United States
Environmental Protection
Agency
Office of
Research and
Development
Office of
Energy. Minerals and Industry
Washington. D.C. 20460
EPA-600/7-77-037
April 1977
WATER REQUIREMENTS FOR
STEAM-ELECTRIC POWER
GENERATION AND SYNTHETIC
FUEL PLANTS IN THE
WESTERN UNITED STATES
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of. and development of, control technologies for energy
systems: and integrated assessments of a wide range of energy-related environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA Report Number 600/7-77-037
February, 1977
WATER REQUIREMENTS FOR STEAM-ELECTRIC
POWER GENERATION AND SYNTHETIC FUEL PLANTS
IN THE WESTERN UNITED STATES
by
H. Gold, D.J. Goldstein, R. F. Probstein,
3. S. Shen and D. Yung
Water Purification Associates
Cambridge, Massachusetts
A Subcontract Report to the University of Oklahoma
Science and Public Policy Program for:
Technology Assessment of Western Energy Resource Development
EPA Contract Number 68-01-1916
Project Officer
Steven E. Plotkin
Office of Energy, Minerals and Industry
Washington, D.C. 20460
Office of Energy, Minerals and Industry
Office of Research and Development
U.S. Environmental Protection Agency
Washington, D.C. 20460
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DISCLAIMER
This report has been reviewed by the Office of Energy, Minerals and Industry,
U.S. Environmental Protection Agency, and approved for publication. Approval does
not signify that the contents necessarily reflect the views and policies of the
U.S. Environmental Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
11
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FOREWORD
The authors of this report were given the assignment of determining the
water requirements of several fossil fuel energy conversion technologies at
six sites in the Western United States. It is known that the magnitude of
such requirements is dependent upon plant design; thus, a critical assumption
of the study is that the water use systems are designed by engineers operating
simultaneously as cost-minimizing businessmen and water conservationists. These
two roles are not mutually exclusive in the West, since water is hardly a free
good. However, the price of water to the facilities in question is not so high
that the water requirements presented in the report should be viewed as "minimum"
requirements. Outright shortage of water, substantial increases in water cost,
or restrictive legislation could force the water requirements of the conversion
plants still lower.
The effect of water consumption by energy development on the environment,
lifestyle and economy of the arid American West is a critical issue facing
local, State and national policymakers. It is one of the key issues addressed
by the Office of Energy, Minerals and Industry's "Technology Assessment of
Western Energy Resource Development," a three year study addressing the impacts -
and means of relieving those impacts - of energy development in the Western
United States. The study is being conducted by the Science and Public Policy
Program of the University of Oklahoma, under the management of Professor Irvin
L. (Jack) White. This document is a subcontractor's report to the study, and
will be formally appended to the study's Final Report. Because of our desire
to disseminate important research results to the public as quickly as possible,
we are publishing this report as a separate document.
StepHfen J. Gage
Deputy Assistant Administrator
for Energy, Minerals, and Industry
111
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ABSTRACT
The study describes the procedures for the detailed determination of the
water consumed for mining and processing coal and oil shale, and for determining
the residuals generated. The processes considered are Lurgi, Synthane, and
Synthoil for coal conversion, TOSCO II for shale conversion, coal-fired steam
electric power generation and slurry pipeline. In addition, determinations are
also made of the water consumed for process cooling, flue gas desulfurization,
revegetation of mined land, solids disposal and by evaporation and other uses
within the mine-plant complex. In these determinations it is assumed that there
is no discharge to receiving waters and that there is a reasonably high level of
recycle and reuse of process effluent waters. Wasteful evaporation of waste-
water is not permitted. Economic studies of water treatment are not included
in this assessment except for some of the process cooling studies.
The consumptive water use and solids residuals are determined for a total
of 21 plant-site combinations. The sites are: Beulah, North Dakota; Colstrip,
Montana; Gillette, Wyoming; Kaiparowits/Escalante, Utah; Navajo/Farmington,
New Mexico; and Rifle, Colorado. A detailed breakdown by consumptive water
use category is presented in tabular form for each plant-site combination.
Approximately twenty water use categories are considered. Results are also
presented for three energy development scenarios focused on the Powder River
and Rocky Mountain Regions.
iv
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CONTENTS
FOREWORD iii
ABSTRACT iv
FIGURES viii
TABLES x
CONVERSION TABLE xv
ACKNOWLEDGEMENTS xvii
1. INTRODUCTION AND SUMMARY 1
1.1 Introduction 1
1.2 Summary, of Findings and Conclusions 4
2. COAL CONVERSION PROCESSES 17
2.1 SynthoiJ. Process 17
2.2 Process Water Streams 33
2.3 Cooling Water 38
2.4 Lurgi Process 45
2.5 Synthane Process 48
References 54
3. SHALE CONVERSION 56
3.1 Underground Mining and Surface Processing 56
3.2 TOSCO II Process 57
3.3 Water Streams for Retorting 61
3.4 Water Streams for Upgrading 66
3.5 Process and Cooling Water Consumption 68
References 69
4. STEAM ELECTRIC GENERATION 70
4.1 Costs of Cooling Systems 70
4.2 Comparison of Dry and Evaporative Cooling 78
Systems Not Including the Costs of Water
4.3 Costs of Water 89
4.4 Costs of Wet-Dry Cooling Systems 101
4.5 Water Consumed and Solid Residuals Generated 108
References 114
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5. SLURRY PIPELINE
References
6. FLUE GAS DESULFURIZATION 119
6.1 Particulate and Sulfur Removal 119
6.2 Water in Flue Gas 120
6.3 Water in Waste Solids 124
6.4 Comparison of Present Approach 127
References 129
7. MINING 130
7.1 Categories 130
7.2 Coal and Shale Mining Rates 130
7.3 Road, Mine and Embankment Dust Control 134
7.4 Handling and Crushing Dust Control 137
7.5 Mine Personnel 138
7.6 Sanitary and Potable Water 141
7.7 Service and Fire Water 143
7.8 Revegetation 143
7.9 Coal Washing 145
References 147
8. EVAPORATION, SOLIDS DISPOSAL AND OTHER USES 149
8.1 Categories 149
8.2 Bottom Ash and Spent Shale Disposal 149
8.3 Fly Ash and Shale Dust Disposal 153
8.4 Plant Dust Control 154
8.5 Plant Personnel 155
, 8.6 Plant Sanitary and Potable Water 156
8.7 Plant Service and Fire Water 156
8.8 Settling Basin Evaporation 157
8.9 Reservoir Evaporation 160
References 161
9. MUNICIPAL WATER REQUIREMENTS AND RESIDUALS 162
Reference 163
VI
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10. SITE-SPECIFIC RESULTS
Page
164
11. FINDINGS
11.1
11.2
11.3
Total Site-Specific Water Consumption and Residuals
Site-Specific Water Consumption and Residual Breakdowns
Regional Water Consumption and Residuals
187
187
191
204
APPENDIX A.
COAL ANALYSES
206
APPENDIX B.
WATER ANALYSES AND PRECIPITATION AND EVAPORATION RATES
209
APPENDIX C.
LOAD FACTORS
215
APPENDIX D. TOTAL WATER CONSUMED AND RESIDUALS GENERATED FOR
THREE ENERGY SCENARIOS BY STATE AND COUNTY
217
APPENDIX E. STATE TOTALS OF WATER CONSUMED AND RESIDUALS
GENERATED FOR THREE ENERGY SCENARIOS
245
vii
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FIGURES
Number Page
1-1 Breakdown of net annual water consumption and wet solid residuals
generated in the production of 250 x 10° scf/stream day of
synthetic natural gas' by the Lurgi arid Synthane- processes at
different Western sites -.-..' 9
1-2 Breakdown of net annual water consumption and wet solid residuals
generated in the production of 100,000 bbl/stream day of fuel oil
by the Synthoil process at different Western sites and by the
TOSCO II oil shale process at Rifle, Colorado. 10
1-3 Breakdown of net annual water consumption and wet solid residuals
generated in the production of 3,000 MWe/stream day of electricity
by coal-fired steam-electric generating plants at different
Western sites ; 11
1-4 Regional net annual water consumption and wet solid residuals
generated in the Western coal and oil shale areas between the years
1980 and 2000 for three levels of energy development 15
2-1 Synthoil process 19
2-2 Hydrogen production train 25
3-1 TOSCO II retort flow diagram for upgrading shale oil output of
50,000 bbl per stream day with feed of 35 gallon per ton oil shale. 58
3-2 Flow diagram for TOSCO II shale oil upgrading refinery 60
3-3 TOSCO II process water streams for upgrading shale oil output of
50,000 bbl per stream day with feed of 35 gallon per ton oil
shale 62
4—1 Cooling tower nomenclature 72
4-2 Annual evaluated cost of dry cooling system as a. function of the
initial temperature difference for Navajo/Farmington, New Mexico.. 81
4-3 Annual evaluated cost of evaporative cooling system as a function
of cooling range for Navajo/Farmington, New Mexico 81
4-4 Wet/dry cooling system 104
4-5 Total annual evaluated costs of wet/dry cooling system as a
percentage of evaporative loss of all evaporative cooling system
at Navajo/Farmington, New Mexico 107
vtii
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FIGURES (continued)
Number; Page
11-1 Breakdown of net annual water consumption and wet solid residuals
generated in the production of 250 x 1C)6 scf/stream day of
synthetic natural gas by the Lurgi and Synthane processes at
different Western sites 192
11-2 Breakdown of net annual water consumption and wet solid residuals
generated in the production of 100,000 bbl/stream day of fuel oil
by the Synthoil process at different Western sites and by the
TOSCO II oil shale process at Rifle, Colorado 193
11-3 Breakdown of net annual water consumption and wet solid residuals
generated in the production of 3,000 MWe/stream day of electricity
by coal-fired steam-electric generating plants at different
Western sites 194
11-4 Regional net annual water consumption and wet solid residuals
generated in the Western coal and oil shale areas between the
years 1980 and 2000 for three levels of energy development 205
ix
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TABLES
Number Page
1-1 Unit size plants and ratio of operating or stream days to
calendar days in a year (load factor) 2
1-2 Summary of net annual water consumption and wet solid residuals
generated at each site ,
1-3 Net water consumed for Western coal sites per million Btu of
heating value in product
