well as the desire of the sparsely populated
Western Slope area of Colorado to keep its water, the political strength
of Eastern Colorado is such that it continues to divert water from the
Colorado River, and to plan for future transmountain diversions.
However, this is becoming increasingly difficult, and few more trans-
mountain diversions should be expected as opposition from a variety of
groups increases.
One possible alternative for water supply in the Powder Basin,
Wyoming, area is the transmountain diversion of Green River water to
the North Platte River, and thence a diversion to the Powder River.
This would be the second transmountain diversion from the Colorado River
Basin in Wyoming, and might meet with less opposition than any similar
proposal in Colorado, because it would allow Wyoming to more fully use
its Colorado River opportionment. Again, however, this would have the
effect of increasing salinity in the lower reaches of the Colorado.
Several streams in Wyoming, Utah, Colorado, and New Mexico are
subjects of interstate compacts, and convered by the Upper Colorado River
Basin Compact of 1948. These compacts covering La Plata Creek, Little
Snake Creek, Yampa River, San Juan River, Henry's Fork, Beaver Creek,
Burnt Fork, Birch Creek, and Sheep Creek, still have the conditions of
the Upper Colorado River Basin Compact of 1943 as their major limits,
and will therefore not be discussed individually.
559
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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 eventual clash
between the states of Colorado and Utah when an attempt is made in
either state to put a significant amount of water to use. Currently, the
river remains largely undeveloped.
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4.4 Federal Water Policy
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 watever 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 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 upheld firmly.
The problem associated with the Federally reserved water rights is
that they have not been quantified or even identified, resulting in
uncertainty on the past of 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.
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An outcome of the trials known as the "Eagle County Cases" and
the McCarran Amendment of the 1952 U.S. Congress was the decision
that Federal claims to water would be made within the state systems
for general adjudications of water rights. As a result of these
cases, the Federal Government must move to establish its claims in
the State Legislatures; however, this has been proceeding quite slowly
because the government is seeking to determine the maximum use for
any of the possible futures which might take place on its reservations.
Some claims have been established in the Colorado River Basin; for
example, the amount of water claimed for the Naval Oil Shale Reserves
has been designated as 200,000 Acre-Feet, although the Federal Govern-
ment in Colorado still does not agree that its claims under the
Reserve Rights Doctrine must be quantified.
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, Dolores, and Colorado in the study
area.
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5. COMPETING WATER DEMANDS
5.1 General
In assessing water availability for synthetic fuel production in
the western states an important consideration is how other alternative
uses will compete for the available water at any particular supply
source. The future water supply and demand interaction in any region
is virtually impossible to accurately predict because of potential and
often likely changes in the seasonal distribution of water supplies
through new control/diversion facilities or changes in institutional
constraints affecting how the water can be used. The best available
indicator of how water supplies in any region will be distributed
among the various demand sectors is the present way in which the water
is used. This chapter deals first with the present use of water in
the various regions of interest to this study, then discusses the
factors that may lead to changes in the demand structure, and finally
suggests 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
effected the development 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 elevations in the upper watersheds. Melting
of the extensive mountain snowpeaks results in high rates of spring
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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 potential 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 on 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.
As pointed out in Chapter 4, the legal right to use water is a
more important consideration in the west than is the mere presence of
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an available supply that is not being fully utilized. In this
context it is important to note that although a certain free market
transfer of supplies between various individuals or sectors of
demand is possible within the system, the provisions of the intra-state
compacts and in state regulation may in fact be an increasingly significa
factor as supplies become more fully allocated. Concern over conflicting
plans for future use of the water in the Yellowstone River Basin, for
example, recently led Montana to enact a temporary moratorium on an
major new appropriations within its portion of the basin. Also,
individual states are increasingly recognizing instream flow needs as
a beneficial and therefore reservable use.
Generalizations concerning the major water use categories that
apply throughout the western study region are presented in the following
paragraphs. The discussion then focuses on the specific water use
situation in the individual sub-regions of primary interest.
Irrigation
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. The amount of water applied
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per acre is quite variable with location, depending on the age and
condition of the project, the technology of application, the type
of crop grown, the local geology, and the cost/availability of water
Normal irrigation practice usually results in return flows (either
directly or through the shallow groundwater system) that may be
reused for irrigation or other applications. 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.
Water quality requirements for irrigation are dependent on
a number of factors including salinity, sodium adsorption ratio,
crop type, quality of the soil, the amount of rainfall and the total
amount of rainfall applied. Although absolute limits cannot be set
for irrigation water quality, the U.S. Department of Agriculture
has established some general classifications for the salinity
hazard which may be used as a guide where there are no particular
soil problems (Upper Colorado Region State-Federal Interagency
Group, 1971). These categories are as follows:
Salinity Hazard IDS (mg/1)
Low < 160
Medium 160 - 480
High 480 - 1440
Very High > 1440
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Reservoir Evaporation
As indicated earlier an extensive system of reservoir storage
has been developed throughout the West to more uniformly distribute
the spring runoff over the year and particularly through the growing
season. These reservoirs often serve multipurpose functions in-
cluding 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.
Instream Flow Needs
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
ana 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.
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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.
Municipal
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 that 5% of overall water use and an
even smaller fraction of total depletions.
Water quality requirements for municipal systems are quite high.
The U.S. Public Health Standard recommended guideline for drinking
water specifies a maximum TDS level of 500 mg/1 (U.S.P.H.S., 1962).
Many smaller communities in the West, however, have supplies containing
over 1000 mg/1 TDS for lack of better quality supplies.
Industrial
Self supplied industrial users are generally considered separately.
The major industrial uses in this category are the mining and minerals
industry which uses water primarily in the cleaning and processing of
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ores, and the power Industry which uses water in thermal electric
plant for cooling. These major industries as well as many other less
significant water users offer fully deplete their water with-
drawals because any wastewater produced would be detrimental to the
environment if returned to the streams.
The water quality requirements for industrial uses vary widely
according to the industry served. Much of the water used in the
mining and materials industry can be highly brackish without affecting
its utility. Industries using cooling water require fairly nigh
quality water to prevent fouling of the facilities. Where water
quality requirements are high, treatment prior to use may be practical
for some industrial applications. Fresh and brackish groundwater
supplies for industrial use have been developed in many locations
where there is a suitable match between the quality of available
supplies and the needs of the industry.
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5.2 Present Water Use
Upper Missouri River Basin
Water use in the Upper Missouri Basin is committed largely to
agricultural pruposes. 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 inter-state
rivers and their major tributaries. Good water availability 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 development 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.
As previously described in Section 4, 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 is already in very short supply. Within each
of the major tributaries, various inter-state compacts define how
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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.
Although the Northern Great Plains States do have a formal agree-
ment as to how much of the available water is allocated to each state
under the compacts, the Wyoming State Water Plan (Wyoming Water Planning
Program, 1973) provides a breakdown that appears to be the best avail-
able at the present time. Allocations among the states according to
the plan are as follows:
Total Subject
to Compact Wyoming Montana
Tributary
Bighorn
Tongue
Powder
(AF)
1 ,800,000
241,100
287,300
(%)
80
40
42
(AF)
1 ,800,000
96,400
120,700
(%)
20
60
58
(AF)
400,000
144,700
166,600
The way in which water is presently used in the Upper Missouri
coal regions is shown in Table 5.1. For each of the study sub-regions
defined earlier, water use estimates under the categories of irrigation,
municipal and industrial (including rural domestic), self-supplied
industrial, and reservoir evaporation are given. 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 the
water utilized in these sectors.
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Table 5.1
PRESENT WATER USE - UPPER MISSOURI BASIN
(Depletions - Acre-Feet/Year
Sub-Region
i-Rosebud
Irrigation
187,200
M&I and
Rural
Domestic
5,000
Industrial
1 ,600
Reservoir
Evaporation
8,000
Total
201,8
Powder
181,600
4,400
1 ,600
29,000
216,700
Yellowstone Mainstem
1,561,200
79,400
24,600
331,900 1,997,100
Belle Fourche-Cheyenne
(Wyoming Only)
6,000
2,000
3,000
31,000
41,000
Heart-Cannonball
24,300
6,500
2,400
8,000
41,200
Upper Missouri Mainstem 1,335,300 159,600 (including all 1,445,000 2,939,900
(To Oahe Dam) Industrial)
North Platte
(Wyoming Only)
574,000
7,000
9,000
177,000
766,000
Sources: Wyoming Framework Water Plan (Wyoming Water Planning Program, 1972)
Water Use in Montana (MT. DNRC, 1975)
Water for Energy (U.S. Dept. of Interior, 1975)
Critical Water Problems Facing the Eleven Western States (U.S. Dept. of Interior, 1975)
North Dakota Water Resources Development Plan (N.D. State Water Commission, 1968)
-------
Upper Colorado River Basin
The Upper Colorado region also has agriculture as an important
part of the economy. 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 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 sub-regions according to
the various demand sectors is given in Table 5.2.
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Table 5.2
PRESENT WATER USE - UPPER COLORADO BASIN
(Depletions - Acre-Feet/Year)
Sub-Basin
Upper Green
Lower Green
Upper Mainstem
Lower Mainstem
San Juan
Irrigation
242,000
550,000
775,000
33,000
286,000
i
Other losses are consumptive
attributed to recreation, wil
Sources: Wyoming
Critical
M&I and
Rural
Domestic
12,000
6,000
15,000
1,500
11,500
conveyance
dlife, and
Industrial
16,000
28,000
13,000
1,500
31,500
Reservoir
Evaporation
26,000
31,000
79,000
2,000
95,000
Other1 Total
296,000
154,000 769,000
194,000 1,096,000
38,000
48,000 472,000
losses and evaporation
wetlands
Frameowrk Water Plan (Wyoming Water Planning Program,
Water Probl
ems Facing
the Eleven Western
States (U.S.
