&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-«F
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 (39.2°F)
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 » 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 » 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 (°F + 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
acrfi—fee 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 „,.,,,«
square feet
temperature, °C
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 °F
"C
tons/day
tons/year
gallons of water/minute
millions gals of water/day
pounds
metric tons
thousand pounds/hour
thousand pounds/hour
Btu/hour
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
= °'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 °F 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 50°F, so the moles/hr
HO in the exit gas, M' is given by:
2
-------
°-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 160°F.
6) Stack losses are 12 percent of the fired preheater duties.
7) Cooling loads involve cooling the flashed gas, water and light oil
from 550°F to 100°F 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 100°F 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)(°F) over
a range of 2400°F, 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 )
£•
-------
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. The•dry 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 Lignite—Process 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
550° 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 section—A.
-------
STEAM \1
SRC
SOLUTION
FROM
SECTION A
WASH SOLVENT
TO FILTER
VENT
RECYCLE SOLVENT
TO SLURRY BLEND
TANK
SRC
Figure Al-2. SRC dissolving section—B.
-------
FILTER
COAL
TO
SHIFT
REACTOR
SECTION B
6FW
700° F
I5PSIA
r^\
STEAM
X
AS
RUB
r
130°F
WA
INT
COh
TER
RSTAGE
-JDENSATE
265PSIA
SYN GAS
COMPRESSOR
Figure Al-3. SRC hydrogen production by gasification—A.
-------
en
FROM
SECTION A
STEAM
600°F
SHIFT
CONVERSION
REACTOR
750° F
SHIFT
CONVERSION
REACTOR
TO DISSOLVING
1700PSIA' SECTION
HYDROGEN
COMPRESSOR
Figure Al-4. SRC-hydrogen production by gasification—B.
-------
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
C°2
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
C°2
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
f™3
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
2« 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
C°2
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 £ •§
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
« 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
£2
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 «
' *J p 4J
X 0 00
a .* J x
*-* i3 C to
*j a oj o
c »o
4t . C •
m 2: 3 z
.
J^
01
X V
V *-
U O 4)
^ tr.
u o cm -o «
.. S 2 S -25
01 4J a 4J «-! *J
*J C EC < C
4j o go o o
o £ 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
2£
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 £
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 £
S£
1.76
1.26
0.30
3.32
2.53
0.44
0.05
0.18
0.12
3.32
« 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
-< «
£ §
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 «
CT> E
c a
£ -3
£ 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 J£
— i «
0
Q Z
1.71
1.94
0.35
4.00
3.04
0.40
0.11
0.30
0.15
4.00
« 0
c c
I-t r-t
« 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->
±> 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 «
a. -t->
1 0
& £
1.72
2.01
0.37
4.10
3.11
0.46
0.11
0.27
0.15
4.10
V
0*
•o «
"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.
£
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 •
« 2 D 2
X
0)
0)
o
0)
w
a
c
£
u
C d
P
9 o
CM £
(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 « 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 £ 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 £ 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
!§M
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
01
0 C -P
-Q -H V
C E rH
(2 S O
0"
c
-l-l
£
Creek,
H
oj a
a c n
, o
£ o
35
S
0
3.44
„
o ra
£ <
4.32
§ni
jj
tn o
c x
•H fy
•u Q
•H •
O Z
3.91
ffl
- 4-1
oT£
53
0) •
03 Z
•g rt
0 V
0 0
2-S
ai Q
C *
D Z
J<
(1)
U
k
u
M
4)
«
rd
C
id
-------
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 1800°F. 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 900°F
and assumed to be in equilibrium at 950°F.
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 + 15'5°° - 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 300°F, 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
550°F. 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 :
= 25'8°° + 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 1±> 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 300°F 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 140°F 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 Process—Material 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
230° 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~£>rocess water streams in Synthoil process.
-------
COAL
aCHAR
OXYGEN
GASIHER
FUE.L (WHERE REQUIRED)
\ 1800'F
900*f
DIRTY
CONDENSATE
STEAM
CLEAN
COND£NSATE<
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 £rom 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 «
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) ,£
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
Muo«
— —
—
—
—
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
-------
TA»LE 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 %
%£
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
^§
-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
« 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 200°F. 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 400°F 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 750°F to adjust the ratio of hydrogen to CO for the downstream
methanation reaction. The shifted gas is cooled to 100°F 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 100°F)- 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 750°F:
(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
H2°
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 800°F — 0.14
Total heat of effluent
gases at 800°F — 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, 1000°F)
Energy to produce oxygen
Slurry pump
Recycle oil heater
Sensible & chemical heat in ash
residue at 1850°F
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
C°2
"l°
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
C°2
CH4
C2H6
H2°
"2
H2°
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
£g
C
0
m
Vt o
flj j^
H, o
tr>
c
0
M
2
§
>
>,
C
OJ
tt.