2-1 Material balance on Synthoil plant exclusive of hydrogen
production for Colstrip, Montana 20
2-2 Material balance on Synthoil plant exclusive of hydrogen
production for Beulah, North Dakota 21
2-3 Material balance on Synthoil plant exclusive of hydrogen
production for Gillette, Wyoming. 22
2-4 Material balance on Synthoil plant exclusive of hydrogen
production for Navajo/Farmington, New Mexico 23
2-5 Water equivalent hydrogen balance of Synthoil plant at four sites. 27
2-6 Approximate total heat load of Synthoil plant at four sites 29
2-7 Gas compressor energy and interstage cooling requirements for
Synthoil and Synthane plants 31
2-8 Approximate thermal efficiencies of Synthoil plants 32
2-9 Ultimate disposition of unrecovered heat in Synthoil plants 34
2-10 Water lost in condensate water treatment 35
2-11 Demineralizer water treatment waste 37
2-12 Water evaporation rates for wet cooling 42
2-13 Cooling water treatment waste 44
2-14 Water equivalent hydrogen balance of Lurgi plant at four sites.... 47
2-15 Assumptions and calculations on thermal efficiency of Lurgi
plants 49
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TABLES (continued)
Number
2-16 Water equivalent hydrogen balance for the Synthane process
using Wyodak coal 50
2-17 Approximate thermal efficiency for Synthane plant at Wyoming 52
2-18 Approximate disposition of unrecovered heat in Synthane plant
at Wyoming 53
3-1 Determination of TOSCO II retort water streams for upgrading
shale oil output of 50,000 bbl per stream day with feed of
35 gallon per ton shale, on basis of water balance for combined
retorting and upgrading steps . 64
3-2 Compilation of TOSCO II refinery water streams for upgraded
shale oil output of 50,000 bbl per stream day with feed of
35 gallon per ton shale, on basis of water balance for combined
retorting and upgrading steps 67
4-1 Summary of unit price data 79
4-2 Summary of design conditions for optimized cooling systems at
Navajo/Farmington, New Mexico 83
4-3 Summary of capital costs for optimized cooling systems
(lO^ Dollars) at Navajo/Farmington, New Mexico 84
4-4 Summary of energy and power quantities for optimized cooling
systems at Navajo/Farmington, New Mexico 85
4-5 Breakdown of annual evaluated costs for optimized cooling system
at Navajo/Farmington, New Mexico (106 dollars/yr) 87
4-6 Comparison of total annual evaluated costs of optimized cooling
systems and breakeven water costs 88
4-7 Control limits for cooling tower circulating water composition.... 91
4-8 Flow diagram, circulating water concentration and estimated costs
for Navajo/Farmington, New Mexico cooling tower 96
4-9 Summary of annual evaluated costs of water treatment and
blowdown disposal 97
4-10 Pipeline data 99
4-11 Evaluated costs of supplying water 100
4-12 Summary of evaluated water costs 102
XI
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TABLES (continued)
Number page
4-13 Total annual evaluated costs for optimum wet/dry cooling systems
at Navajo/Farmington, New Mexico 106
4-14 Water evaporated and heat dissipation rates for cooling towers.... 109
4-15 Residuals generated at each site 110
4-16 Drift rates 112
4-17 Demineralizer residuals 113
6-1 Moles of water vapor per mole of dry gas at saturation 120
6-2 Determination of total moles of dry flue gas per unit weight of
coal or char as fired 122
6-3 Element weights per unit weight of coal or char and makeup water
requirements per unit weight of coal or char for coals and char
of present study 123
6-4 Weight of CaS04-2H20 and CaSC^-^O, and water of hydration
per unit weight of sulfur 124
6-5 Weight of slurry water per unit weight of sulfur for a 40 wt.%
solids concentration . 125
6-6a Weight of components of lime sludge (dry) and corresponding
weights of sulfur and water of hydration 125
6-6b Weight of components of limestone sludge (dry) and corresponding
weights of sulfur and water of hydration 126
6-7 Weight of solids and water of hydration per unit weight of
sulfur in lime and limestone sludges . 126
6-8 Weight of sulfur and makeup water requirements per unit weight
of coal for coals of present study and with 40 wt.% solids in
slurry 128
6-9 Comparison of flue gas desulfurization makeup water requirements
for Kaiparowits coal from design estimates of Ref. 2 and present
approximate formulation 128
7-1 Process heat requirements for 250 x 10 scf/stream day
Lurgi plant 131
7-2 Mine and process requirements for coal conversion plants 132
7-3a Coal tonnage requirements for unit size plants in tons
per calendar day 133
xii
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TABLES (continued)
Number Page
7-3b Coal and shale tonnage requirements for unit size plants in
tons per calendar day 133
7-4 Coal yields per acre 134
7-5 Annual pond evaporation rates 135
7-6 Area strip mined annually in acres per year 136
7-7a Number of mine personnel for specific mines integrated with
coal conversion plants and a slurry pipeline. 140
7-7b Number of mine personnel for an underground and surface mine
integrated with a steam-electric plant and for an underground
oil shale mine integrated with a shale oil plant 140
7-8 Sanitary and potable water usage per man-shift and percent of
usage consumed 141
8-1 Temperature of bottom ash on removal and ash temperature drop
on quenching 150
8-2 Ash quantities in tons per day. 152
8-3 Plant personnel at all sites 156
8-4 Evaporation rates without and with evaporation control and
need for settling basin 159
9-1 Municipal water requirements in gallons per capita per day 163
10-1 Summary of total water consumed and residuals generated at
each site 165
11-1 Summary of net annual water consumption and wet solid residuals
generated at each site 188
11-2 Net water consumed for Western coal sites per million Btu of
heating value in product 190
11-3 Weight of water as a percent of total weight of wet
solid residuals 201
A-l Coal analyses 208
B-l Source of feed water 212
B-2 Source water quality 213
B-3 Precipitation and evaporation data (inches/year) 214
xiii
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TABLES (continued)
Number Page
C-l Load factors 216
D-l Base quantities assumed for water consumed and residuals
generated for standard size plants in each state of western
region 219
D-2 Location of results for specific scenarios by region, energy
demand, and year 220
E-l Location of results for specific scenario by region and facility.. 246
xiv
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CONVERSION TABLE
LENGTH
English to Metric
1 mile - 1.609 kilometers « 1609 mecer*
1 yard - .9144 meter - 9144 centemecers
PRESSURE
English to Metric
1 pound per square inch (pel) - .06804
atmosphere - 703.1 ktlograas per
square meter
AR£A
En«lIsh Equivalent
1 square mile • 640 acre*
English to Metric
1 square mile " 2.590 square kilometer* -
259.0 hectares - 2,590,000 square Mtera
1 acre - .004047 square kilometer •
.404? hectares - 4047 square meter*
FLOW RATE
English to Metric
1 cubic foot per second » 4488 gallons per
minute - 723.8 acre per year » .02832
cubic meters per second
1,000,000 acre feet per year - 3,9126
3.9126 cubic meters per second
WEIGHT
English Equivalent
1 ounce (avoirdupois) - 437,5 grains (troy)
English to Metric
.9066 matrlc tons
1 short ton (2,000 pounds)
- 906.6 kilograms
1 pound - .4536 kilogram
1 ounce - 2.8349 grams
VOLUME AND CAPACITY
English Equalivant
1 acre-foot - 43,560 cubic feet -
325,900 gallons
1 cubic yard » 202 gallons (liquid)
1 cubic foot • 7.481 gallons (liquid)
English to Metric
1 cubic yard « ,7646 cubic meter* •
764.6 liters
1 cubic foot • .02832 cubic meters •
28.32 liters
XV
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CONVERSIONS OF UNITS
VOLUMETRIC FLOW RATES
1 gallon per minute
1 million gallons per day
1 cubic foot per second
1 acre foot per year
mgd
cfs
acre ft/yr
1
694
448
0.619
1.44
0
8.91
x 10
1
.645
4
x 10
2.23 x 10
1.55
1
•5
1.38 x 10
1.614
1,120
723
1
MASS FLOW RATES
1 ton per day =
1 ton per year **
1 pound per hour =
1 gallon water per minute* =
ton/day
ton/yr
Ib/hr
gpm of H?O
1 365
2.74 x 10~3 1
0.012 4.38
6.00 2.19 x 103
83.3 0.167
0.228 4.56 x 10~4
1 2.00 x 10~3
500 1
*I gallon of water =8.33 pounds
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ACKNOWLEDGEMENTS
The authors wish to express their most sincere thanks to Steve Plotkin
of the Office of Energy, Minerals and Industry, U.S. Environmental Protection
Agency and Professor Irvin L. (Jack) White of the University of Oklahoma,
Science and Public Policy Program for their many suggestions during -the course
of the work and for their untiring efforts to ensure the success of the program.
xvii
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1. INTRODUCTION AND SUMMARY
1.1 Introduction
Two important aspects of any assessment of the potentials for
utilizing the abundant coal and oil shale resources in the Western United
States are first the local and regional environmental problems associated
with the large consumptive use of water required for mining and proces-
sing these resources, and second the problem of disposal of the large
quantities of solid residuals that 'leave the mine-plant complex. In
some western locales, where coal and oil shale can be economically mined,
surface and groundwater is in short supply. Moreover, in the West there
is frequently keen competition between agricultural, power producing,
municipal, industrial, recreational and other users for allocations of
the available water supply. The problems cited could hamper efforts to
utilize the nation's western coal and oil shale resources.
As a first step in estimating the impact of water supply and'avail-
ability on the development of these fossil fuel resources, it is neces-
sary to make an accurate determination of the water consumed for mining
and processing, together with a determination of the residuals generated.
In this study, the consumptive water requirements and solid residuals are
determined for the unit size plant-mine complexes and load factors
indicated in Table 1-1.
The coal input rates are about the same for the Lurgi and Synthane
gasification plants, although more coal is mined for the Lurgi plant
because the fines cannot be used and must be sold off. Compared with
the unit size gasification plant the coal input to a 3,000 MWe generating
plant is about 30% more, to the unit size Synthoil plant about 2 times
-------
as much, and to the slurry pipeline about 3 times as much. The input
to the shale oil plants is not directly comparable, but we would note
that the raw shale tonnage for a 100,000 bbl/day surface retort shale
oil plant is 3 times the coal tonnage for a 100,000 bbl/day Synthoil
plant.
Table 1-1. Unit size plants and ratio of operating or stream
days to calendar days in a year (load factor).