1972)
Dept. of Interior, 19
Water for Energy (U.S. Dept. of Interior, 1974)
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5.3 Demand Variability
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 irrigation water requirements (U.S. Department
of Commerce, NOAA, 1977).
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 tent to be highest. During these periods demands of many of
the junior water rights in certain areas cannot be met.
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, the significant evaporation water
losses result in net decreases in the water available to downstream
575
-------
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 require
priority rights during low flow periods.
576
-------
5.4 Potential Demand Changes
Any discussion of potential demand changes must recognize thet
the limited water supply and associated high economic cost of v/ater
in the West have directly influenced growth and development in many
areas. 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 significant 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,
institutional constraints may play a key role in the way water may
be distributed or used. As described in Section 4, constraints or
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.
Changes in institutional constraints are impossible to predict
at the present time and will not be attempted within the context of
this study. It will be assumed that present institutional constraints
577
-------
will continue into the future. It is important to bear in mind
however that this aspect of the supply/demand interaction will remain
in a state of flux. Several important areas where institutional
changes could be of particular importance are regulations to protect
the existing agricultural socio-economic character of the region,
as presently advocated by certain groups, to recognition of instream
flows as a beneficial use as presently being studied by several
states, and the quantification of Indian water rights.
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.
With regard to the future course of agricultural development
in the energy resources regions of the country, 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 because the
demand for food and fiber production depends, to a great degree on
national policies and market conditions, which will affect the degree
of Federal financing of irrigation development such as Bureau of
Reclamation storage projects (W.F.E., 1975).
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
578
-------
affect the level of coal and oil shale development occurring 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 for future
energy development.
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.
Major concerns in the area of agricultural usage have led to a number of
recent studies which have shown that significant improvements in the efficiency
of irrigated agriculture water use can be attained. Recommended procedures
include improvements in the design and layout of existing distribution
systems to reduce seepage and salt loadings, and use of drip irrigation
systems to reduce evaporation losses (C.vl.P., 1975). In industrial
applications, including energy production, studies have indicated
that air cooling processes, although more expensive initially, are
as effective as water-cooled systems, but use little water. 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. Many industrial and maining
processes such as slag quenching, ore rinsing, dust control, and
stack gas scrubbing can utilize water that would not be suitable for
many other uses.
579
-------
5.5 Future Demand Projections
As discussed in the previous section, many factors that cannot
presently be determined will affect levels of future demands. Many
other studies have reported estimates of future water demand for
different uses and the results vary considerably, indicating that
there is no general agreement as to how future uses will shape up.
The available data has been reviewed during the course of this study
and summarized by sub-region according to use.
Upper Missouri River Basin
Estimates of water use in the year 2000 in the Upper Missouri
River Basin portion of the study area are given in Table 5.3.
Projections for portions of the Sub-Regions in the State of Wyoming
are taken from the Wyoming Framework Water Plan (Wyoming Water Planning
Program, 1973) 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 Conservation (1977).
Figures for the Yellowstone Mainstem and the Heart-Cannonball Sub-
Regions were disaggregated from estimates for the total Yellowstone
Basin and the Western Dakota tributaries of the Upper Missouri Basin.
No use projections were made for the Upper Missouri Mainstem sub-
region 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 will into the future.
580
-------
Table 5.3
PROJECTED FUTURE (YEAR 2000) WATER USE - UPPER MISSOURI REGION
(Depletions - Acre-Feet/Year)
00
Powder
Sub-Region
i-Rosebud
%
'stone Mainstem
Fourche-Cheyenne
Irrigation
238,000
285,000
1,785,000
7,000
M&I and
Rural
Domestic
11,000
10,000
128,000
5,000
Industrial
124,000
62,000
25,000
45,000
Reservoir
Evaporation
9,000
29,000
332,000
31,000
Total
382,000
386,000
2,270,000
88,000
(Wyoming Only)
Heart-Cannonbal1
61,000
8,000
3,000
17,000
89,000
Upper Missouri Mainstem
(To Oahe Dam)
Note (1)
North Platte
(Wyoming Only)
918,000 36,000
47,000
180,000 1,181,000
Major water demands in this region will be supplied out of the Mainstem reservoirs
which have a supply that greatly exceeds any projected uses.
Sources: Water for Energy (U.S. Dept. of Interior, 1975)
Future of the Yellowstone River (MT. DNRC, 1977)
Wyoming Framework Water Plan (Wyoming Water Planning Program, 1972)
- .- -, / MT
-------
In Table 5.3, the figures given for industrial usage include
self-supplied industrial uses (municipally-supplied industrial water
is included under M&I/Domestic) which are primarily the mining/minerals
industry and thermal power generation. Projections for synthetic
fuel production are not included in this category, but are discussed
later in Section 6. Data on future reservoir evaporation losses
is not available so it has been assumed for the purposes of Table 5.3
that these depletions will be the same in the future as at present.
Upper Colorado River Basin
Upper Colorado River Basin water use estimates for the year
2000 are given in Table 5.4. 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 disaggregated from
figures given for the individual states (Upper Colorado Region Com-
prehensive Framework Study, 1971). M&I and self-supplied industrial
(exclusive of synthetic fuel production) projections were derived
from figures given in "Water for Energy in the Upper Colorado River
Basin" (U.S. Department of Interior, 1974). By the year 2000, it
was assumed that each state will be utilizing their allowable share
of the mainstem reservoir evaporation 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 fifty percent increase in this category
over present depletions, primarily for fish, wildlife, and other
recreational developments.
582
-------
Table 5.4
PROJECTED FUTURE (YEAR 2000) WATER USE - UPPER COLORADO REGION
(Depletions - Acre-Feet/Year)
in
CD
LO
Sub-Basin
Upper Green
Lower Green
Upper Malnstem
Lower Mainstem
San Juan
Sources: Wyomi
Criti
Irrigation
407,000
655,000
1 ,166,000
58,000
696,000
ng Framework
M&I and
Rural
Domestic
6,000
15,000
20,000
2,000
27,000
Water Plan (Wyomi
cal Water Problems Facint the
Industrial
104,000
146,000
108,000
23,000
188,000
Reservoir
Evaporation
73,000
144,000
168,000
18,000
117,000
ng^ Water Planning Program,
Eleven Western
States (U.S.
Other
24,000
231 ,000
291,000
72,000
1972)
Dept. of
Total
618,000
1,191,000
1 ,753,000
101,000
1,100,000
Interior, 19
Water for Energy (U.S. Dept. of Interior, 1974)
-------
6. WATER SUPPLY AVAILABILITY FOR ENERGY DEVELOPMENT
6.1 Regional Hater Availability
Previous sections of this report have dealt with annual water
yields and water usage in each of the hydrologic sub-regions selected
for study because of the presence of significant coal or oil shale
energy reserves. This section combines the total annual water supply
data with water use projections for uses other than energy development
to estimate total future unallocated surface water supplies in each
region. These results give an indication of the net water supply
that could be expected to be available for energy production without
the transfer (acquisition) of existing water rights from present
uses to energy use. Section 6.2 then discusses the range of likely
energy development scenarios and Section 6.3 considers alternative
ways in which the energy water requirements might be met.
A summary of projected regional water availability for energy
use in the year 2000 in the Upper Missouri River Basin is given in
Table 6.1. A similar summary is given in Table 6.2 for the Upper
Colorado River Basin.
These summaries consist of three parts for each region: the
overall water supply, water use and commitments, and the net re-
maining water supply. The overall water supply in a sub-region consists
of the natural water yield within the sub-region (as previously
given in Tables 3.1 and 3.3), the depleted stream inflows from other
sub-regions, and any water imports from other sub-regions. Data on
584
-------
Table 6. 1
PROJECTED FUTURE WATER AVAILABILITY - UPPER MISSOURI BASIN
(1000 AF/YR)
Annual Water Supply
Water Use and Commitments
03
Ln
Sub-Region
Tongue-Rosebud
Powder
Yel lowstone
Mainstem
Belle Fourche-
Cheyenne
Heart-
Cannonbal 1
Natural
Yield
467
502
10,488
182
338
Depleted
Inflow
0
0
0
0
0
Imports
0
0
0
0
0
Total
Supply
467
502
10,488
182
338
Projected
Depletions
382
386
2,270
88
89
Total
Instream Flows Exports Use
148 o 53ฐ
162 o 548
4,070 o 6>340
75 o 163
138 o 227
Net Water
Availability
(63)
(46)
4,148
19
111
North Platte
1,223 520
10 1,753 1,181
501
0 1,682
71
-------
Table 6.2
PROJECTED FUTURE WATER AVAILABILITY - UPPER COLORADO BASIN
(1000 AF/YR)
Annual Hater Supply
Water Use and Commitments
Ln
CO
(Ti
Sub-Region
Upper Green
Lower Green
Upper Mainstem
Lower Mainstem
Natural
Yield
1926
3534
6833
451
Depleted
Inflow
0
1 ,300
0
9,298
Imports
0
0
0
0
Total
Supply
1926
4834
6838
9749
Projected
Depletions
618
1191
1753
101
Instream Flows
2
3
4
960
,400
,400
,900
Exports
10
112
620
0
Total
Use
1,588
3,703
5,773
5,001
Net Water
Availabil i
338
1,129
1,065
4,748
ty
San Juan
2387
130
2517
1100
1,260
113 2,473
44
-------
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 Tables 5.3 and 5.4), estimated present unused water
commitments and instream flow requirements, any any water exports
from out of the sub-region. The difference between the total
available water supply and the total water use and commitments is
the net water supply available for future depletion.
587
-------
6.2 Energy Development Scenarios
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,
foreign oil, or other forms of energy. The purpose of the work
reported on here is to establish, based on a number of existing
energy scenario projections, a range (minimum, likely, and maximum
levels ) of water needs in each sub-region that may be required for
energy purposes. Sources of water supply for these water requirements
are discussed in the next section.