"Si
CJ -H
4J
0} jJ
>i 10
a -H
•H M
(0 --!
O AJ
c in
0 0)
£ 2
Q-
O>
c
X
"&
M
>
10
U
1)
-«J 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
' «
)-. C
11 IU
Ji -M
CJ C
01 O
Q £
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 £
u z
°" s
c 3
Jj J5
M >9
j:
8 .
Z §
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 £ >
EC > «
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 £
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
£
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 140°F, with wet cooling
below this temperature. Much the largest part of the load, which is condens-
ing water out of gas streams, occurs above 140°F. 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
§ 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
C°2 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 H2° 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
C°2 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 H2°
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 273°F 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 750°F, 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 225°F, as shown on Figure A5-1, and the balance is condensed at
100°F 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 220°F. 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"?
WAIt»
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 "• §
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 £
4.3
66.4
4.4
14.7
1.0
0.5
8.7
11,200
•Coals with less than 4.3» moisture listed "as-received."
92
-------
TABLE A5-2. FLOW AND ENERGY RATES FOR
REFERENCE SYNTHANE PLANTS
Coal feed0
Oxygen feed®
Steam feed®
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-gas®
Dirty Condensate (5)
Char quench (6J
Steam for Shift®
After Shift®
Condenaate after
Shift®
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-H«H-^>, r-fO^OW «J > Ifl >
4->O OO|-^C'*-IS3J3T3'HT3 O''~'-HIW-H C' C QJ
. .
4-> O QO-HCl*-(S3J3
S>> Q, >• 0 O OJ «-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 (§) ) 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 ° °'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
72.5» 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
C°2
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
C°2
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
C°2
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
H2°
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
H2°
CH4
C2H6
CO
co2
"2
Product HHV, 8.46 x
Scale Factor « 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
H2°
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
C°2
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 « 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
C°2
H2
Product HHV, 4.86 »
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 « 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 140°F 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 600°F to
900°F. 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 115°F and 134°F
respectively. Above 134°F, efficiency falls. We have assumed that below
115°F, 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 115°F, so the procedure adopted in this study, which
is never to cool below 115°F, is reasonably generally applicable when cooling
water is scarce.
The heat rates required when the condenser temperature is in the range
of 115°F to 134°F 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 115°F to a value of 12,200 Btu/kw-hr at the condenser
temperature of 134°F.
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 115°F to 134°F 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 115°F to a value
of 8,700 Btu/lcw-hr at the condenser temperature of 134°F. 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 £ 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 134°F. 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 119°F which is a reasonable and usual 15°F
below the design condensing temperature, and cold water temperature, t , of
94°F. The cold water temperature means that the circulating pumps must be
sized for a 25°F 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) = °-°°5 UD(TC -
(7)
TC - TD,h = (TC - TD,c)(1 - °-°°5 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 °F
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
115°F, then it is controlled at 115°F 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 °F.
When the condenser temperature is controlled at 115°F, 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 30°F, 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 0°F for dry air and liquid water at 32 °F
i± = 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
32°F.
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 115°F 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
37°F approach is chosen. This makes the tower bottom temperature 37° 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 = t° _ 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- = — °_ (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 (£/kw-hr) = (area, ft AW) (cost, £/ft ) (Vyr) (1/7000 hrs/yr)
Electrical energy (C/kw-hr) = (energy, kw-hr/kw-hr)(cost, £/kw-hr)
Fuel penalty (C/kw-hr) = (fuel penalty, Btu/kw-hr)(steam, £/Btu)
Please note that "total costs" (£/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 104°F (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
109°F 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, °R, (°R = 460 + °F)
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, °R(°R = 460 + °F)
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.(r°"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 119°F and 94°F 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 the•calculation 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 = 119°F, T = 109°F, t = 94°F.
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 °F 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 . < 95°F so
cilir
the third stage water cooler is turned off when T <_ 95°F.
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.) _<_ 5°F, 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. < 5°F.
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
£2.106/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
t—H
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
^»
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
i—t
U~l
LU
Q
Z
O
H—I
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
«c
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
«af
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 (°F)
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 (°F)
140
Figure A7-13. Turbine condenser cooling requirements at full load.
152
-------
0 20 40 60 80
AMBIENT TEMPERATURE DROP(°F)
Figure A7-14. Fan power reduction factor for air coolers.
153
-------
AMBIENT
Tr J
15 psia
N
i
27.26 psia
T
3,o =
250°F
\
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 » 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, °F
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, °F
air dry bul_b temperature, "F
air temperature at which dry condenser wi11 carry whole load,
hot circulating water temperature, °F
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 (°F).