Load Factor
Nominal Output (stream day/calendar day)
Slurry Pipeline 25 x 10 tons coal/year 1.0
Lurgi 250 x 10 scf/stream day 0.9
Synthane 250 x 10 scf/stream day 0.9
Synthoil 100,000 bbl/stream day 0.9
Electrical Generation 3,000 MWe @ 35% eff. 0.7
Electrical Generation 1,000 MWe @ 35%'eff. 0.7
Oil Shale, TOSCO II 50,000 bbl/stream day 0.9
Oil Shale, TOSCO II 100,000 bbl/stream day 0.9
For each process, detailed calculations are carried out on the quanti-
ties of water consumed for the following purposes:
(1) the energy conversion process itself,
(2) evaporation for process cooling,
(3) flue gas desulfurization, if required,
(4) the mining operation and any revegetation of mined land,
(5) solids disposal, evaporation and other uses within the mine-plan
complex.
In our determinations we assume zero discharge to receiving waters.
We also assume water treatment facilities based on available technology
-------
to provide for a reasonably high level of recycle and reuse of process
effluent waters. Wasteful evaporation of wastewater is not permitted.
The water treatment procedures that can be used are given. Economic
studies of water treatment are not included in this assessment except
for some of the process cooling studies. For example, the choice of
wet, wet/dry, or dry cooling for steam electric generating plants is
made on economic considerations. The choice of cooling in the process
plants is also made on the basis of economic considerations from other
ongoing studies, although the detailed cost breakdowns are not incorpo-
rated in this report.
The water consumption and solid residuals generated for the unit
size mine-plant complexes noted are determined at a number of different
locations. The locations considered are:
Beulah, North Dakota
Colstrip, Montana
Gillette, Wyoming
Kaiparowits/Escalante, Utah
Navajo/Farmington, New Mexico
Rifle, Colorado
Not every plant is sited at each location. In particular, the slurry
pipeline is sited only at Gillette, while shale oil production is sited
only at Rifle. At Kaiparowits only electric power generation is con-
sidered, with the coal source an underground mine, as distinct from the
other sites, where all coal is taken to be surface mined. A total of
21 plant-site combinations is examined.
-------
Regional consumptive water requirements and solid residuals
generated are determined, based on the site-specific results and on
an assumed distribution of plants and different levels of energy
development from the present to the year 2000. The aggregated or
regional scenarios focus on the Powder River Region, which includes
the states of Montana, North Dakota and Wyoming, and the Rocky Mountain
Region which includes the states of Colorado, New Mexico and Utah.
Three levels of Western energy development are considered for the years
1980, 1985, 1990 and 2000 based on the Stanford Research Institute
energy model.
1.2 Summary of Findings and Conclusions
A preliminary assessment has been made of the minimum water con-
sumption and the solid residuals generated in synthetic fuel plants
and coal-fired steam-electric generating plants sited in the West.
Approximate regional estimates and projections have been made based on
three different levels of energy demand. The results show some esti-
mated plant water consumptions as much as a factor of three below the
lowest published design estimates. It is indicated that with more
detailed study of optimized water treatment and use large reductions
in water consumption and residual discharge are possible. Under these
conditions there will be larger variations in water consumption with
site, and these should be studied. The results also point up that
detailed regional environmental impacts cannot be properly assessed
without further determinations of local and regional water supply and
demand data and residual disposal methods.
-------
The study findings and conclusions are presented below on the
basis of total site-specific water consumption and residuals, a break-
down of these quantities, and regional water consumption and residuals.
Total Site-Specific Water Consumption and Residuals
Table 1-2 summarizes the study findings on the net annual water
consumption and wet solid residuals generated at each site for the unit
size mine-plant complexes assumed to be located there. Table 1-3
summarizes the net water requirements in terms of gallons per million Btu
of fuel produced (gal/10 Btu) with no distinction made as to consumption
between the sites but with overall ranges given instead.
Some of the major but necessarily tentative conclusions of this
study are the following:
1. Lurgi gasification facilities have the largest variation in
net water consumption as a function of site, ranging from
3
3.3-5.6 x 10 acre-ft/yr, principally as a consequence of differences
in coal moisture at the different locations.
2. The variations in water consumption with site for the Synthane
and Synthoil facilities are found to be relatively small being no more,
respectively, than 13% and 16%. However, for the steam electric power
generating plants a maximum difference in water consumption of 25% is
noted. These same findings do not hold for the residuals.
3. Synthane facilities use from 1.5-2.3 times the water that a
Lurgi facility does at the same site partly because the Lurgi process
accepts wet coal and utilizes the moisture, although at a cost. This
same moisture could in principle be recovered in Synthane plants in coal
drying, and this should be studied.
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Table 1-2. Summary of net annual water consumption and wet solid residuals generated at each site.
FACILITY
SLURRY PIPELINE (25 x 106 tons/yr 8 100% load factor)
NET WATER CONSUMED - 103 ACRE-FT/YR*
WE? SOLID RESIDCALS « 10s TONS/YR
LURGt (250 x 106 scf/stream day @ 90% load factor)
NET WATER CONSUMED - 103 ACRE-FT/YR
WET SOLID RESIDUALS - 106 TONS/YR
SVMTHANE (250 x 106 set/stream day @ 90% load factor)
NKT WATER CONSUMED - 103 ACRE-FT/YR
'.•XT SOLID RESIDUALS - 106 TONS/YR
SYNTUOIL (100,000 bbl/stream day g 90% lead factor)
NET MATED CONSUMED - ID3 ACRE-FT/YR
WCT SOLID RBSIDUALS - 106 TOMS/YR
ELECTRICAL GENF.RATION (3,000 HWe ? 35% et£, 70* load factor)
KET V.'ATER CONSUMED -- 103 ACRE-FT/YR
WET SOLID RESIDUALS » 106 TONS/YR
ELECTKICAL GENt-'HATION (1,000 M*e S 35* eff, 70» load factor)
NET WATER CONSUMED - 103 ACKB-FT/YR
WET SOLID RESIDUALS - 10s TONS/YR
OIL SHALE (50,000 bbl/stream day 8 90% load factor)
NET WATSB CONSUMED - 103 ACRE-FT/YR
WET SOLID RESIDUALS - 106 TONS/YR
OIL SIIALE (100,000 bbl/stream day 8 90% load factor)
Ni.T WATER CONSUMED - 103 ACRB-FT/YR
WET SOLID RESIDUALS - 106 TONS/YR
BEULAH,
NORTH DAKOTA
3.31
1.20
7.67
1.08
10.09
2.00
23.88
2.65
COLSTHIP,
MONTANA
4.62
1.27
7.81
1.12
10.30
2.07
26.66
3.01
GILLETTE,
WYOMING
19.17
4.21
0.72
7.78
0.71
9.23
1.23
25.84
1.32
KAIPAROWITS/
ESCALANTE,
UTAH
29.82
5.30
NAVAJO/
FARMINGTON,
NEW MEXICO
S.64
3.00
8.67
2.84
11.75
5.31
29,21
5.00
RIFLE,
COLORADO
9.49
0.38
6.48
20.40
12.92
40.81
•To convert 103 acre-ft/yr to 1Q6 tons/yt multiply by 1.36,
to convert 10^ acre-ft/yr to 10& gal/day multiply by 0.894.
-------
Table 1-3. Net water consumed for Western coal sites
per million Btu of heating value in product.
Net Water Consumed
Facility (gal/lQ6 Btu)
Lurgi 14-24
Synthane 32-36
Synthoil 15-19
Oil Shale 23
Slurry Pipeline 14
Electric Generation 43-54*
*gal/10 Btu of heating value of input coal.
4. The net water consumption of Synthoil and TOSCO II oil shale
facilities producing the same output of 100,000 bbl/day are roughly the
3
same at between 9.2 and 12.9 x 10 acre-ft/yr, with the oil shale con-
sumption at the upper end of the range.
5. With the design procedures used in this study and with proper
water treatment design the Lurgi, Synthoil, oil shale and slurry pipeline
water requirements are roughly the same with s. mean around 18 gal/10 Btu
when expressed per unit of heating output. The slurry pipeline require-
ment is at the lower end of the spread, while oil shale is at the upper
end. The Synthane facilities require about 2 times more water. The
water for electric power generation is by far the largest requiring
2.5 times mor,e water, as measured in terms of the heating value of the
input coal.
6. For a given facility the quantity of solid residuals is very
site dependent. For all the coal-to-fuel and electric generating
7.
-------
processes the largest variation between sites is more than a factor
of 4, with a range for surface mined coal of 2.8-5,0 x 10 tons of wet
solids per year at Navajo, New Mexico to a corresponding range of
0.7-1.3 x 10 tons/yr at Gillette, Wyoming. The large quantity of
solid residuals at Navajo is associated with the high ash content of
the coal.
7. Outstripping all the coal conversion residuals by an order
of magnitude are those from surface oil shale processing; where the
primary residual is the wet spent shale amounting to 41 x 10 tons/yr
for a 100,000 bbl/day plant,
Site-Specific Water Consumption and Residual Breakdowns
Figures 1-1 to 1-3 show breakdowns of the consumed water by use
and of the wet solid residuals by type. The breakdowns are given in
Fig. 1-1 for the production of 250 x 10 scf/day of synthetic natural
gas by the Lurgi and Synthane processes; in Fig. 1-2 for the production
of 100,000 bbl/day of synthetic fuel oil by the Synthoil process and
from oil shale by the TOSCO II process; and in Fig. 1-3 for the genera-
tion of 3,000 MWe of electricity by coal-fired steam generation. The
sites indicated correspond to those called out in Table 1-2.
As noted in the Introduction, five separate categories of water
consumption were calculated in some detail. For clarity of graphical
presentation, these categories and their subcategories are combined
into three major use groups: (1) process and flue gas desulfurization
(FGD), (2) cooling and (3) solids disposal, mining and other. Although
in the detailed analyses solids disposal is broken down into a large
number of categories, for simplicity of presentation they are here
-------
250X|06SCF/DAY
(Or
•SYNTHANE
WATER
-------
100,000 BBL/OAY
14
12
10
SYNTHOIL
WATER (I03ACRE-FT/YR)
MINING. DISPOSAL,
,OTHER-
SYNTHOIL
SYNTHOIL
PROCESS
OIL SHALE
ui
o
o
a:
a.
BEULAH
6r
4 •
-)
COLSTRIP
GILLETTE
NAVAJO
WET SOLIDS (I06TONS/YR)
y/A
'ASH J
/ /
RIFLE
40
38
6
BEULAH
Fig. 1-2.