Summaries of the expected ranges of water requirements for the
year 2000 from several sources are presented in Tables 6.3 and 6.4
for the Upper Missouri and Upper Colorado Basins. Because the
interaction of water requirements for energy development other than
synthetic fuel production (primarily electric generation) are signi-
ficant to the overall water availability outlook, separate figures
are given for synthetic fuel production and the total coal industry.
In general, the sub-areas used to report energy development and water
requirement projections under various scenarios were different in
these studies than the drainage sub-areas used in our investigations.
As a result some adjustment of the values was necessary to make the
figures consistent with our study basins. Although these adjustments
are in accordance with the general availability and accessibility
of the coal reserves from region to region, they are somewhat
arbitrary in cases where the data is lacking or not specific.
The overall range of water requirements however is probably reasonably
representative.
588
-------
Table 6.3
ENERGY WATER REQUIREMENT SCENARIOS - UPPER MISSOURI BASIN
(1000 AF/YR)
WPA Syn. Fuel Sites
Harza Energy Study
Syn. Fuel Plants
Syn. Fuel , AF/YR
Total Coal Ind. AF/YR
Wyoming Water Plan
Syn. Fuel Plants
Syn. Fuel, AF/YR
Total Coal Ind. , AF/YR
Univ. OK/EPA
Syn. Fuel AF/YR
Total Coal Ind. AF/YR
Natural Petroleum Council
Syn. Fuel Units
Syn. Fuel, AF/YR
Total Coal Ind. ,AF/YR
Composit Range
Syn. Fuel , AF/YR
Total Coal Ind., AF/YR
Powder
Tongue-
Rosebud
0-6-9
0-36.1-189.0
48.2-65.1-195.2
4
55
114
0-0-0
0-0-0
15.7-32.7-55.6
Belle-Fourche
Cheyenne
3
0-1-2
0-18.8-31.3
9.8-21.9-45.6
3
50
114
46.3-63.6-57.5 39.7=58.9-53.5 12.7-16.2-10.2
134.0-151.3-145.3 136.8-179.9-240.1 38.6-42.1-46.5
2-4-13 1-2-5
14.5-33.5=127.2 7-20.0-44.5
121 .2-140.2-233.8 60.4-73.4-113.4
15-40-190
50=140=230
5=15-55
15-100-240
1-2-8
10.5-23.5-97.5
90.5-103.5-177.5
10-20-30
20=35=50
Yellowstone-
Missouri
Mainstem
Heart-
Cannonbal1
0-4-5
0-44.5-73.7
11.1-105.8-126.9
0-4-5
0-49.7-63.7
10.3-101.9-112.4
39.6-60.4-49.5
95.6-191.2 = 214.;
17.6-24.2-39.5
65.4-48.0-121.5
1-5-10 1-1-2
7.5-46.0-103.0 7.5-10.0-23.0
124.5-163.0=220.0 56.5-59.0-72.0
5-45-75
10-150-220
5-25=60
10-60-120
-------
Table 6.4
ENERGY WATER REQUIREMENT SCENARIOS - UPPER COLORADO BASIN
(1000 AF/YR)
Source
WPA Sites
UCRB Report (2000)
Syn Fuel, Plants
Syn Fuel, AF/Yr
Total Energy, AF/Yr
Upper
Green
Lower
Green
1
Upper Colorado
Mainstem
2
37.0
116.5
4
98.5
243.5
7
191.0
325.0
San Juan
2
72.0
154.0
Ln
tฃ>
O
Wyoming Water Plan (2020)
Syn Fuel, AF/Yr
Total Energy, AF/Yr
204.8
Univ of OK/EPA (2000)
Syn Fuel, AR/Yr
Total Energy
38.8-51.7-51.7
38.8-51.7-51.7
5.6-14.3-14.3
34.8-43.5-101.9
National Petroleum Council (1985)
Syn Fuel, Plants
Syn Fuel, AF/Yr
Total Energy
2
18-18-18
42-42-42
13
112-112-112
112-112-112
1
20-48-60
140-168-180
COMPOSIT RANGE
Syn Fuel, AF/Yr
Total Energy, AF/Yr
50-100-200
40-60-100
110-110-325
40-60-180
-------
Composite ranges and intermediate energy water requirements
selected from the available sources for use within the context of
our present study are further summarized in Table 6.5. Comparison
of these figures with the water availability results from Tables
6.1 and 6.2 gives an indication of the relative adequacy of water
supplies for energy production in the study sub-regions. These
results show that the projected levels on energy development
cannot be accommodated by the available supplies in most sub-regions,
Only in the Yellowstone, Upper Missouri, Upper Green, and Upper
Colorado mainstem sub-regions does it appear that sufficient un-
reserved supplies are available for the expected levels of energy
production. In all other regions, lack of sufficient water could
be a limiting factor unless additional supplies can be made avail-
able through surface and/or groundwater development or through
the acquisition of existing rights.
591
-------
Table 6.5
SUMMARY OF ENERGY WATER REQUIREMENTS
(1000 AF/YR)
Sub-Region
UPPER MISSOURI
Powder
Tongue-Rosebud
Yellowstone Mainstem
Synthetic Fuel
Min. Inter. Max.
15
5
Belle Fourche-Cheyenne 10
Heart-Cannonball 5
Upper Missouri
North Platte
40
15
20
25
190
55
30
60
Total Coal/Shale
Min. Inter. Max
50
15
20
10
140 230
100 240
35
60
50
120
UPPER COLORADO
Upper Green
Lower Green
Upper Mainstem
Lower Mainstem
San Juan
20
10
-
50
0
0
60
50
40
no
-
40
100
60
-
-
60
200
100
325
-
180
592
-------
6.3 Alternative Water Supply Sources
In this section, we attempt to present some of the possibilities
for water supply for energy conversion. 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. We hope that these will not affect
the conclusions in any significant manner. 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 alternatives, although no estimates
are made of the prices or the different manipulations 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 irri-
gation, construction of storage facilities, purchase of water
from existing storage facilities, and inter-basin transfers of
water. Each of the alternatives given below is comprised of one
or more of these water sources.
Different alternatives appear in the various scenarios of
water demand, for two reasons:
a. the alternative supplied either too little or too much
water (i.e., economic reasons), or
b. the alternative would not be acceptable for institutional
reasons (e.g., it is permissible to dry up a small portion
of farmland, but not an entire area).
593
-------
The alternatives presented are compatible with those for
the other river basins, event 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 sub-regions
in the Upper Missouri Basin is presented in Table 6.6. Alternatives
for the Upper Colorado Basin are given in Table 6.7. A few additional
comments on each sub-region are given in the following paragraphs.
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 avail-
able water in the drainage basin. Because these rivers are both
tributary to the Yellowston River, importations to the Tongue and
Rosebud basin from other parts of the Yellowstone Basin are expessly
permitted by the Yellowstone River Compact. These are several
sites in the basin for which reservoirs have been proposed, and
these are included as possible alternatives for water supply.
POWDER RIVER BASIN
Large amounts of coal have been found in the Yellowstone River
Basin, including the drainages of the Powder, Tongue, and Bighorn
Rivers, which are tributaries of the Yellowstone. In general, the
Yellowstone and Bighorn have sufficient water supplies for all
594
-------
Table 6.6
SUMMARY OF WATER SUPPLY ALTERNATIVES - UPPER MISSOURI BASIN
Sub-Region
Tongue-Rosebud
Scenario I
Low Demand
Additional storage alone,
or with water rights
acquisition
Scenario II
Moderate Demand
Additional storage, or
aqueduct from Bighorn
or Yellowstone
Scenario III
High Demand
Aqueduct from Bighorn
or Yellowstone
Powder
Acquisition of water
rights, or construct
Moorhead or Lower Clear
Creek Reservoir
Ultimate Powder River
development, or aqueduct
from Bighorn or Yellowstone
Aqueduct alone, or with
reservoir development
Yellowstone Mainstem
Mainsteni diversion
Mainstem diversion to
offline storage
Missouri Mainstem, or
Fort Peck Reservoir
Belle Fourche-Cheyenne
Reservoir development, or
groundwater development
Reservoir and ground-
water development, or
aqueduct
Aqueduct from Bighorn, or
Yellowstone Rivers
Heart-Cannonbal 1
Reservoir development
Aqueduct from Sakakawea
or Oahe Reservoir
Same as II
Upper Missouri
Mainstem
Mainstem diversion
Aqueduct from Fort Peck,
Sakakawea or Oahe Reservoir Same as II
North Platte
Acquisition of water rights
and/or groundwater develop-
ment
Same as I, or importation Same as II
from Green Basin
-------
Table 6.7
SUMMARY OF VJATER SUPPLY ALTERNATIVES - UPPER COLORADO BASIN
Sub-Region
Scenario I
Low Demand
Scenario II
Moderate Demand
Scenario III
High Demand
Upper Green
Additional local storage
facilities
Aqueducts from Fontenelle
and/or Flaming Gorge
Same as II
Lower Green
Upper Mainstem
Lower Mainstem
Reservoir development on
the White River
Diversion from the main
stem to utilize existing
storage
Reservoir development on
the White River
Same as I
White River storage
plus diversion from
the Green River
Same as I
Although no significant energy development has been projected for the Lower Mainstem
hydrologic sub-region, large supplies are available from Lake Powell.
San Juan
Groundwater development
and/or diversion using
Navajo Reservoir storage
Same as I
Diversion using all
available Navajo Reser-
voir storage and exten-
sive groundwater develop-
ment
-------
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 constraints 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 are unique in this study,
as they 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, Fort 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.
The Yellowstone River is presently being stuided for inclusion
in the Wild and Scenic Rivers Section, because it is still free-
flowing. It if is so designated, severe restrictions will be placed
597
-------
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
the State of South Dakota and art 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 presently being used for a variety of uses, with agriculture
being the largest 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.