**WBT = wet bulb temperature (°F).
158
-------
TABLE A7-5. HEAT TRANSFER COEFFICIENTS, FAN AND PUMP ENERGIES
U[Btu/(hr)(ft )(°F)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
2£/kw-hr
$1.80/106 Btu
p < 300
300 ^ p < 450
450 £ 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 «= 1.24, water/gas rates 2.12,
circulation rate 348 Ib/kw-hr, 0.696 gpm/kw.
Month
10
11
12
Condenser temperature (°F)
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 (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
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 (°F) 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 (°F) 109 108 106 105 104 107 110 109 103 105 107 108
Cold water temperature (°F) 96 95 92 89 85 86 89 89 84 88 93 97
Tower bottom temperature (°F) 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 (°F)
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 (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
Fraction circulating water
that bypasses tower
r , i«~3 kw-hr v
Div fan power (10 )
kw— hr
—3 kw— hr
Coolq tower fan pwr (10 , , )
3 kw-hr
— 3 kw—hr
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 (°F) 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 (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
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 (°F) 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 (°F) —
Cold water temperature (°F)
Tower bottom temperature (°F)
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 (°F)
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 (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
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 (°F) 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 (°F)
Cold water temperature (SF)
Tower bottom temperature (°F)
Fraction circulating water
that bypasses tower
., -3 kw-hr.
Dry tan power (10 —)
-3 kw-hr,
Cooig tower fan pwr ilO )
K W"° H IT
Circulating pump pwr (10*3 —£^) 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 («F) 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 (°F)
Cold water temperature (°F) - —
Tower bottom temperature (°F)
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
}cw™rijr
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 (°F) 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 (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
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 (°F) 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 (°F)
Cold water temperature (°F)
Tower bottom temperature (°F) — — — — — — — — — -- --
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 (°F) 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 (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
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 (°F) 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 (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
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 (°F) 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 (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
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 £——•) 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 (°F) 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 (°F) ~ — -- -- 107 107 109 108 104 114
Cold water temperature (°F) -- — -- — 94 86 88 87 85 112
Tower bottom temperature (°F) ~ — — — 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 (°F)
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 (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
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 (°F) 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 (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
Fraction circulating water
that bypasses tower
-3 kw-hr
Dry fan power (10 •• )
-3 kw-hr.
Coolg tower ran pwr (10 )
• _ ,-, «-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 (°F) 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 (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
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 (°F)
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 (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
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 (°F) 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 (°F) — — — — 108 105 108 107 103 113
Cold water temperature (°F) — -- -- — 96 83 85 85 82 110
Tower bottom temperature (°F) — — — — 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 (°F) 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 (°F)
Cold water temperature (°F) —
Tower bottom temperature (°F) — - —
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 £ 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, °F 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, °F 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 «" 140°F
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'F» 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 " °-
G,2 ° 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 " °
AD,2 ° °
AD,3 " °
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 - 140°F
CD
Design £t2/1000 Ib
ft2/1000 Ib lb/1000 Ib gpm/1000
AD,1 ' 28.156 AW(1 -
AD 2 - 14.334 A
AP/T «• 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 • 160°F
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 « 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.'-, » 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 °
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)
°W1
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 ° ;
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 R°', - 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 • 140°F
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 °
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 - °-
62 - 0.
03 ' °-
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._, « 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 - 180°F
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 12°
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 «• all wet
Design ft /1000 Ib
ADjl - 0 J
AD,2 ° ° J
AD,3 = ° '
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
»,w/1 - 4
\H'2 - 2
S/3 ° 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
140°F
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
»er 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_. » 160°F
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 » 180°F
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 £>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 " °
AD,3 ° °
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 °
00 Ib lb/1000 Ib gpm/1000 Ib
49.178 RL(i - 1050.76 RG(1 » 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 £ 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 £ 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, °F
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, °F
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, °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
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, °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
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 - 3§} - 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 Reclamation—Cordero
Mine, Sun Oil Co., Coal Lease W-8385, Campbell County, Wyoming," Final
Environmental Statement No. 76-22, U.S. Dept. of the Interior, April 30,
1976.