COLSTRtP
GILLETTE
NAVAJO
RSFLE
Breakdown of net annual water consumption and
wet solid residuals generated in the production
of 100,000 bbl/stream day of fuel oil by the
Synthoil process at different Western sites and
by the TOSCO II oil shale process at Rifle,
Colorado.
10
-------
32 r
28 -
20
16
12
3,000 MWe
WATER (103ACRE-FT/YR)
DISPOSAL, MINING,OTHER
FGD
FGD
BEULAH
COLSTRIP
GILLETTE
KAIPAROWITS
NAVAJO
•»£7]
WET SOLIDS (I06TONS/YR)
ft
6D
SLUDGE
I
•'w •:£
• u-';v.'i
,'K;"
BEULAH
COLSTRIP
GILLETTE
KAIPAROWfTS
NAVAJO
Fig. 1-3. Breakdown of net annual water consumption and
wet solid residuals generated in the production
of 3,000 MWe/stream day of electricity by coal-
fired steam-electric generating plants at differ-
ent Western sites.
11
-------
combined into the following main groups: (1) ash, (2) flue gas
desulfurization (FGD) sludge, (3) spent shale, (4) coal refuse and
(5) other wastes. In the groups of Figs. 1-1 and 1-3, generally only
two types of waste are indicated and in Fig. 1-2 only one type,
because the contributions of the remaining types are negligibly small
on the scales of the figures.
The major conclusions of this phase of the study are the following:
1. The largest quantity of water consumed in all facilities,
except oil shale, is the water evaporated for cooling. These water
requirements are highest for electric power generation when compared
to the other processes, because for the same energy input the genera-
tion of electricity has the lowest thermal efficiency.
2. Cooling is needed to dissipate about 75% of the unrecovered
heat in the fuel-to-fuel and electric generating plants. Whether to use
wet cooling, dry cooling or wet/dry cooling depends on the cost of water,
including any necessary treatment, although at least 25-50% of the
unrecovered heat in the fuel plants- should be dissipated by dry cooling.
3. For electric generation at Navajo, New Mexico when water
costs about $2.20/1000 gal, partial dry cooling is more economical than
all wet cooling. For this water cost at all other sites, all evaporative
cooling systems are preferable if sufficient water is available.
4. Estimates for the Synthoil and Synthane plants are based on
all wet cooling of turbine condensers. Cooling water requirements for
the Lurgi plants are taken from existing designs and are about 2/3 that
for Synthane except at Navajo, New Mexico where it is about 1/2. Wet/dry
cooling was not examined but could reduce the cooling water requirement
12
-------
to about 25% of that used and probably becomes economically viable
when cooling water costs $1 to $1.50/1000 gallons evaporated for cool-
ing, although this would have to be checked in a future study.
5. Wet scrubbing of stack gases for sulfur removal represents
a large fraction of process water usage in Lurgi and Synthane plants
and is a large consumer of water in electric generating plants. The
largest quantity .of this water leaves as saturated vap.or in the flue
gas and the amount depends critically on the flue gas saturation
temperature.
6. Most of the solid residuals leave the plant boundaries wet
and for the Lurgi, Synthane and Synthoil facilities, with surface
mined coal, the greatest part of this solid waste is ash with a weight
percent water averaging around 25%. For electric power generation,
except for the high ash Navajo coal, about half of the residuals is
the sludge generated by flue gas desulfurization and the other half
is ash. The combined weight percent of water averages around 38%. In
underground mining the largest fraction of the solid waste is coal
refuse with a 30% weight of water.
7. In surface mining the largest use of water is for dust
control, except when water is required for mined land revegetation,
which for the sites examined is only necessary at Navajo, New Mexico.
The actual quantities of water are quite site dependent. In under-
ground mining, examined only at Kaiparowits, the largest quantity of
water is required for coal washing.
8. In oil shale processing, where the tonnage mined and the
solid residuals generated are the largest of all the processes, the
13
-------
3
water consumption is 1.8 x 10 acre-ft/yr for mining and
3
4.1 x 10 acre-ft/yr for solids disposal and other uses.
9. Although the principal solid residuals from coal conversion
and processing are generally harmless, they do contain trace quantities
of harmful elements and compounds. It is possible that the disposal of
the large quantities of wet residuals identified could lead to a
collective problem in the dispersion of the hazardous materials, but
this must be examined.
Regional Water Consumption and Residuals
Fig. 1-4 summarizes the study findings on the aggregated net
annual water consumption and wet solid residuals generated in the
region of the West in which energy development is focused. The three
levels of energy development are based on the Stanford Research
Institute energy model with low end-use demand, nominal end-use demand
and low nuclear availability.
The major findings and conclusions are:
1. For all levels of energy development considered, the aggregated
net\regional $ater consumption in the Western coal and oil shale areas
increases by a. factor of 9-10 between the years 1980 and 2000, while
during the same period the wet solid residuals increase by a factor of
75-100. This large increase in residuals is associated with the role of
surface oil shale processing and the need to dispose of the spent shale.
2. On the basis of the quantities of water consumed and residuals
generated, Colorado appears to be the state most affected by energy develop-
ment in the Rocky Mountain Region. This is due principally to the pro-
jected rapid growth of a surface processing oil shale industry. Montana
14
-------
2600 r
2200
1800
1400
tooo
600
WATER (IQ3ACRE-FT/YR)
200
LOW DEMAND
[~~] NOMINAL DEMAND
[771 LOW NUCLEAR
X
I960
1985
1990
240
160
80
WET SOLIDS (!06TONS/YR)
SPENT SHALE -_
\
1980
Fig. 1-4.
1985
1990
2000
2000
1600
800
400
2000
Regional net annual water consumption and wet
solid residuals generated in the Western coal, and
oil shale areas between the years 1980 and 2000
for three levels of energy development.
15
-------
is the most affected state in the Powder River Region, principally
because of the projected growth of slurry pipeline development and
coal-fired steam-electric power generation.
3. The actual environmental impacts of siting synthetic fuel
and electric power generation facilities cannot be properly assessed
without an appropriate determination of local and regional water
supply and demand data, and residual disposal methods.
16
-------
2. COAL CONVERSION PROCESSES
In this section are described the methods used to determine the process
water and cooling water requirements for the Synthoil, Lurgi and Synthane
coal conversion processes. Because different information is available for
each process the details of the procedures differ from process to process.
However in each case the same broad outline was used: (i) First the hydrogen
balances around the plant were made to determine net process water require-
ments (in some of the plants using a very moist coal there is a net production
of water). (ii) Current designs were used to determine the cooling water
requirements for the Lurgi process. (iii) For the Synthoil and Synthane
processes the plant thermal efficiency and the quantity of unrecovered heat
were estimated. We then determined how this unrecovered heat was lost to the
atmosphere, whether directly as up a stack, or through a heat transfer surface.
Finally, for that heat which was lost through a heat transfer surface we
determined, by economic considerations, whether the heat exchanger could be
directly air cooled or whether evaporative water cooling was required. The
discussion on cooling together with the relationship between heat lost and
water evaporated is given in Section 2.3.
2.1 Synthoil Process
The Synthoil process for hydrogenating coal to a heavy oil has been
*
described in many publications by the Bureau of Mines including References 1
to 4. The only integrated plant design (including hydrogen production) which
* References are given at the end of each section.
17
-------
we have seen is that of Ref. 3 made for a Wyoming coal and made specifically
for cost estimating purposes. For the purpose of estimating water require-
ments we have chosen to make our own, somewhat simplified design, using
the block diagram from Ref. 3 reproduced as Fig. 2-1 in a form suitable
for present purposes. The overall material balances, not including hydrogen
production, were made using the following rules and are presented in
Tables 2-1 to 2-4.
(a) Overall material balances
1. 100,000 bbl/stream day of oil equals 1.4 x 10 Ib/stream hr
(Ref. 3) and the oil is assumed to be 90 wt. % carbon, 8.5 wt. % hydrogen
and 1.5 wt. % oxygen, nitrogen and other elements.
2. We assume that 5 barrels of oil are produced from each ton
of carbon in the coal. This is the average of published results:
Ref. No. bbl oil/ton carbon in coal
1 5.3
2 5.0
3 4.7
used in this work 5.0
The feed to the reactors (streams 2 and 5) must, therefore, contain
1.67 x 10 Ib/stream hour of carbon. Coal is assumed dried to 0.5 wt. % moisture.
This moisture is assumed to remain in the product oil,
3. Hydrogen requirements have been given as:
Ref. No. scf H2/bbl oil
1 4200
2 4730
3 4830
used in this work 4700
18
-------
COAI
Q.
^—
1
WATER
VAPOR
COAL
PREPARATION
& DRYING
HYDROGEN
HYDROGEN
PRODUCTION
S
COMPRESSION
STEAK OXYGE!.1 WATER
& CONDENSATE
RECYCLE OIL
COAL
SLURRY
PREPARATION
230°F
HEAT
' EXCHANGER
I
I
RECYCLE GAS
PURIFICATION
800°F
PHASE
SEPARATION
WATER
CON DENS ATE <1 -V
CHAR
CHAR
DE-OILING
Fig. 2-1, Synthoil process.
REACTOR
OIL
GAS
-*• SALES GAS
-> PLANT FUEL
-------
Table 2-1. Material balance on Synthoil plant exclusive of
hydrogen production for Colstrip, Montana.
Units: 10 Ib/stream hr
Stream
2
4
5
6
7
8
9
No.
Coal, as received
Water lost in drier
Coal, dry
Make-up hydrogen
Oil
Gas
Char
Total -Moisture C H
3303 816 1670 105
816 804
2500 12 1670 105
148 19 103
1490 12 1340 127
246 51
103
0
324
324
26
13 Water from phase
separation
296
30 266
20
-------
Table 2-2. Material balance on Synthoil plant exclusive of
hydrogen production for Beulah, North Dakota.
Units: 10 Ib/stream hr
Stream No.
Total Moisture C H
2
4
5
6
7
8
9
Coal, as received 4130
Water lost in drier 1473
Coal, dry 2657
Make-up hydrogen 148
Oil 1490
Gas
Char
1486 1670 112 492
1473
13 1670 112 492
19 103 26
13 1340 127
246 36
103
13 Water from phase
separation
464
52 412
21
-------
Table 2-3. Material balance on Synthoil plant exclusive of
hydrogen production for Gillette, Wyoming.