598
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Developments in the water use of Platte River water will be
closely monitored by Nebraska, and significant increases in con-
sumptive 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, Fontanelle
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 Fontanelle 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 Strawberry - Duchesne Rivers. In general,
the Green River is seen as a probable source of water for the Utah
energy requirement, with excellent storage capacity in Fontanelle
and Flaming Gorge Reservoirs.
599
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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 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
600
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by coal conversion plants. These are the San Juan River and ground-
water. 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 minimg 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. 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
State Engineer, who is concerned primarily with quantities of water,
and the New Mexico 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 Navajo
601
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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 it is essentially the entire
Colorado River drainage of New Mexico, it is the San Juan River
and drainage from which New Mexico receives its allotment of Colorado
River water.
The low level and medium level of demand scenarios, calling
for 40,000 AF/year, 100,000 AF/year, would probably come from the
Navajo Reservoir on the San Juan River, with groundwater sources as
a supplement.
The high demand scenario of 140,000 AF/year could also be supplied
primarily from the Navajo Reservoir, 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 com-
plications in supplying the high demand scenario, due to institutional
problems of water transfer. It is not known at this time to what
extent groundwater can serve as a source for the water demand.
602
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6.4 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 interstat rivers and piped to the point of
intended use; developed from groundwater reserves; or a combination of these.
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. Sub-regions in this category include
the following:
1. Yellowstone River Mainstem
2. Missouri River Mainstem
3. North Platte River
4. Upper Green River
5. Upper Colorado Mainstem
Although overall water availability is generally favorable within these
regions, individual plant sites may be located considerable distances
603
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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 the Western Dakotas
are located in regions with these characteristics. These sub-regions
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.
604
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7. REFERENCES AND DATA SOURCES
Harza Engineering Company, 1976, "Analysis of Energy Projections
and Implications for Resource Requirements".
Missouri River Basin Commission,1976, "Yellowstone Basin and
Adjacent Coal Area Level B Study - Depletion Report".
Montana Department of Natural Resources and Conservation, 1975a,
"Water Use in Montana",Inventory Series Report No. 13.
,1975b, "Yellowstone River Basin - Water Resources Situation
Report".
,1976, "The Framework Report, A Comprehensive Water and
Related Land Resources Plan for the State of Montana".
,1977, "The Future of the Yellowstone River?"
North Dakota State Water Commission, 1968, "North Dakota Interim
State Water Resources Development Plan", Information Series No.8.
Northern Great Plains Resources Program, 1974, "Water Work Group
Report".
,1974, "Water Quality Subgroup Report".
Upper Colorado Region State-Federal Interagency Group, 197],
"Upper Colorado Region Comprehensive Framework Study , Appendix X,
Irrigation and Drainage".
U.S. Bureau of Reclamation, 1974, "Alternative Sources of Water in
Prototype Oil Shale Development - Colorado and Utah".
U.S. Department of Commerce, National Oceanic and Atmospheric
Administration, 1974, "Climatic Atlas of the United States".
U.S. Department of Health, Education and Welfare, Public Health
Service, 1962, "Standards for Public Drinking Water Supplies".
U.S. Department of Interior, 1971a, "Index of Surface-Water Records
to September 30,1970 - Missouri River Basin", Geologic Survey
Circular 656.
, 197]b, "Index of Surface-Water Records to September 30,
1970 - Colorado River Basin, "Geologic Survey Circular 659.
,1973,"Final Environmental Impact Statement for the
Prototype Oil Shale Leasing Program, Vol. I", U.S. Gov't Printing
Office, Washington, D.C.
, 1974a, "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.
605
-------
, 1974b, "Report on Water for Energy in the Upper Colorado
River Basin", U.S. Gov't Printing Office, Washington, D.C.
, 1975a, "Westwide Study Report on Critical Water Problems
Facing the Eleven Western States", U.S. Gov't Printing Office,
Washington, D.C.
U.S. Geological Survey, 1964, "Generalized Map Showing Annual
Runoff and Productive Aquifers in the Conterminous United States",
Hydrologic Atlas HA - 194.
, 1965,"Preliminary Map of the Conterminous United States
Showing Depth to and Quality of Shallowest Ground Water Containing
More than 1000 ppm Dissolved Solids", Hydrologic Atlas HA-199.
, 1975a, "The Role of Groundwater in Resource Planning in
the Western United States", Open File Report 74-125.
, 1975b, "Water Resources Data for Colorado", U.S.
Gov't Printing Office, Washington, D.C.
, 1975c, "Water Resources Data for New Mexico1', U.S.
Gov't Printing Office, Washington, D.C.
, 1975d, "Water REsources Data for Montana", U.S. Gov't
Printing Office, Washington, D.C.
, 1975e, "Water Resources Data for Utah", U.S. Gov't
Printing Office, Washington, D.C.
, 1975f, "Water REsources Data for Wyoming", U.S. Gov't
Printing Officw, Washington, D.C.
, 1977, "STORET Data Retrieval System Printout".
Water Purification Associates, 19676, "An Assessment of Minimum
Water Requirements for Steam-Electric Power Generation and Synthetic
Fuel Plants in the Western United States, 1976.
Wyoming State Engineer's Office , 1971, "Compacts, Treaties and
Court Decrees".
Wyoming State Engineer's Office and Wyoming State Water Planning
Program, 1973, "Wyoming Framework Water Plan'1.
606
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APPENDIX A
SUMMARY OF STATE WATER CODES
A.I Upper Missouri River Basin States
Wyoming
The Appropriation System is used in Wyoming exclusively for
water administration. The Wyoming State Engineer is the person
responsible for handling this procedure, and for ensuring that
all water is used in accordance with set priorities and conditions.
Generally, the procedure for obtaining a water right is as
follows: the prospective user files an application for a permit
with specific maps and plans with the State Engineer;, the priority
date being established when the State Engineer accepts the application
At the time that the permit is granted by the State Engineer, dates
are set for the construction and completion of the facility and the
commencement of water diversion. Usually, project construction
must be completed within five years of the date of project approval,
with the possibility of extension of the completion deadline by
the State Engineer for good cause. When the water specified in
the approved permit application is put to beneficial use, and the
required notices are filed, the State Board of Control will issue a
certificate of appropriation which is the final step in the granting
of a decreed water right. In some instances, a water right is recog-
nized in Wyoming as being attached to the land. Transfers may take
place with the approval of the Board of Control.
607
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There is a rank ordering of the beneficial uses in Wyoming,
indicating which categories of use are preferred over others.
Agriculture, the use consuming the greatest amount of water, is
relatively low on the list, as domestic, municipal, stream power
plants, transportation, and industrial uses of water are preferred
to it. The meaning of preference in beneficial uses is simply that
transfers from a use lower on the list to a use higher on the list
are more easily handled and encouraged than other types of transfers,
and in some cases, preferred uses may condemn the rights put to
inferior use. In fact, almost any use to which water is put that
benefits somebody in the slightest way is considered a benficial
one. An important exception to this is instream flow which at present
is not considered a beneficial use.
Because most of the water is presently in agricultural use, and
agricultural uses are so low on the list of preferred uses, most of
the water transfers would probably come from agricultural-industrial
transfers if no new water supplies are developed. Agricultural water
is, in some cases, tried to the land upon which it is used. It may
therefore be necessary to purchase the land in order to acquire the
water.
Because of the time requirement for the perfection of completion
of decrees, there are relatively few permits for the construction
of diversion facilities which are still outstanding, i.e., being
completed. Thus, a dynamic, rapidly changing situation exists
currently in the Wyoming water resources picture with respect to
the availability of presently undeveloped and undecreed water.
608
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Montana
Montana has, since 1973, a permit system for the orderly
management of its water rights. Before 1973, even through Montana
followed the appropriation doctrine, there existed no centralized
water management and administration authority in Montana. Water
rights were only erratically, if at all, recorded at local county
courthouses, and there was no legal requirement to have them recorded.
The procedure used in establishing a water right is set in
the Montana Water Use Act Regulations of 1973 and is described here.
After application to the Montana Department of Natural Resources
and Conservation, a permit is issued following ascertainment that
the Water Use Act Regulations are met. After the water is put to
beneficial use, and the Department has inspected in order to determine
completion of appropriation, a certificate of water right is issued.
It should be noted that certificates are issued only in areas where
the existing rights have already been established and recorded.
This is significant, because until 1973, no water rights had
received this treatment, and the process is still unfinished, as
the Department of Natural Resources and Conservation is in the process
of recording all existing water rights and filings.
In an attempt to gain time for the State agencies to complete
their planning programs, the 1974 Montana Legislature enacted a
3-year moratorium on Yellowstone River Basin diversions greater
than 20 cfs (14,000 AF/Year). Developments in the near future
are anticipated as the moratorium terminates on July 31, 1978 after a
six month extension.
609
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Of general interest to those involved in water supply will be
the final outcome of the Intake vs. Yellowstone River Compact
Commission court case. Essentially, the Intake Water Company is
a firm seeking to perfect a large water right near Intake,
Montana for purposes including the marketing of water, possibly
to out-of-state customers. The Yellowstone River Compact Commission
is seeking to deny this permit, and the Intake Water Company is
in the process of appealing through the courts. It is anticipated
that the outcome will have significant effects of future interstate
water marketing efforts.
Generally, water must be diverted for beneficial use, which,
in Montana, has a broad difinition. The use of water for slurry
pipelines exporting coal from Montana, however, is not a beneficial
use, by act of the Montana Legislature. Instream water use, on
the other hand, is recognized as a beneficial use in Montana.
Transfers of water with respect to use, location, and ownership are
permitted if Department of Natural Resources and Conservation
approval is obtained. Groundwater is, in general, handled in much
the same manner as surface water.
North Dakota
The water administration system of North Dakota incorporates
aspects of both the appropriation doctrine and the riparian code.