3. North Dakota Gasification Project for ANG Coal Gasification Co.,
"Environmental Impact Report in Connection with Joint Application of
Michigan Wisconsin Pipe Line Co. and ANG Coal Gasification Co. for a
Certificate of Public Convenience and Necessity, Woodward-Clyde
Consultants," 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 1—Plant 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 £ 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 » 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
°-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 -° 103 lb/hr
°-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
«„ 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-° 1Q3 Ib/hr
1S-B 10 Btu/hr
FGD WATER
Vaporized °-56
With sludge °-49
TOTAL:
FGD sludge produced, wet
ASH HANDLING
coal
coal
_°_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 £ 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 °
TOTAL: 0
FGD sludge produced, wet 0
ASH HANDLING
IO3 Ib/hr
Bottom ash: dry 150
water 80.7
sludge 231
Fly ash: dry °
water °
aludqe °
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 £ 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 » 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 »
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 °
water °
sludge °
(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 1±> 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. » 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 °
water °
sludge °
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
» 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 » 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 he«t
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
» 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
» 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 » 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. £>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 £ 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 £ 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 £ 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/l±) 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 » 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 » 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 £ 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
» 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*.,». 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: «9 103 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 lt»/hr
213
351
201
234
43
103 Ib/hr
78
21
14
0
5
1,205
1O3 Ib/hr
solids water £ 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 °-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
OTH£R 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 £ 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 £ 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 £ 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 »
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)
° - 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 o£ 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 » 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
1•59 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 » wet
Ln Direct loss 3.04 0
Designed dxy °-55 °
Designed wet °-4° 10°
Acid gas rejnoval
regenerator condenser 0.80 10
Total turbine condensers 0.67 100
Total gas compressor
interstage cooling °-17 10°
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 0-9°
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
» 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 £ 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 °-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 » 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-°H Ib/Lb coal
°-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:
"° 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-« 0 1,410 0
-J Designed dry °-55 ° i'410 °
*~ Designed wet °-4° 10° L410 28<
Acid gas removal
regenerator condenser °-B° 1° l'410 57
Tot*l turbine condensers 0.67 100 1,410 475
Total gas compressor
Jnterstaoe coolinq °-" 10° 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-°
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 » 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 °-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 »
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 » 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 l±>/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 »
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-°°
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
°-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-° 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
» 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
°-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 °-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 » 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 °-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 °-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 20°
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 °-&7 !° 1,375 49
Total gas compressor
interstage cooling
3.65
-------
WORK SHEET: WATER QUANTITY CALCULATIONS FOR
BIGAS PROCESS
PRODUCT SIZE: 250 X 10° EOF/day
ENERGY: 9.9 x 10 Btu/hr
to
O
Coal Analysis (wt » 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 » 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 £ 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
,nfi«llb/lb coal 0
, ?s Ib/lb coal 129
129
wet 184
10 Ib/hr
103 l±>/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 lo£e , 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 £ 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 £ 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
Ta±.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 §
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
72.1»
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 » 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 £ 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 £ 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-°*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 °-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 £ 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 £ 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 » 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. 5»
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 £ 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 10° 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 °-82 ° 1'410 °
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 .-„,*(„„ ™,,rt«n«.,r« 0.77 100 1,410 546
Total gas compressor
interstage cooling 0.22 100 1,410 156
wrr»r, 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 £ 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 »
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 »)
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 £ 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 _WAT£R
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
OTH£R 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 «
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 1±> 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 £ underground coal mining are the same)
a. Lime softening
b. Ion exchange
c. Biotreatment
0.07
water £ 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 £ 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 » 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 £ 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 £ reverse osmosis
c. Biotreatment
1,934
272
1,925
10' Ib/hr
solids water £ 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 10° 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 7°3
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" "«>tn
( RESERVOIR ")-^-* EVAPORATION ( RESERVOIR )-J1* EVAPORATION
i' " '
3 3
SOFTENER NO. 1 [f> SLUDGE SOFTENING NO.l f^>SLUDGE
n ' 1 . i« iv
BOILE
TREA
FIG.
*5 — « 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 1°
i ' TREATMENT PHENOL ». PHENOL
L» 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 >( « ,„
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 ±> 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 « ' „
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
» 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-» 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
±-
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 « 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 « BOD concentration in mg/1 and Q » 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 20« 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 « 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; «/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
S°4°
Phenol as C^H.OH
6 b
Amoonia * ? NH
BOD
-M-
Ca
Mg**
HCO
ng/1
SRC £ 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
£ 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 £ 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
£ Lignite
600
500
2,000
s
s
1,000
Synthane £ 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
£ 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 » 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
» 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-
S°4~
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~
»9~
HCO/
S°4"
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~
S°4~
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"
S°<"
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 l±>/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 USE£)
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 66'30° 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. 1°80 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. 13° 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
«/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. 2°89 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 US£D
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
£,. 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) : pl£
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
«/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 l±)/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:
«/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-«l <* 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-°
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 :
«/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 «-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
«/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
£lte 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
«/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
v£>
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 ± 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. 1°07 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
«/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
10° 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
k£> 8 537 18. 94 28. 21 39 58
^J
9 537 20. 52° 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 ± 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.
Hyga»
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:
«/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
Oth«r 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
«/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 J£ 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'°°° 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 »of t«ning 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
«/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]« 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
«/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 1°
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
900°F 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 (200°F)
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: F»Favorable, Q»Quest1onable, 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
-------
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 u
|