Units: 10 Ib/stream hr
Stream No.
Total Moisture C H 0
2
4
5
6
7
8
9
Coal, as received 3381
Water lost in drier 935
Coal, dry 2446
Make-up hydrogen 148
Oil 1490
Gas
Char
947 1670 115 432
935
12 1670 115 432
19 103 26
12 1340 127
246 46
103
13 Water from phase
separation
408
45 363
22
-------
Table 2-4. Material balance on Synthoil plant exclusive of
hydrogen production for Navajo/Farmington, New Mexico
Units: 10"" Ib/stream hr
Stream No.
Total Moisture C H
Coal, as received
3532
438 1670 122 338
Water lost in drier
422
422
Coal, dry
3110
16 1670 122 338
6 Make-up hydrogen
148
19 103 26
Oil
8 Gas
1490
16 1340 127
246 63
Char
103
13 Water from phase
separation
313
35 278
23
-------
The hydrogen in stream 6 is, therefore 5.16 x 10 moles/stream hr or
3
103 x 10 Ib/stream hr. Stream 6 is taken to be 97% H2 and 3% CO.
4. The carbon in the char has been given as:
Ref. No. Carbon in char as % of carbon in coal
1 6
3 about 6^3
used in this work 6.2
3
so the char (stream 9) contains 103 x 10 Ib/stream hr of carbon; the
hydrogen and oxygen are assumed to be negligible.
5. The oxygen in the coal is assumed converted as follows:
10^ to gas and oil.
3
26 x 10 Ib/stream hr reacts with CO in stream 6 to
yield CO- which remains in the gas.
The balance is converted to water, stream 13.
6. The balance of the carbon and hydrogen appear in the gas.
b. Hydrogen production
There are many ways to make hydrogen: (i) The gas can be put through
a steam reforming reaction (this is quite efficient but necessitates burning
char and coal for plant energy and both char and coal contain sulfur) .
(ii) The char, with added coal, can be partially oxidized (gasified) to make
synthesis gas which can be converted to H~ by the shift reaction (this pro-
cedure yields the sulfur as HUS which can be readily removed; the gas produced
in the oil plant is also stripped of H2S and is then burnt as a char fuel).
We have assumed that gasification is used and the hydrogen production train is
shown in Figure 2-2. Extrapolating from Ref. 3 the following rules were used
to calculate the various water streams of Figure 2-2.
24
-------
COAL
& CHAR
I
GASIFIER
1800°F
450 psig
STEAM
ACID GAS
REMOVAL
1
' to
^ 300°P
QUENCH
t
WATER
WASTE
HEAT
RECOVERY
i /m°p /"A
0 kf A/
500° F
410
psig
i
95°F ^
•" ™\ / V '
r
FIRST
STAGE
SHIFT
(950°F)
1
r
SECOND
STAGE
SHIFT
(550°F)
HYDROGEN
COMPRESSION
900°F ^
DIRT
COND
{ STEAJ
©
>
f
HEAT
EXCHANGER
i
/ ^
2NSATE
<
r
^
300°F
<
|
f
ACID GAS
REMOVAL
^
f
IRON OXIDE
&
CHAR TOWER
*•-
cw
V
CLEAN
CONDENSATE
Fig. 2-2. Hydrogen production train..
-------
1. The gasifier is pressurized aad yields hydrogen at 390 psig
which is compressed to 4000 psig for use in the Synthoil reactor.
2. The gasifier off-gas comes off at 1800°F and contains
4 4
2.22 x 10 moles/stream hour H2 and 3.10 x 10 moles/stream hr CO. At
Beulah, North Dakota more synthesis gas is produced as explained in rule
No. 8. After shift reaction this stream will give stream 6.
3. The gasifier is supplied with 0.5 Ib of steam/lb of carbon
fed to the gasifier.
4. Enough coal is added to the char so that when the material
balance is complete the gasifier will be in thermal balance. The coal carbon
required varies with moisture in the coal.
5. The carbon in the coal plus char appears as CO + C0~ which
gives the CO,, rate.
6. The water in the off-gas satisfies the hydrogen balance.
7. The oxygen fed satisfies the oxygen balance.
8. In one case, Beulah, North Dakota, extra HL + CO are made and
used as fuel because there is not enough energy in the Synthoil gas to drive
the plant.
9. The gases leave the first shift reactor in equilibrium at
750°F and the second shift reactor in equilibrium at 550°F. The gasifier
off-gas is quenched by direct addition of water. This, in fact, proved to
yield a surplus of steam for the shift reaction and a waste heat recovery
unit would improve the plant efficiency.
Total hydrogen balances are presented in Table 2-5.
26
-------
Table 2-5. Water equivalent hydrogen balance of Synthoil plant at four sites.
IN
Moisture in as-received coal to liquefaction
Water equiv. of hydrogen in as-received coal to liquefaction
Moisture in as-received coal to gasifier
Water equiv. -of hydrogen in as-received coal to gasifier
Total steam to hydrogen production
Quench water to hydrogen production
Total
OUT
From drying coal to liquefaction
Total dirty process condensate
Clean process condensate
Water equiv. of hydrogen in product oil
Moisture in product oil
Water equiv. of hydrogen and moisture in gas produced
Total
10 lb/ stream hr
Cols trip ,
Hont.
816
945
170
197
495
712
3335
804
785
144
1143
12
459
3347
Beulah ,
N.D.
1486
1008
399
270
467
670
4300
1473
1101
96
1143
13
*
465
4291
Gillette,
Wyo.
947
1035
178
194
511
528
3393
935
759
132
1143
12
414
3395
Navajp ,
N.M.
438
1098
83
207
529
581
2936
422
635
139
1143
16
567
2922
* Includes the surplus synthesis gas produced in gasifier and burned as plant fuel.
-------
c. Plant energy requirements
An estimate of the energy needed to drive the plant was obtained
by adding the following requirements:
coal
slurry pump
slurry and hydrogen heating
char deoiling
oxygen production
hydrogen plant steam
hydrogen plant waste heat recovery
hydrogen plant CCL removal
gasifier lock hoppers
hydrogen compression
plant electricity
water treatment and other low
temperature energy consumers
stack gas losses
These are the principal, but not all the energy loads in the plant. The
approximate heat loads of the plant are shown in Table 2-6. Since all the
energy requirements may not have been found, the stated efficiencies may be
high. This will not affect the cooling water. Much the most important
difference from plant to plant is the energy consumed in drying coal. This
is low enough in Navajo/Farmington, New Mexico, that the product sold includes
quite a lot of gas. Drying coal consumed so much energy in Beulah, North
Dakota, that some gasifier off-gas had to be burnt.
28
-------
Table 2-6. Approximate total heat load of Synthoil plant at four sites.
N>
Drying coal to liquefaction
Slurry pumps
Heat exchanger and phase separator
Char deoiling
Coal and char feeding to hydrogen production
Acid gas removal in hydrogen production
Waste heat recovery in hydrogen production
Hydrogen compression
Oxygen production
Electricity generation
Water treatment and other low level uses
Boiler stack gas loss
Approximate total heat load
10 Btu/stream hr
Co Is trip ,
Mont.
0-.90
0.36
0.80
0.45
0.03
1.00
(-0.76)
0.97
0.92
0.32
0.50
0.61
6.10
Beulah ,
N.D.
1.65
0.39
0.82
0.45
0.04
1.04
(-0.94)
0.97
1.16
0.32
0.50
0.72
7.12
Gillette ,
Wyo.
1.05
0.36
0.79
0.45
0.03
0.93
(-0.56)
0.97
0.72
0.32
0.50
0.62
6.18
Navaj o ,
N.M.
0.47
0.45
0.89
0.45
0.03
0.93
(-0.54)
0.97
0.76
0.32
0.50
0.58.
5.81
-------
In calculating Table 2-6 we used the following procedures. The slurry
contains two pounds of oil per pound of coal and the pumps were 70% efficient.
The heat loads to the dissolver heating section and char deoiling section
were estimated using the detailed design of Ref. 3. Coal and char are
assumed fed to the gasifier using a lock hopper; lock hopper compressor
t-
requirements were scaled from Ref. 5. The acid gas removal system was
assumed to be the Benfield hot potassium carbonate system , Compressor
energies are listed in Table 2-7 which includes other compressors needed for
the Synthane plant. The heat rate to all turbine drives was 11,700 Bfu/kw-hr.
The energy needed to drive an oxygen plant is the energy to compress air to
90 psia plus the energy to compress oxygen from 20 psia to gasifier pressure.
The electricity plant produces 27,000 kw. The low level uses of heat are an
arbitrary addition. The boiler stack gas loss is 10% of the fuel burnt.
The approximate plant thermal efficiencies are shown in Table 2-8.
d. Ultimate disposal of unrecovered heat
The plants must be in thermal balance. That part of the energy
in the feed coal which is not sold as oil or gas must leave the plant in
some unrecoverable low level form. To determine whether cooling water is
needed we estimated the low level heat that leaves the plant (i) directly
through stacks (including water vapor) by convection, etc., and (ii) by transfer
to water in a cooling tower. One big load, the condensers in the regenerators
of a Benfield CO^ removal system, is dry cooled (as is currently practiced in
selected cases) which accounts for about 2/3 of the dry cooling load-.
Evaporative cooling was used for all compressor interstage coolers and the
condensers on all steam driven turbines for all plant moving machinery and
electrical generation. This accounts for about 2/3 of the evaporative cooling
and could, in extreme water short areas, be replaced by dry cooling.
30
-------
Table 2-7. Gas compressor energy and interstage cooling requirements
for Synthoil and Synthane plants.
Conditions: Stage entry temperature 95°F; polytropic efficiency 77%
Basis: 2000 Ib gas/hr
Gas
Pressures (psia)
Inlet Exit
No. of
Stages
Drive
Turbine
(kw)
Interstage
Coolers
(103 Btu/hr)
Air
15
90
59
200
Oxygen
20
465
92
240
Oxygen
Hydrogen
20
405
1015
4015
120
1115
340
2880
***
* 4.32 Ib air yield I Ib oxygen.
** Aftercooler to 95°F included.
*** Forecooler, 140° to 95° included.
31
-------
Table 2-8. Approximate thermal efficiencies of Synthoil plants,
10 Btu/stream hr
Colstrip , Beulah, Gillette, Navajo,
Montana N.D. Wyoming N.M.