Originally riparian rights were the water law of the State; in
1955 the State Legislature enacted the irrigation code which is the
basis of the current appropriation doctrine. It recognizes the
610
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riparian rights which were established before 1955, e.g., rights
belonging to those who owned land adjacent to the water body, and
in keeping with the "reasonable use" requirement.
To appropriate water, an application for appropriation is
made to the State Engineer. If water is available and the approval
is not "contrary to the public interest," the permit is approved,
and a completion time is set. The final license is issued after
inspection by the State Engineer for the amount of water actually
applied to beneficial use. The actual beneficial use is the basis
and measure of the water right. Transfers can take place with the
approval of the State Engineer.
611
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A. 2 Upper Colorado River Basin States
Colorado
Colorado has a unique form of the appropriation system in which
the judiciary is incorporated in the administration and establishment
of water rights. The Colorado State Engineer is responsible for
the enforcement of the decisions made in the VJater Court system.
When a water right is to be established, the plans for the
diversion and beneficial use are presented to the water court.
After determination is made that other parties will not be damaged,
a "conditional decree" is granted for a diversion of a specific
amount and location. A requirement for the continuation of the
conditional decree is "due diligence" - i.e., some progress towards
constructing the facility and putting the water to beneficial use.
With the completion of construction, the decree "is "perfected," or
made final, in a court adjudication, and the seniority date of the
decree is that date when the conditional decree was granted. This
permits long-term projects to be undertaken with the firm assurance
of a priority date and water supply. This system also permits
speculation to take place with conditional permits, which tends to
inflate drastically the price of undeveloped water.
Transfers in ownership, location, and point of use are made
through the courts; with the primary factor under consideration being
that other user, both senior and junior, are not adversely affected.
612
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Actual beneficial use is the basis, measure, and limit of the water
right.
Groundwater tributary to a surface stream is administered
in the same manner as surface water. The State Engineer exercises
control of groundwater that is non-tributary to surface waters,
i.e., deep aquifer systems, to a much greater extent.
New Mexico
The State Engineer of New Mexico plays a dominant role in the
administration of the water of the State. The Appropriation
doctrine is followed in New Mexico, with actual beneficial use as
the basis, measure, and limit of the right to divert and use water.
Generally, the State Engineer handles the entire procedure of water
rights administration and establishment, from permit application to
final adjudication of the water right, including hearings and pro-
tests from existing water users. The decisions of the State Engineer
may be appealed to the appropriate district court; in fact, this is
rarely done. Transfers are handled by the State Engineer in essen-
tially the same manner as described above for the establishment of
new water rights.
Utah
Utah uses a permit system of water rights following the
Appropriation docutrine. A permit date is granted at the time when
the application is first received in the State Engineer's Office.
The application is approved after notice publication, opportunity
for protest, and a hearing of all interested parties in the State
613
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Engineer's Office. All of the State Engineer's decisions can be
reviewed by the District Court, which is also responsible for adjudi-
cating all rights in each drainage basin. Because applications have
a value determined by their date, they are marketable; this is
encouraged because of the possibility of change of point of diversion,
point of use, and type of use. Additionally, there are a large
number of permits applications which have been filed, but not
approved, implying a very active market in water speculation.
614
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APPENDIX 15
COST OF SUPPLYING WATER TO CHOSEN SITES
INTRODUCTION
The degree to which dry cooling is used in a coal conversion plant is
mainly an economic one and depends primarily on the cost of water . The cost
of water is equal to the cost of transporting water to the site as well as the
cost of water treatment and disposal of any blown down streams. 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 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. In this appendix the costs of transporting water by pipeline
to all of the coal conversion sites in the Western states are estimated for a
number of different water supply options.
SUPPLY WATER COSTS
The cost of transporting water by pipeline over long distances is dependent
on the costs associated with the construction of the pipeline itself and the
costs associated with pumping water through the pipeline. There have been
quite a number of excellent studies defining the economics for water conveyance
615
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systems including those of Singh and Tyteca . For convenience we have used
Singh's classification of the cost elements of the conveyance system. However,
we have derived a simple, yet accurate model to illustrate the important
features of the economics.
The three principal costs of transporting water are the pipeline construc-
tion cost, the cost of pumping water through the pipeline, and the cost of the
pumping stations. We have neglected the pipeline and pumping station operation,
maintenance and repair costs and the easement cost, but have included insurance
and tax costs in the annual cost.
Pipeline Construction Costs
The pipeline construction costs include the cost of the pipe material,
labor for installation, excavating, backfill, contingencies and valves and
other appurtenances integral to the pipeline. Allowance was also made for
landscaping and environmental enhancement. Extra costs for going under or
over roads, railroads, rivers or bridges are not included. The pipeline
construction costs are approximated by
Cc = kc D L (1)
where
k = pipeline construction costs, in $/in(diameter)-mile
D = inside pipe diameter, in inches
L = length of pipe, in miles.
We have obtained data from three sources. Stone and Webster has estimated
costs for a 12 inch diameter pipeline in the Wyodak, Wyoming area . The line
was designed for a water flow of 2,200 gpm (3.2 x 1Q6 gpd) and runs for about
3.8 miles. The total cost was estimated to be approximately $1Q6 and represents
about $22,000/inch(diam)-mile. Pipelines of this nature cost in the range of
$20,000 - $30,000/inch(diam)-mile.
Data for a 1972 Bureau of Reclamation study on buried aqueducts and data
from the North Central Power study are presented in Figure A15-1 where
the installed cost in terms of $/inch(diam)-mile is shown as a function of
616
-------
40
30
D
0
O
OJ
9
20
o
o
o
D
a
D
a
D
o
10
9 REF. 5
a REF. 6
30
40
60
70
80 90
D(IHCHES)
100
no
120
130
140
-------
aqueduct diameter. These costs include the interest charges during construc-
tion and the cost of the pumping stations. The costs from Ref. 6 are based on
1975 costs. The data seem to group according to pipe diameter. For pipe
diameters less than 84 inches, k is approximately $21,000/ inch(diam)-mile;
while for pipe diameters larger than 84 inches, k is about $32,000/inch(diam)-
c
mile. For the present study we have assumed an installed cost of k = $25,000/
C
inch(diam)-mile.
Another interpretation of the data presented in Figure A15-1 is that k
is a function of D. For example, if k ^ D , then C = ALD . The data in
c 2 c
Figure A15-1 give A = 7600 and a = 0.30. Singh uses values of A = 2160 and
a = 0.20. However, as we discussed above, for the present study we used Eq.(1)
with k = $25,000/inch(diam)-mile.
c
Annual Pipeline Construction Cost
We have taken a fixed annual charge rate to be applied to the pipeline
construction costs. This rate includes the interest rate on capital and the
insurance and tax rates. The annual pipeline construction cost is
P = y k DL (2)
c c c
where
y = annual charge rate on pipeline construction costs
Annual Pumping Cost
We have sized the pipelines and pumping plants to deliver a constant
daily water demand Q = 1.50 , where O are the maximum daily plant water
requirements (expressed in terms of million gal/stream day), over a period of
X days corresponding to a plant load factor of N. For the examples given in
this section, N = 0.91 corresponding to 333.3 days or 8000 hrs. The annual
pumping cost is given by
P = 1.15xl03 k OH N
p P* T (3)
618
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where
k = cost of energy, in $/kw-hr
H = 984.8 fLV2 + H
N = plant load factor (4)
f = Mannings coefficient of roughness
Q = flow rate, in mgd
V = flow velocity in pipe, in ft/sec
H = static head, in feet of water
E = pump efficiency
The flow rate is rela _d to the flow velocity by
-3 2
Q = 3.54 X 10 D V (5)
Pumping Station Cost
We have used a simplified form of the cost function of Singh for
2
the pumping station cost. Singh assumed that a single pumping station
will increase the pipeline pressure to no more than 300 feet of water.
The cost of a single pumping station is $[17,000 + 135WJ when W is the
total installed horsepower when the head is 300 feet. If the total head,
H , exceeds this limit, more pumping stations are required. For convenience
the total capital cost of the pumping station is taken to be
C = [17,000 + 135W] JT
PS 300 (6)
where
W = 68.3 Q/E , in hp (7)
*The standby factor in Ref. 2 has been taken as 1.30 and the
storage capacity has been taken as 0.
619
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Annual Pumping Station Cost
We have taken a fixed charge rate to be applied to the cost of the
pumping station. It includes the interest rate on the capital cost, and
the insurance and tax rates,
where
P = y (56.7 + 30.8 H (8)
ps *p E T
y = annual charge rate on pumping station costs
P
Pipeline Operation, Maintenance and Repair Cost
Based upon the cost functions defined in Ref. 1, the pipeline operation
maintenance and repair cost is not more than 5 percent of the annual pipe-
line construction cost if the amortized rate is greater than 6 percent and
the pipeline diameter is greater than 24 inches. These costs have been
neglected in the present study.
Easement Cost
Based upon the cost functions defined in Ref. 1, the easement costs
do not exceed more than 2 percent of the pipeline construction costs for
pipe diameters greater than 24 inches. Those costs have been neglected in the
present study.
Pumping Stations Operations: Maintenance and Repair Cost
Based upon the cost functions defined in Ref. 1, these costs do not
exceed 6 percent of the annual pumping station costs. These costs have
been neglected in the present study.
Total Annual Cost
The total annual cost of transporting water by pipeline is given by
620
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p = p + p + p
c p ps (9)
. , _ , 3 k QH N
= y k DL + 1.15 x 10 p* T
c c -ฃ -
+ yp(56.7 + 30.8 )HT
Cost Optimization
The factors that directly influence the annual pipeline costs are the
length, diameter, flow rate and the static head, or slope of the pipeline.
Other factors such as the annual charge rates, or friction coefficient, and the
pump efficiency are parameters that are fixed once the materials of construc-
tion, pumps, money market, etc. are known. The length of the pipeline and
static head are considered known. Thus the total annual cost can be considered
to be a function of the flow rate and pipe diameter. Furthermore, the flow
rate is defined for a particular plant.
It is clear from Eq. (9) that the total annual cost has a minimum. The
capital cost of the pipeline varies directly as D, while the pumping and
pumping station costs are proportional to 1/D for a fixed flow rate Q. The
latter two costs are also proportional to the slope of the pipeline H/L.
Figures A15-2 and A15-3 show the total annual cost (expressed in terms of
$/1000 gal-mile) as a function of pipe diameter for a particular set of conditions
For the particular example shown in Figure A15-2 , the diameter of the pipeline
that gives the minimum cost is D = D = 20.3 inches with a flow velocity of V
m
= V =6.7 ft/sec. The total annual cost increases more rapidly for diameters
m
smaller than D than for diameters larger than D . The friction pumping costs
m m
dominate the total costs for the former case while the pipeline construction
costs dominate for the latter case. For the particular example the costs of
pumping against the static head are very small. The effect of changing Q on
the total annual cost is shown in Figure A15-3.
The minimum or optimum cost is found by setting the derivative of Eq. (9)
with respect to D (keeping Q constant) equal to zero. The pipe diameter and
velocity for which the total cost is a minimum are
621
-------
10
-1
to
c:
o
CO
O
O
O
00
8
3x10
-3
PUMPING STATION -
PUMPING (FRICTION) COSTS
k = $25,000/inch (diam.) mile
y = 0.10
J
PIPELINE
CONSTRUCTION
COSTS
$0.02/ Kwhr
3000 feet
6.7 ft/sec
90.6 inches
PUMPING (ELEVATION)
0.1
1.0
D/D
M
Figure A15-2 Total annual costs for transporting water
as a function of pipe diameter.
622
-------
\\\ PUMPING STATION -
. , vm 0M \\\ PUMPING (FRICTION) COSTS
(mgd) (ft/sec) (inch) \\\
\
25,000/in (diam.)-mile
\ \ TOTAL .<,
0.016
0.80
$0.02/Kwhr
0.91
3000 feet
50 mile
\ PUMPING (ELEVATION)
PIPELINE '
CONSTRUCTIOiV
3x10
0.1
D/D
M
Figure A15-3 Effect of flow rate on the total annual costs
of transporting water.
623
-------
Ey k \ 1/6
m ~ \ k NfG
where
G = ! + 2^0268 p
N p
The minimum costs are given by
V = 0.0368 ' ~ ~ ' (11)
P = y k D L (13)
c c c m
[
'
P r k NG
P +P = -=^- 1 + 5.75x10 ~ -ฃ (14)
p ps 5 L D Ey k
1 m c c I
It is interesting to note that if the static head is zero (or if the
second term in Eq. (14) is small), the minimum cost occurs when the costs of
pumping and pumping stations is 1/5 of the annual pipeline construction cost,
or 1/6 of the total annual cost. This was found by Singh on the basis of a
more detailed cost analysis. Furthermore, for the cases that we are going to
consider, the function G is relatively insensitive to Q, so that the flow
velocity in the pipeline corresponding to the minimum annual cost is also
insensitive to Q (Figure A15-3).
Table A15-1 lists the values of the cost parameters used in the present
study.
624
-------
TABLE A15-1 COST PARAMETERS USED IN THE PRESENT STUDY
k
c
k
P
y
c
f
E
N
$25 , 000/inch (diam) -mile
$0.02/kwhr
y = 0.10
P
0.016
0.80
0.91
With these values Eqs. (10)-(14) become
= 6.50 -\/Q (15)
V =6.68 ft/sec (16)
m
G = 1.15 (17)
Pp + Pps = PP + Pps/QL = ^^ 11 + 0.0093,/Q -I (19)
0.0576 -5 H_
L
where P is the minimum cost expressed in $/1000 gal-mile. The first term of
Eq. (20) is the annual cost of pipeline construction, pumping stations and
pumping against friction while the second term is the annual cost of pumping
against a static head. Figures A15-4 and A15-5 show the cost of transporting
water. The capital and pumping (friction) costs does not include the cost of
pumping against a static head. The static head pumping costs are given in the
lower part of the figures and should be added to the capital and pumping
(friction) costs to arrive at a total annual cost. In general, the static
head pumping costs can be neglected with respect to the other costs.
625
-------
K)
O1
-------
3.5
3.0
2.5
2.0
O
O
O
1.5
1.0
0.5
k = 25,000/in(diam.)-mile
yc =
f =
N =
ฃ -
k -
0.016
0.91
0.80
$0.02/Kwhr
40
H = 0
Q = 50 mgd
H = 3000'
PUMPING COSTS H = 1000'
1
80 120 160
DISTANCE (miles)
200
240
Figure A15-5 Water supply costs.
627
-------
Sensitivity Analysis
The effects of variable interest rates, pipeline installation costs and
power costs on the unit cost of water are shown in Figures A15-6, A15-7 and
A15-8 respectively. The interest rates were varied from 6% to 14% per year,
pipeline installation costs were varied from $20,000/inch(diam)-mile to
$40,000/inch(diam)-mile, and the power costs were varied from $0.01/kw-hr to
$0.04/kw-hr. Eqs. (10) and (12) were used to compute the pipeline diameter
and Eqs. (13) and (14), rewritten in terms of $/1000 gal-mile, were used to
compute the minimum cost. However, the last term in Eq. (12) was neglected in
the calculation.
Furthermore, if we neglect the second term in Eq. (12) so G = 1, then the
effect of varying the above parameters can be conveniently shown, as follows
1/6
5/6 1/6 IT =
Jc P / V
c 5/6 5/6 k 1/6
c c p
The cost of pumping against a static head is given by k H/L.
Increasing the interest rate from 10% per year to 12% per year and from
10% per year to 14% per year increases the total cost 16% and 32% respect-
ively. If the pipeline installation cost is increased from $25,000/inch(diam)-
mile to $30,000/inch(diam)-mile and then to $40,000/inch(diam)-mile, the total
cost is increased by 16% and 48% respectively. Similarly, if the power cost
is increased from $.02/kw-hr to $0.04/kw-hr, the total cost is increased by
11%.
2
The results of the present study were compared to those of Singh . The
Comparison with Other Analysis
The results of the presen
major difference between the two analyses is that the effective values of k
c
are very different. For examples, in the present analysis k = $25,000/inch(diam)
mile and was taken to be constant. In the analysis of Singh, k varied with
the diameter of the pipe, i.e., k = 2160 D ' . For D = 24, k = 3900 and for
c c
D = 60, k = 4900. These values of k will lead to a factor of about 4-5
*-- C
lower in the optimized total annual cost as compared to our analysis.
628
-------
10
-1
Oi
CAPITAL AND PUMPING (FRICTION)
COSTS
24'
~1I1 I I I
N = 0.91
f = 0.016
E = 0.80
kp - $0.02/Kwhr
- $25,000/in
(diam.)-mile -
(O
en
O 10
O
O
GO
O
O
-2
50
0.06 -
H/L - 25 ft/mile
PUMPING (ELEVATION) COST
10
-3
10
100
Q, FLOW RATE (mgd)
Figure A15-6 Effect of interest rate on unit cost
of water supply
629
-------
10
-1
CAPITAL AND PUMPING (FRICTION)
COSTS
0=12
OJ
24"
C1
o
o
CO
o
o
10
-2
36"
~ I I I I
N = 0.91
f - 0.016
E - 0.80
k = $U.02/Kwhr
50
43"
40,000
35,000 -
30,000
25,000
^$20, OOO/in'
(diam.)
mile
H/L = 25 ft/mile PUMPING (ELEVATION) COSTS
10
-3
10
Q, FLOW RATE (mgd)
Figure A15-7 Effect of pipeline construction cost
on the unit cost of water supply.
100
630
-------
10
-1
(D
i
i
IS)
c
o
ro
CD
o -in-2
o I U
CO
o
CAPITAL AND PUMPING (FRICTION)
COSTS
.D = 12 inches
H/L - 25 ft/mile kp = $0.04/Kwhr
PUMPING (ELEVATION) COST
0.04
0.02
k = $0.01/ '
p Kwhr
10"
0.02
0.01
i i l i i
100
Q, FLOW RATE (mgd)
Figure A15-8 Effect of power cost on the unit cost
of water supply.
631
-------
The results were also compared to the design and cost estimates of the
Montana-Wyoming aqueduct study of the Bureau of Reclamation. The cases that
were selected for comparison had a constant flow capacity through the pipe-
line, i.e., there are no flow diversions and the pipeline diameter is constant.
The following quantities were used in their study: y = 0.0426, N = 0.9 and
c
k = $0.004/kw-hr. The results are compared in Table A15-2. On the lefthand
P
side of the table are the values used in Ref. 5; on the righthand side are
derived values calculated from the basic data. The water costs do not include
basic charges to purchase water. For example, k is derived from the invest-
ment cost and the length and diameter of the pipeline. The static head is
calculated from the difference between the total dynamic head and the friction
head. The values of D and'V are calculated from Eqs. (10 and (11) and the
m m
optimized costs are obtained from Eqs. (13) and (14). The nominal pipe diameter
is always greater than the calculated value of D to minimize pumping costs
m
('Figure A15-2). The optimized total costs are consistently lower, but
fairly close to the water costs as estimated by the Bureau of Reclamation.
The last column is the product of the optimized total water cost in C/1000
gals-mile and y/Q and should be equal to 2.2 for k = 25,000. The differences
v c
are due primarily to the different values of k , with some differences attri-
c
butable to the costs of pumping against a static head.