Heating value of
coal feed
34.4 35.8
33.9 34.8
Heating value of
product oil
26.2 26,2
26.2 26.2
Heating value of
gas sold
0.6
0.2
1.7
Unrecovered heat 7.6
9.6
7.5
6.9
34.4 35.8
33.9 34.8
Overall thermal
efficiency
78%
73%
78%
80%
32
-------
The results are shown in Table 2-9. Direct losses are caused by coal
drying, boiler stack losses, char deoiler stack losses, electricity used,
pump and compressor losses and an allowance for convection losses. At
Beulah, North Dakota, some gasifier off-gas is burnt for fuel and as this is
wet the stack losses are higher than at other sites. The air cooling losses
are the Benfield acid gas removal regenerator condenser and cooling of gas,
oil and hydrogen from 300 to 140°F, At Beulah, North Dakota, the recovery of
condensed water from the Benfield system increases the cooling load over
other sites. The remaining losses have been assigned to wet cooling so as
not to understate the water requirements. As discussed in Section 2.3, all
turbine condensers and compressor interstage coolers are wet cooled.
2.2 Process Water Streams
The water consumed for the process is shown in the summary tables of
Section 10 and was calculated from the process description as follows.
(i) The dirty plant condensate (which is about half from the oil
section of the plant and about half from the gasification section of the
plant) was assumed sent to water treatment where about 1.8% of the water
was lost (see Table 2-10). The sludge produced in Tjiotreatment, which is
80% moisture, is 0.75% of the weight of the treated water; Che water in the
sludge is 0.6% of the weight of the treated water.
(ii) Clean process condensate was not sent to treatment.
A sample calculation for the Synthoil process at Colstrip, Montana follows:
33
-------
Table 2-9. Ultimate disposition of unrecovered heat in Synthoil plants.
10 Btu/stream hr
Points of load
Coal drying
Stack loss, including
char deoiling
Electricity used, slurry
pump loss
Other direct losses
Subtotal - direct loss
Acid gas removal regen-
erator condenser
Air cooling in phase
separator and other
process streams
Subtotal - dry cooling
Turbine drive condenser
Compressor interstage
cooling
Additional wet cooling
load
Subtotal - wet cooling
Total unrecovered heat
Cols trip ,
Montanta
0.90
0.81
0.20
0.19
2.1
1.00
0.40
1.4
1.82
0.58
1.70
4.1
7.6
Beulah ,
N.D.
1.65
1.02
0.21
0.22
3.1
1.44
0.46
1.9
2.02
0.65
1.93
4.6
9.6
Gillette ,
Wvomine
1.05
0.82
0.20
0.13
2.2
0.93
0.47
1.4
1.68
0.51
1.71
3.9
7.5
Navajo ,
N.M.
0.47
0.78
0.23
0.22
1.7
0.93
0.47
1.4
1.77
0.53
1.62
3.8
6.9
34
-------
Table 2-10. Water lost in condensate water treatment
Basis: 10 Ib water treated.
Gas plant
Oil plant
Ib NH~ in wastewater*
Ib water lost with NH3
in 40% solution
Ib BOD*
Ib wet sludge (80% moisture) **
Ib water in sludge
Total water lost , with ammonia
& in sludge
3
5
13
6.5
5
10
14
21
17
8.5
7
28
* Typical analysis.
** 0.1 Ib dry sludge/lb BOD removed, Ref. 7.
35
-------
10 Ib/stream hr
Stream and quench water fed (Table 2-5) 1207
Clean condensate recovered (-144)
Dirty water to treatment (-785)
Lost in treatment 14
Net process water consumed 292
„„. ~3 Ib 1 gal 0.9 stream hr 1 calendar hr
stream hr 8.33 Ib calendar hr 60 calendar min
= 526 gal/calendar min .
Water in condensate treatment sludge =
,Q, ,^3 Ib O.Q06 Ib water in sludge
785 x 10 —-—' T— x — ——.—°—
stream hr Ib water treated
n nm o gals/calendar min ~ •,/-,,
x 0.0018 & ,, . • r = 9 gals/calendar mm .
Ib/stream hr 6
The boiler makeup water has been taken to be 100 gal/calendar min more
than the steam quantity shown in Table 2-5. The demineralizer waste is taken
to be 50% moisture and to have a solids content of 1.6 times the total
dissolved solids in the makeup water. This corresponds to complete
deionization of the makeup water and a regenerant usage of 160% of the
stoichiometric values. The makeup water is usually source water but may be
treated process condensate if this has not all been used for cooling.
Table 2-11 was used to calculate demineralizer waste. A sample calculation
to estimate boiler demineralizer waste at Colstrip, Montana follows:
36
-------
Table 2-11. Demineralizer water treatment waste.
tons wet sludge (50% moisture)
per 1000 gal water evaporated
Colstrip, Montana
0.0053
Beulah, North Dakota
0.0057
Gillette, Wyoming (Yellowstone)
0.0053
Gillette, Wyoming (North Platte)
0.0055
Rifle, Colorado
0.0032
Navajo/Farmington, New Mexico
0.0040
Kaiparowits/Escalante, Utah
0.0077
Treated process condensate
0.0096
37
-------
Steam makeup:
,3 lb 0.0018 gal/calendar min . ,nn gal
495 x 10
stream hr lb/stream hr calendar min
= 991 gal/calendar min .
Wet sludge:
991 gal 0.053 tons 1440 min _ _, , , , ,
—;—j ~ x TAOA *—i— x —j = '.56 tons/calendar day
calendar min 1000 gals day
Dry solids:
0.50 x Wet sludge = 0.5 x 7.56 —, fc°ns .— =3.78 tons/calendar day
calendar day
Water in waste:
7.56 tons wet sludge 0.5 tons water 2000 Ib/ton 1 gal
calendar day tons sludge 1440 min/day 8.33 lb
-, cs , , . , , , „ «00/ gal water/calendar min
= 7.56 tons wet sludge/calendar day x 0.0834 -* n , ,—:; 3 1—
tons sludge/calendar day
= 0.6 gal/calendar min .
2.3 Cooling Water
Some of the heat not recovered in coal conversion plants is lost to the
atmosphere through a heat transfer surface. This surface can be directly
cooled by air (which is called dry or air cooling) or it can be cooled by
circulating cooling water which is itself cooled in an evaporative cooling
tower (which is called wet or evaporative cooling). In general wet cooling
requires a lower capital investment than dry cooling, can cool to a lower
38
-------
temperature, but does require water. Water is not free. It costs about
2c to move one thousand gallons of water one mile through a horizontal
pipeline. It costs $0.50 to $1.00/thousand gallons of water evaporated to
treat water in a circulating cooling system and to dispose of the solid
8
residues . The decision as to whether to use wet or dry cooling will depend
on the cost of water and its treatment, and will be different for each point
of cooling in the plant.
9
The cooling of plant process streams has been evaluated and based on
that evaluation all process streams have been assumed to be cooled to 300 F
with waste heat recovery, from 300 to 140 F by dry cooling, and below
140 F by wet cooling. The cooling water requirement depends on the tempera-
ture to which the stream must be cooled. The cooling water required for
process cooling is very low and this is corroborated in many actual plant designs.
The gas purification system regenerator condenser cooler, which is a
very large load, is discussed in Ref. 9. This will be dry cooled by using a
hot potassium carbonate system for the Synthoil and Synthane processes.
The gasifier off-gas in the Synthane process is quenched to 270 F by
direct water contact. As discussed in Ref. 9 the circulated water is cooled
in a dry cooler.
Much the most important use of wet cooling is for the condensers.on
steam turbine drives used to drive gas compressors, slurry pumps, electric
generators and other mechanical loads on the plant. For this type of steam
turbines, the thermal efficiency reaches its maximum when the exhaust pressure
is between 3 and 5 inches Hg.' absolute. The corresponding condenser tempera-
tures are 115 and 134°F. Typical turbine inlet steam conditions are tempera-
ture in the range from 700 to 900°F and pressure in the range from 715 to 915 psia.
39
-------
Based on these inlet conditions, a typical turbine efficiency of 80%, and
a bearing efficiency of 97.5%, the heat rate to the turbine per kw power
output is about 11,700 Btu/hr when the condenser temperature is 115 F, and
goes up linearly to about 12,200 Btu/hr when the temperature is 134 . The
corresponding heat rejection rates in the condenser for these two temperatures
are about 8,200 Btu/hr and 8,700 Btu/hr. The thermal efficiency of the cycle
when the condenser temperature is between 115 and 134 F is therefore
approximately 30%.
The economics of whether dry cooling or wet cooling should be used
have been analysed in a manner similar to Ref. 9 for the following four sites:
Colstrip, Montana; Beulah, North Dakota; Gillette, Wyoming; and Navajo/Farmington,
New Mexico. In the dry cooling calculations, the condenser is designed to
operate in the temperature range from 115 to 134 F. The condenser is sized
for a maximum dry bulb temperature which would not be exceeded for more than
10 hours a year. In the winter time when the temperature is lower, the
cooling fans are gradually shut off by automatic control of blade pitch
so that the condenser temperature does not drop below 115 F. This saves
fan energy.
In the wet cooling tower calculations, the condenser is designed to
operate at the lowest temperature, 115 F. The circulating water is designed
to be between 80 and 105 F, and the wet tower is designed for the highest
wet bulb temperature in the summer. In the winter time when the entering air
is dryer and colder and evaporation is more efficient , part of the circulating
cooling water can be bypassed from the tower allowing part of the cooling
tower to be shut off. This saves fan energy and water. Tower calculations
were made using Ref. 10 based on the optimization of both dry and wet towers.
40
-------
If the fan energy is assumed to be 2$ per kw-hr, the breakeven cost for
water is only about $1.10 to $1.20 per 1000 gallons evaporated for these
four sites. The water consumption rate, which ranges from 5.2 Ib/kw-hr
to 5.7 Ib/kw-hr, is shown in Table 2-12, expressed in Btu/lb of water
evaporated. In our calculations, we have taken the heat rate to the tur-
bines to be 11,700 Btu/kw-hr and the condenser load to be 8,200 Btu/kw-hr.
Although there will be circumstances^ when water costs more than
$1.20/thousand gallons and dry cooling will be economical, we have, through-
out this study, assigned all turbine condenser cooling loads to wet cooling.