In summary, the simplified model that we have proposed qualitatively
predicts the behavior of the design parameters and quantitatively predicts the
annual cost of transporting water by pipeline. It appears that the estimated
cost of installing pipelines in the West ranges from $20,000 - $30,000/
inch(diam)-mile.
SITE STUDIES
The site studies on water transport and water availability are broad in
geographical scope, encompassing eight sites each in Montana and North Dakota,
nine sites in Wyoming, and three sites in New Mexico. The water conveyance
systems were sized and layed out to serve a single plant or a complex of
632
-------
TABLE A15-2. ANALYSIS OF BUREAU OF RECLAMATION AQUEDUCT DATA"
Annual Water Investment Total Water Total Water
Delivery H Cost Cost Costซ/1000
Origin- Capacity L D T
Terminal (mgd) (10 gals/hr) (mile) (inch) (ft) ($10 ) (5/1000 gals) gals-mile)
Hoorehead
Reservoir-
Gillette 48.4 16.9 52 51 1383 53.5 0.17 .33
^ Hoorehead
-------
plants. The plants were sited from a minimum of one mile from the water
source (Decker mine from Upper State Line Reservoir) to a maximum of 290 miles
(East Moorhead mine from Boysen Reservoir). It has been assumed that water
will be delivered in harmony with existing water laws and water rights.
Water Supply and Requirements
The area encompassing the chosen mine locations was subdivided into the
following river basins (cf Appendix 14) :
Powder River Basin
Tongue-Rosebud River Basins
Heart-Cannonball River Basins
Belle Fourche-Cheyenne River Basins
Green River Basin
North Platte River Basin
Yellowstone-Missouri River Basins
San Juan River Basin.
Table A15-3 lists all of the mine locations with respect to the seven river
basins.
The most important water sources for each of the river basins were
selected based on present and potential reliable water supplies. Potential
developments of water supplies for coal-related industrial and agricultural
uses in the Western coal bearing regions have been studied extensively
( Appendix 14 and Refs. 6 to 11) . Present and potential water supplies
which could be developed for industrial use, on an annual firm basis, are
shown in Table A15-4.
The water requirements for each plant-site combination is presented in
Table A15-5 expressed in acre-ft/yr and mgd. At some sites more than one
coal conversion process was considered. The water requirements vary from 2878
acre-ft/yr (2.6 mgd) to 11,082 acre-ft/yr (9.9 mgd) with an overall average of
4872 acre-ft/yr (4.4 mgd).
634
-------
TABLE A15-3 MINE LOCATIONS WITH RESPECT TO RIVER BASINS
Powder Tongue- Heart - Belle Fourche Green North Yellowstone
River Rosebud Cannonball - Cheyenne River Platte - Missouri
Basin River Basins River Basins River Basins Basin River Basins River Basins
Lake-de-
Smet
Spotted
Horse
East
Moorhead
Decker Slope Gillette Jim Hanna
Creek Bridger
Otter Dickinson Antelope Kemmerer
Creek Creek
Foster Bentley Belle Ayr Rainbow
Creek #8
Pumpkin Scranton
Colstrip
Beulah
Knife R.
Williston
Underwood
U.S. Steel
Coalridge
San
Juan River
Basin
Gallup
We sco
El Paso
-------
TABLE A15-4 WATER SOURCES AND SUPPLIES FOR SITE STUDIES
ON AN ANNUAL FIRM BASIS IN ACRE-FEET PER YEAR
Powder River Basin
Lake-de-Smet
Moorhead Reservoir
Lower Clear Creek Reservoir
Bighorn River
Hole-in-the-Wall
Crazy Woman Creek Reservoir
Beaver Creek Reservoir
Boysen Reservoir
Agricultural transfer
Tongue-Rosebud River Basins
Lower State Line Reservoir
Upper State Line Reservoir
Rockwood Reservoir
Prairie Dog Reservoir
Yellowstone River
Bighorn River
Boysen Reservoir
Agricultural transfer
Heart-Cannonball River Basins
Mott Reservoir
Cannonball Reservoir
Thunderhawk Reservoir
Broncho Reservoir
Missouri River
Yellowstone River
Fort Peck Reservoir
Lake Sakakawea
35,000
50,000
50,000
230,000
20,000
67,000
20,000
230,000
15,000
88,000
86,000
45,000
38,000
100,000
100,000
100,000
15,000
22,000
22,000
22,000
22,000
120,000
120,000
120,000
120,000
Continued.
636
-------
Table A15-4 (concluded)
Belle Fourche-Cheyenne River Basins
Beaver Creek
Boysen Reservoir
Bighorn River
Yellowstone River
Agricultural transfer
Ground water
Green River Basin
Green River
Fontanelle Reservoir
Flaming Gorge Reservoir
Yellowstone-Missouri River Basins
Yellowstone River
Missouri River
Lake Sakakawea
Fort Peck Reservoir
Bighorn Lake
San Juan River Basin
San Juan River
Navajo Reservoir
Ground water
20,000
50,000
50,000
50,000
15,000
25,000
750,000
750,000
750,000
220,000
220,000
220,000
220,000
220,000
100,000
100 ,000
637
-------
TABLE A15-5 WATER REQUIREMENTS FOR PLANT SITE COMBINATIONS IN ACRE-FT/YEAR AND (mgd)
Mine
HyGas
Synthane
Lurqi
Biqas
SRC
Synthoil
Wyoming
Gillette (Wyodak)
Lake-de-Smet-Banner-Healy
Antelope Creek Mine
Spotted Horse Strip-Felix Bed
Jim Bridger Mine
Belle Ayr Mine
Hanna Coal Fid (Rosebud #4,5)
Kemmerer
Rainbow #8 Mine
North Dakota
Slope (Harmon)
Knife River
Dickenson
Williston
Center
Bently
Underwood
Scran ton
Montana
Decker (Dietz)
Otter Creek (Knobloch)
East Moorhead Coal Field
Foster Creek
Pumpkin Creek
Coalridge
U.S. Steel, Chupp Mine
Co Is trip
New Mexico
El Paso
Wesco
Gallup
4060(3.6)
3920(3.5) 3260(2.9)
3310(3.0)
4869(4.3)
4340(3.9)
5689(5.1) 5634(5.0)
5634(5.0)
3481(3.1)
7889(7.0)
5620(5.0) 7170(6.4)
4050(3.6)
4050(3.6)
4220(3.8) 5390(4.8)
4646(4.1) 5865(5.2)
5831(5.2)
4101(3.7) 5265(4.1)
' 2587 (2.4)
6020(5.4)
2729(2.4)
3677(3.3)
2878(2.6)
4838(4.3)
2878(2.6)
2926(2.6)
5516(4.9)
3055(2.7)
5561(5.0)
3156(2.8)
3845(3.4)
3071(2.7)
3487(3.1)
5970(5.3)
3391(3.0)
4070(3.6)
-------
Pipeline Routes
The route studies of water conveyance facilities consisted generally
of layouts on one-degree U.S. Geological Survey quadrangle maps of 1:250,000
scale. The routes chosen generally followed existing roads, railways,
rivers and streams. Where this was not possible, routes were chosen to
follow the least difficult terrain. The difference in elevation, or static
head, was taken to be the difference in elevation between the ground surface
at the mine location and the water surface at the source, as obtained from
the U.S. Geological Survey maps. Where water surface elevation was unknown,
nearby ground elevation was used.
Gillette, Wyoming Site Study
As an example, we have considered the cost of transporting water to
Gillette, Wyoming, from sources within the basin and outside of the basin.
Two plants have been sited at Gillette; one utilizes the Hygas process for
coal gasification and has a total water requirement of 3.6 million gallons
per stream day; while the other is an SRC plant for coal liquefaction which
has a water requirement of 3.2 million gallons per stream day. The pipelines
have been sized to deliver 50 percent more water than the daily requirement.
Table A15-6 lists the unit costs of transporting water for each process
(Eqs. (15) to (20)). Water sources for the Gillette mine were selected
(Table A15 - 4) and the water conveyance routes layed out. Figure A15-9
shows the location of the Gillette mine and each pipeline route, together
with the milage and total annual cost (in $/1000 gals). The water require-
ments correspond to those of the Hygas process. Table A15-7 shows the
distance and static head for each source of water, while Table A15-8 shows a
breakdown of the water costs. If individual pipelines provide water to each
plant, then the cost of water will range from $1.20 to $6.17 per 1000 gals.
If a single pipeline would provide water for both plants, then the range of
water costs would be reduced to $0.95 to $3.86 per 1000 gals; the diameter
of the pipeline would be 19 inches.
Figures A15-10 through A15-13 show four other river basins and the
location of one mine under study in each of the basins. Alternate water
sources, together with the pipeline routes, are also shown.
639
-------
TABLE A15-6 UNIT COSTS OF TRANSPORTING WATER TO GILLETTE, WYOMING
Pumping Pumping
Daily Water Pipeline D Capital (Friction) (Head)
Process Requirement Flow Rate m Cost-$/1000 Cost/$1000 Cost/$1000
Type (mgd) (mgd) (inches) gals-mile gals-mile gals-ft
Hygas
SRC
3. 6
2. 3
5.4
3.5
15
12
0.0207
0.0257
0.00414
0.00514
0.000089
0.000089
TABLE A15-7 ROUTE DATA FOR GILLETTE, WYOMING
Water Source
Lake-de-Smet
Lower Clear Creek Reservoir
Crazy Woman Creek Reservoir
Moorhead Reservoir
Bighorn River at Hardin
Boysen Reservoir
Miles City on Yellowstone River
Beaver Creek Reservoir
Hole-in-the-Wall Reservoir
Distance
(miles)
72
62
45
60
180
200
170
84
100
Static Head
(feet)
0
1000
940
1240
1340
-253
2340
900
0
640
-------
TABLE A15-8 COST OF TRANSPORTING WATER TO GILLETTE, WYOMING
Entries on the Table apply to two processes, thusf Hygas
VSRC
Capital Pumping Pumping
Water
Location Source
Gillette Lake-de-
Smet
Lower Clear
Cr. Res.