The derivation of the cooling water requirement shown in the summary
charts can be seen from the following example for a Synthoil plant at
Colstrip, Montana:
9
Wet cooling load (Table 2-9) 4.1 x 10 Btu/stream hr T
1500 Btu/lb water evaporated (Table 2-12) x
0.0018 S^/calendar min = gals/calendar min .
Ib/stream hr
Treatment of cooling water yields waste sludges which are about 50%
moisture. These sludges are (i) derived from lime-soda softening and (ii)
derived from evaporation of the final blowdown water. For estimating pur-
poses we did not use cooling tower blowdown for any other water requirement.
We assumed sidestream softening to remove hardness with clarification to
remove, dirt introduced from the air. At all the sites the underflow from the
sidestream clarifier was enough blowdown to prevent excessive chloride in the
circulating water (see Ref. 8). This underflow is what has been called the
41
-------
Table 2-12. Water evaporation rates for wet cooling.
Location Btu/lb water evaporated
Colstrip, Montana 1500
Beulah, North Dakota 1576
Gillette, Wyoming 1488
Navajo/Farmington, New Mexico 1436
42
-------
Insoluble cooling treatment waste in Table 2-13. When the makeup water was
treated process condensate water (assumed to have 200 mg/1 Cl~) a liquid
blowdown was required in addition. The solids dissolved in this liquid
blowdown formed what we have called the soluble cooling treatment waste in
Table 2-13.
In the coal conversion plants treated process condensate was used as
makeup to the cooling tower. In some cases there was too much condensate
and the additional water was assumed used for boiler feed. In other cases
source water had to be added to the condensate to supply enough makeup.
When a mixed water source was used for the cooling tower we calculated the
sludges individually for the two sources separately and not for a blended water.
The wastes produced at each site are shown in Table 2-13. An example
of the calculation follows for cooling water treatment waste in a Synthoil
plant at Colstrip, Montana:
3
10 Ib/stream hr gal/calendar min
Dirty water to treatment (Table 2-5) 785
Less: water lost in treatment
1.8% of entry 14
Treated water 777
Clean condensate 144
Total condensate evaporated in
cooling tower 921 1658
Source water evaporated in
cooling tower 3261
Total water evaporated in
cooling tower 4919
43
-------
Table 2-13. Cooling water treatment waste.
Water
Colstrip, Montana
Beulah, North Dakota
Gillette, Wyoming (Yellowstone)
Gillette, Wyoming (North Platte)
Navajo/Farmington, New Mexico
Treated process condensate
tons wet sludge (50% moisture)
per 1000 gal water evaporated
insoluble
waste
0.0060
0.0070
0.0072
0.0078
0.0065
0.0049
soluble
waste
0.0067
* Used for power plant and gas plants.
** Used for oil plant.
44
-------
Insoluble waste =
gals 0.0060 tons 1440 min
» .X. -i /*i /-I /\ i A * "~
c. mm 1000 gal day
gals 0.0049 tons 1440 min
. X - f\f\f\ •» ^ , "
c. min 1000 gal day
= 40 tons wet sludge/calendar day
Soluble waste =
T/-CO gals 0.0067 tons 1440 min , - -,-,/,,,
1658 —°—:— x ., nnn : x — = 16 tons wet sludge/calendar day •
c. mm 1000 gal day 6 J
The makeup water to the cooling tower was arbitrarily taken to be
1.03 times the water evaporated corresponding to a nominal 34 cycles of
concentration. The makeup not evaporated or lost in sludge was assigned to
drift or leakage.
2.4 Lurgi Process
a. Process streams
The Lurgi process for the production of substitute natural gas
is a proprietary process for which not all details are available. However
complete plant designs have been made for four plants (Refs. 11 through 16).
We have examined these published designs and from them made various rules
from which to derive the water requirements at the four sites of the present study.
45
-------
To derive process water streams the following rules were used:
1. Product gas has a composition of 93 voli % methane and
4 vol. % hydrogen, and a heating value (HV) of 950 Btu/scf. The molecular
weight of the product gas is 16.2 Ib/lb mole and the scale of the plant
6 9
production is 250 x 10 scf/stream day = 9.9 x 10 Btu/stream hr.
2. HV of product gas/HV of gasifier feed coal = 0.678. Therefore
9
the HV of the as-received coal to the gasifier is 14.60 x 10 Btu/stream hr.
3. Ib of 02 to gasifier/lb of carbon and hydrogen in as-received
coal to gasifier = 0.455.
4. Ib of steam feed to gasifier/lb of carbon and hydrogen in
as-received coal to gasifier = 1.80.
5. Water decomposed by chemical reaction to supply hydrogen =
3
775 x 10 Ib/stream hr.
6. Purification is accomplished by the Rectisol process. Steam
3 3
needed is 128 x 10 Ib/stream hr and 124 x 10 Ib/stream hr of process
condensate is discharged from the purification stage.
7. Methanation water discharged is at 17.4% of the steam fed
to gasifier.
8. All sulfur and nitrogen in coal are converted to H«S and NH,
respectively and purged out during purification.
These rules give the hydrogen balances shown in Table 2-14. Using the
procedure of Section 2.2 for a gas plant (1.0 wt. % of dirty condensate
is lost in biotreatment and water in the sludge is 5 wt. % of the treated
water) the process water entries in the summary tables have been calculated.
As with Synthoil, 100 gal/calendar min has been added to the boiler makeup
water shown in Table 2-14.
46
-------
Table 2-14. Water equivalent hydrogen balance of Lurgi plant at four sites.
10 lb/stream hr
IN
Moisture in as-received coal
Water equiv. of hydrogen in coal
Steam to gasifier and purification
OUT
Dirty process and purification condensate
Clean condensate from methanation
Water equiv, of hydrogen in byproduct,,ELS,
and NH3
Water equiv. of hydrogen in product gas
Coal feed to gasification
Higher heating value of as-received coal (7^)
Moisture in as-received coal (%)
Colstrip,
Montana
419
488
1672
2579
1313
269
45
945
2572
1695
•«tU^ 0£ -, -,
Ib } 86U
24.7
Beulah ,
N.D.
770
520
1790
3080
1782
289
42
945
3058
2140
6822
35.0
Gillette,
Wyoming
484
529
1770
2783
1476
286
20
945
2727
1728
8449
28.0
Nava j o ,
N.M.
218
547
1732
2497
1172
279
35
945
2431
1756
12.
-------
b. Cooling
Because of the proprietary nature of the Rectisol gas purification
system and other parts of the plant we could not determine the auxiliary
heat loads to drive the plant. Instead we used the design efficiency from
Refs. 11, 12, 14 and 15 together with the design cooling water systems as
used in the Navajo area. Although much more cooling water is used in the
design of Ref. 14, we can not justify this.
The assumptions and results are given in Table 2-15. The assumed
thermal efficiencies are taken from the references. The higher efficiency in
New Mexico is mostly caused by the lower coal moisture. The by-product
heating value comes from the references. The total product heating value
9
includes the gas at 9.9 x 10 Btu/stream hr. From the plant efficiency the
total plant coal feed can be calculated and so can the coal fed as fuel. The
coal burnt as fuel requires stack gas scrubbing discussed in a later section.
The heat lost to wet cooling is taken to be 28% of the unrecovered heat as
used in the designs in New Mexico. From this heat the water evaporated for
cooling was calculated using Table 2-12 and the summary sheets were completed
using the procedure of Section 2.3.
2.5 Synthane Process
A design, for cost estimating purposes, has been made for the Synthane
process . From it we have taken the hydrogen balance shown in Table 2-16,
Because we do not have enough information to distinguish between coals fed
to the Synthane process,Table 2-16 was used at all four sites and the process
streams calculated according to Section 2.2 for gas plants are shown in detail
at all sites.
48
-------
Table 2-15. Assumptions and calculations on thermal efficiency
of Lurgi plants.
Colstrip, Beulah, Gillette, Mavaj o ,
Montana N.D. Wyo.
Assumed thermal efficiency (%) 65 65 65 70
Byproduct heating value as
% HHV of gas 13 12 13 20
Total product HV (109 Btu/stream hr) 11.19 11.09 11.19 11.88
Plant coal feed HV (109 Btu/stream hr) 17.22 17.06 17.22 16.97
Fuel coal feed HV (109 Btu/stream hr) 2.62 2.46 2.62 2.37
Fuel coal feed (103 Ib/stream hr) 304 361 310 285
Unrecovered heat (109 Btu/stream hr) 6.03 5.97 6.03 5.O9
Heat lost to wet cooling
(109 Btu/stream hr) 1.69 1.67 1.69 1.43
49
-------
Table 2-16. Water equivalent hydrogen balance for the Synthane
process using Wyodak coal.
Coal feed: 1,605,000 lb/stream hr of Wyodak seam subbituminous coal
(4.3 wt. % of moisture and 4.1 wt. % of hydrogen, heating value of
10,640 Btu/lb) used for gasifiers.
Product pipeline gas: 250 x 10 scf/stream day with heating value of
940 Btu/scf (92.3 vol. % methane and 1.8 vol. % hydrogen),
IN 103 Ib/stream hr
Moisture in coal fed to gasifier 69
Water equiv. of hydrogen in coal 592
Steam to gasifiers 978
Steam to shift converter 540
Makeup water to scrubber 476
2,655
OUT
Dirty process condensate from scrubbing and cooling 1,069
Dirty condensate from shift converter 411
Dirty condensate from purification 20
Clear condensate from methanation 142
Water equiv. of hydrogen in H?S and NH~ 3
Water equiv. of hydrogen in product gas 921
Water equiv. of hydrogen in char and tar from gasifier 42
2,608
50
-------
Ref. 17 is not satisfactory for estimating cooling water requirements
so we made our own thermal efficiency and cooling water calculations as
shown in Tables 2-17 and 2-18. The thermal efficiency of 62% may be low
9
but the unrecovered heat that is lost to wet cooling, 2.7 x 10 Btu/hr or
42% of the unrecovered heat, is certainly the maximum reasonable wet cooling
load and could be lower. In the Synthane plant all the coal is fed to the
gasifier and char is recovered and burnt to provide fuel for the plant.
To calculate the water required for flue gas desulfurization the char
production was taken to be 205.2 tons/stream hr with the composition:
C 63.64%
H 1.04%
0 1.43%
N 0.38%
S 0.26%
Ash 33.29%
HHV 9800 Btu/lb
The wet cooling load was taken to be invariant from site to site.
The thermal efficiency will vary with the moisture in the coal but this will
not affect the wet cooling load. The cooling water calculations were made
according to Section 2.3 and entered in the summary charts.