Crazy Woman
Reservoir
Moorhead
Reservoir
Hardin on
Bighorn R.
Boy sen Res.
Miles City
on Yellowst
Cost
$71000 gal
1.49
1.85
1.28
1.59
0.93
1.16
1.24
1.54
3.73
4.63
4.14
5.14
3.52
. 4.37
Beaver Creek 1.74
Reservoir 2 . 16
Hole-in-the
Wall Res.
2.07
2.57
v. Friction
$/1000 gal
0.30
0.37
0.26
0.32
0.19
0.23
0.25
0.31
0.75
0.93
0.83
1.03
0.70
0.87
0.35
0.43
0.41
0.51
v. Head
$71000 gal
0
0
0.09
0.09
0.08
0.08
0.11
0.11
0.16
0.16
0
0
0.20
0.20
0.08
0.08
0
0
Total
$71000 gal
1.79
2.22
1.63
2.00
1.20
1.47
1.60
1.96
4.64
5.72
4.97
6.17
4.42
5.44
2.17
2.67
2.48
3.08
Cost
$/acre-ft
583
724
530
652
390
479
520
639
1508
1868
1619
2011
1441
1773
705
870
810
1004
641
-------
.OMILES CITY i;
7(3 (4.4) .,ซ
I'
m^^
O Water Source
Coal Mine
[J Distance, miles -^
M_O_^:A_NA_[_^_^_ ง.. .^_^
|lwyt)MINC -. , p-.
I ) Cost, $/1000 gals
i ' ;', i^.-^.T3-rSr P o
i '.-.^>L;^-B ^'X
.M5-9 Pipeline conveyance routes in the Belle Fourche-Cheyenne
River Basins from various water sources to Gillette,
Wyoming.
642
-------
- I i I :"./ . I ! ^~__- 1 )
' I V J- ' n .J" Ji . ! I "^v - L-r~
-t- 1 ' ---?-_il .-
v L.-. /.:.:',. Y.ซi-
j -1
[GO] (1.28,)
ELLOWSTONE RIVER '
(0.26)
:-^=-O Water Source
, Coal Mine
\ [ JDistance, miles
$A.._.rW . .
;-, -j ( JCost, $/1000 gals
u i_
^I-W- :;
'.I1-'" " i -"- Tv" i
Figure A15-10 Pipeline conveyance routes in the Yellowstone-Missouri
Mainstem River Basin from various water sources to
U.S. Steel (Chupp) Mine, Montana.
-------
/ MILES CITY
~
>=^^ \ri7o] (3.9) -
4" 4S1: t fa v^'-^r^i
rT'--~>\ * i v^~' i ^*." t
Water Source
Coal Mine
1 Distance, miles
( ) Cost, $/1000 gals
MOORHEAD MINE
MOORHEAD RESERVOIR /'
[2oJ (0.59)
._ tj
SPOTTED HORSE MINE -. '_,'
'A,' "'-
LAKE DE SMET
RESERVOIR
[35J (0.99)
[eo] (1.65) dr'^J
HOLE-IN-THE-WALLA.-C i
RESERVOIR
[l04] (2.86
BEAVER CREEK
RESERVOIR
[27ql (7.42)
[130] (3.61)
Figure A15-11 Pipeline conveyance routes in the Powder River Basin
from various water sources to Spotted Horse Mine,Wyoming
644
-------
S E B u D
HARDIN
[
SO] (1.09)
^
I FOSTER CREEK MINE
^
,ii V
'PUMPKIN CREEK MINE f
-*_^
^i* DECKER
'?
/n
I OTTER CREEK
^V1
'-p
,QUPPER STATE LINE
RESERVOIR
[751 (1.62}
r
./.
ROCKWOOD^
RESERVOIR
LOWER STATE LINE
RESERVOIR
O Water Source
ฎCoal Mine
-/ -~TV\ ->
" Ar- V
--. \ I -s. -V-
V
I^IT
-------
en
LAKE SAKAKAWEA
56] (1.49) L.
BRONCHO RESERVOIR
[so] (1.33)
.; , [100
i... . J r' ~tฃ
O Water Source
~^<^S-~^ c*< [_ ]Distance,miles
BENTLY MINE >ฃ_.
SCRANTONV MINE
^^:x LฐXr
~-'. CANNONBALL RESERVOII
[70]
THUNDERHAWK RESERVOIR
Figure A15-13 Pipeline conveyance routes in the Heart and Cannonball
River Basins from various water sources to Dickinson
Mine, North Dakota
-------
Individual Plant Site Studies
We have considered the case of a single pipeline supplying water to a
single plant. We have assumed that the water supply comes from the nearest
reliable water source of sufficient size. Transbasin diversions are presumed
possible. Potential reservoirs have been included as reliable water sources.
In some instances agricultural water was used, but only in those river basins
where it was considered feasible. However, change-of-use permits might be
difficult to acquire.
Table A15-9 lists the mine location, water source and total cost of water
conveyance for the twenty-nine plant locations. The minimum distances 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 $2.54/1000 gals.
Large Scale Water Conveyance
If a large scale coal industry is to be developed in the West, large
quantities of water will be required. In the individual plant site studies
discussed above, a single standard size plant will have water requirements
that vary from 2.4 mgd to 7.0 mgd; the overall average is 4.0 mgd. It is
clear from our previous discussions that a single pipeline will supply, say,
10 standard size plants, at a lower cost then 10 single pipelines, each
supplying a single standard size plant.
We have sized and estimated costs of uniform diameter pipelines having
a constant capacity throughout its length. The water requirements that
were selected are: 50 mgd (56,000 acre-ft/yr), 100 mgd (112,000 acre-ft/yr),
150 mgd (168,000 acre-ft/yr) and 300 mgd (336,000 acre-ft/yr). This corresponds
to the water requirements for 13 standard size plants to 75 plants, based on
an average of 4.0 mgd per standard size plant. The pipe diameters are
respectively: 46, 65, 80 and 113 inches.
The plants were grouped together such that the maximum distance between
two adjacent mines supplied by the same pipe line was 60 miles. The pipeline
provided water from a reliable water supply to a town located approximately
central to the group of mines. One pipeline which linked seven mines situated
approximately in a straight line was also evaluated. Table A15-10 shows
the total cost for a number of mine groupings. We see that the total cost of
647
-------
TABLE A15-9 LOCAL SUPPLY TO INDIVIDUAL PLANTS
Location
Beulah
Williston
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
648
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TABLE A15-9 (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
649
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TABLE A15-10 LARGE SCALE WATER CONVEYANCE COSTS
IjOcation
Midpoint
between Wesco
and El Paso
Highlight
Rock Springs
Gillette
Stanton
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
Ln
O
-------
AB
Concluded)
Location
Stan ton
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
Ye" lowstone 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
01
Ln
-------
transporting water does not exceed $1.63/1000 gals for the cases that we
have considered.
REFERENCES
1. Gold, et al "Water Requirements for Steam-Electric Pour Generation and
Synthetic Fuel Plants in the Western United States", EPA-600/7-77-037,
U.S. Environmental Protection Agency, Washington, D. C. , February 1977.
2. Singh, K.P., "Economic Design of Central Water Supply Systems for Medium
Sized Towns," Water Resources Bulletin, 7_, 79-92, February 1971.
3. Tyteca, D., "Cost Functions for Wastewater Conveyance Systems," Journal
WPCF, 48, 2120-2130, September 1976.
4. Comley, W.D., Private communication, Stone and Webster Engineering
Corporation, Boston, Massachusetts, September 3, 1975.
5. Bureau of Reclamation, "Appraisal Report on Montana-Wyoming Aqueducts,"
U.S. Department of the Interior, Washington, D. C., April 1972.
6. "North Central Pour Study-Report of Phase 1, Vol 2," U.S. Bureau of
Reclamation, Billings, Montana, October 1971.
7. "Northern Great Plains Resources Program-Report of the Work Group on
Water," December 1974.
8. "Powder River storage Development," prepared by Harza Engineering
Corporation for the State of Wyoming, State Engineer's office, Wyoming
Water Planning Program, August 1974.
9. "The West River Study-An Analysis of Alternatives for Developing and
Managing the West River Area's Water and Related Land Resources,"
SWC Project No. 1543, Information Series No. 30, North Dakota State
Water Commission, Bismarck, North Dakota, January 1975.
10. "The Wyoming Framework Water Plan," State Engineer's Office, Wyoming
Water Planning Program, May 1973.
11. U.S. Geological Survey, "Mineral and Water Resources of New Mexico,"
U.S. Senate Committee in Interior and Insular Affairs, U.S. Govern.
Print. Office, Washington, D. C. 1965.
652
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-78-197b
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE Water-related Environmental Effects
in Fuel Conversion: Volume U. Appendices
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 AN
Final; 10/76 -
IRIOD 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.
16. ABSTRACT The repor{- 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 ds-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 DOCUMEN T ANALYSIS
DESCRIPTORS
Pollution
Water Consumpf'
Coal Gasification
Coal
Shale Oil
Liquefaction
Crude Oil
Water Cooling
Waste Water
Wastes
Water Treatment
Waste Treatment
13. DK'Ti-,1 bljTION fa -. tMENT
Unlimited
b.lDEN riFI EPS/OPEN ENDED TERMS
Pollution Control
Stationary Sources
Fuel Conversion
Synthetic Fuels
Coal Refining
Solvent Refined Coal
Solid Waste
19. SECURITY CLASS (This Report)
Unclassified
20. SECURITY CLASS (Tins page)
Unclassified
COSATl Field/Group
13B
13H
2 ID
07D
ISA
21. NO. OF PAT tS
666
22. PRICE
Forn. 3'1.20-1 1--73)
653
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|