51
-------
Table 2-17. Approximate thermal efficiency for Synthane plant
at Wyoming .
9
10 Btu/stream hr
Coal feed 17.1
Gas product 9.8
Byproducts 0.8
Unrecovered 6.5
17.1
Approximate thermal efficiency = 62%
52
-------
Table 2-18. Approximate disposition of unrecovered heat
in Synthane plant at Wyoming.
10 Btu/stream hr
Direct loss Dry cooling Wet cooling
Coal drying
0.6
Stack loss (10% of char
burnt)
0.4
Gasifier off-gas scrubber
1.4
Gas purification
regenerator condenser
1.3
Lock hopper compressor
0.1
Oxygen plant compressors
1.1
Electricity (37,000 kw)
0.3
Process cooling and
unaccounted
1.2
1.1
2.7
2.7
53
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References
1. Akhtar, S., Mazzocco, N.J., Weintraub, M. and Yavorsky, P.M.,
"SYNTHOIL Process for Converting Coal to Non-Polluting Fuel Oil,"
presented at 4th Synthetic Fuels from Coal Conference, Oklahoma
State University, Stillwater, Oklahoma, May 1974.
2. Akhtar, S., Lacey, J.J., Weintraub, M., Rezik, A.A., and Yavorsky,
P.M., "The SYNTHOIL Process - Material Balance and Thermal Efficiency,"
presented at 67th AIChE Annual Meeting, Washington, B.C., December
1974.
3. Bureau of Mines, "Economic Analysis of Synthoil Plant Producing
50,000 Barrels per day of Liquid Fuels from Two Coal Seams: Wyodak
and Western Kentucky," Report No. ERDA 76-35, U.S. Dept. of the
Interior, November 1975.
4. Akhtar, S., Friedman, S., and Yavorsky, P.M., "Environmental Aspects
of Synthoil Process for Converting Coal to Liquid Fuels," in
Second Symposium on Environmental Aspects of Fuel Conversion
Technology, pp. 179-182, EPA Report No. EPA-600/2-76-149, June 1976.
5. Bureau of Mines, "An Economic Evaluation of Synthane Gasification
of Pittsburgh Seam Coal at 1,000 psia Followed by Shift Conversion,
Purification, Single-Stage Tube Wall Methanation and Pollution
Control, Pittsburgh Seam Coal," Report No. 74-31, U.S. Dept. of
Interior, June 1974.
6. McCrea, D.H., "The Benefield Activated Hot Potassium Carbonate Process:
Commercial Experience Applicable to Fuel Conversion Technology," in
Second Symposium on Environmental Aspects of Fuel Conversion Technology,
pp. 217-223, EPA Report No. EPA-600/2-76-149, June 1976.
7. Kastenbader, P.D. and Flecksteiner, J.W., "Biological Oxidation of
Coke Plant Weak Ammonia Liquor," JWPCF 41, No. 2, 199-207, 1969.
8. Gold, H., Goldstein, D.J., and Yung, D., "The Effect of Water Treat-
ment on the Comparative Costs of Evaporative and Dry Cooled Power
Plants," ERDA Report No. COO-2580-1, June 1976.
9. Goldstein, D.J. and Probstein, R.F., "Water Requirements for an
Integrated SNG Plant and Mine Operation," in Second Symposium on
Environmental Aspects of Fuel Conversion Technology, pp. 307-330,
EPA Report No. EPA-60012/76-149, June 1976.
10. Kelly's Handbook of Crossflow Cooling Tower Performance, Neil W.
Kelly & Associates, Kansas City, Missouri.
54
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11. El Paso Natural Gas Company, "Second Supplement to Application of
El Paso Natural Gas Company for a Certificate of Public Convenience
and Necessity," Federal Power Commission Docket No. CP73-131, 1973.
12. Western Gasification Company, "Amended Application for Certificate
of Public Convenience and Necessity," Federal Power Commission
Docket No. CP73-211, 1973.
13. Wyoming Coal Gas Co. and Rochelle Coal Co., "Applicant's Environ-
mental Assessment for a Proposed Gasification Project in Campbell
and Converse Counties, Wyoming," prepared by SERNCO, October 1974.
14. North Dakota Gasification Project for ANG Coal Gasification Co.,
"Environmental Impact Report in Connection with Joint Application
of Michigan Wisconsin Pipe Line Co. and ANG Coal Gasification Co.
for a Certificate of Public Convenience and Necessity," Woodward-
Clyde Consultants, Federal Power Commission Docket No. CP75-278,
Vol. Ill, March 1975.
15. Batelle Columbus Laboratories, "Detailed Environmental Analysis
Concerning a Proposed Gasification Plant for Transwestern Coal
Gasification Co., Pacific Coal Gasification Co., Western Gasifica-
tion Co., and the Expansion of a Strip Mine Operation Near Burnham,
New Mexico Owned and Operated by Utah International Inc.," Federal
Power Commission, February 1, 1973.
16. Moe, J.M., "SNG from Coal via the LURGI Gasification Process,"
IGT Symposium on Clean Fuels from Coal, Institute of Gas Technology,
Chicago, Illinois, September 1973.
17. Bureau of Mines, "Synthane Gasification at 1000 psia, Followed by
Shift Conversion, Purification, Single-Stage Tube Wall Methanation
and Pollution Control. Wyodak Seam Coal," Report No. 75-15, U.S.
Dept. of the Interior, November 1974.
55
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3. SHALE CONVERSION
3.1 Underground Mining and Surface Processing
The analysis of shale conversion in the present assessment is restricted
to the TOSCO II process by the program guidelines. In the TOSCO II process the
oil shale is mined underground and then processed on the surface. The surface
processing operation involves crushing the shale and then heating (retorting)
it to produce the shale oil. The retorted shale oil is too viscous to be
piped, and too high in nitrogen and sulfur to be used as normal refinery
feedstock so that it must also be put through a refinery upgrading process,
normally by hydrocracking. In addition, it is necessary to dispose of the
spent shale from the retorting, equal to about 80 to 85 percent by weight of
the originally mined shale with a volume before compaction averaging 50 percent
greater than its in-place volume, and even after maximum compaction at least
12 percent greater.
The water requirements for the mining and crushing of the raw shale will
be considered in Section 7 along with the same requirements for coal, since
the operations are quite the same as in the underground mining of coal, and
differ only in some details and in the quantities handled. Similarly the
water requirements for spent shale disposal will be considered in Section 8,
along with the water requirements for the solids and ash disposal in the coal
conversion processes. In this same section evaporation losses, plant dust
control and service and potable water needs will also be evaluated, since
they too agree in kind with those for the coal conversion processes.
It will be assumed that needed auxiliary electric power will be pur-
chased and not generated onsite. This is consistent with the TOSCO II
56
-------
design in which the process steam needed in the plant is generated by
burning fuel gas generated in the shale conversion.
3.2 TOSCO II Process
In the TOSCO II retorting scheme shown schematically in Fig. 3-1,
crushed shale of minus 1/2 inch size is preheated by pneumatically conveying
the shale upward through a vertical pipe concurrently with hot flue gases
from the ball heater. The flue gas is cooled during this process and the
cooled gas is passed through a venturi wet scrubber to remove shale dust before
venting to the atmosphere at a temperature of about 125 to 130 J.
The ball heater is a vertical furnace whose purpose is to heat up
ceramic balls of about a 1/2 inch in diameter. After the balls are heated
they are fed along with the preheated shale, which has been separated from
the flue gas in settling chambers and cyclones, into a horizontal rotating
kiln where the pressure is slightly above atmospheric. The mixture of balls
and shale flows through the kiln and the shale is brought to a retorting
temperature of about 900°F through conductive and radiative heat exchange
with the balls. The resulting hydrocarbon and water vapors are drawn off and
fractionated leaving behind a mixture of balls and processed shale.
The ceramic balls are size-separated from the spent shale, which is
a fine powder, by passage through a trommel (a heavy duty rotating cylinder
with many small holes punched in its shell). Warm flue gas is used to remove
residual dust from the ball circulation system. The dust is removed from
the flue gas with a venturi wet scrubber. The balls are then circulated back
to the ball heater, by-means of a bucket elevator, for reheating by burning
some of the product gas.
57
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FLUE GAS 6606PM PREHEAT SYSTEM
TO ATMOSPHERE i STACK
290 SPM
WATER
r^u-1
ISO GPM
FOUL WATER TO
rOUL WATER
PREHEAT SYSTEM
(INCLUDES INCINERATOR]
* ALL SCRUBBER SLUDGE STREAMS
TO PROCESSED SHALE DISPOSAL
** TO GAS RECOVERY AND
TREATING UNIT
Fig. 3-1.
TOSCO II retort flow diagram tor upgrading shale oil
output of 50,000 bbl per stream day with feed of 35
gallon per ton oil shale.
COVERED PROCESSED
SHALE CONVErOR
MOISTURIZED PROCESSED
SHALE TO DISP05«L
-------
The processed shale is cooled in a rotating drum steam generator. One of
the important features of the process is that the cooled spent shale is then
moisturized to approximately 14 percent moisture content in a rotating drum
moisturizer, after which it is transported by a conveyor belt for disposal.
The steam and processed shale dust produced in the moisturizing process are
passed through another venturi wet scrubber to remove the dust before
discharge to the atmosphere.
The importance of the moisturizing is that addition of the water to the
TOSCO type processed shale, at a predetermined shale temperature, appears to
lead to cementation of the shale after proper compaction. More importantly,
the cemented shale appears to "freeze" in the moisture which has been added.
Samples taken from a two year old spent shale embankment at depths of four
to six feet have indicated no change in moisture content from that existing
at the time of compaction, which amounted to about 12 percent, 2 percent hav-
ing evaporated during transportation . The shale seems to become effectively
impermeable and to resist percolation, so that soluble salts are not leached
out .
In the upgrading process the gas, oil and water vapors which are drawn
off are fractionated into gas, naptha, gas oil, bottoms oil, and foul water
streams (see Fig. 3-2). The gas oil produced by the retorting process is a waxy
oil which is high in nitrogen, contains a good deal of sulfur and is not pumpable.
A clean, pumpable oil with reduced nitrogen and sulfur levels is produced by a
proprietary hydrotreating process. The pour point of the bottoms oil is first
reduced by delayed coking prior to hydrotreating. Most of the gas which is produced
will be used as fuel for the production of process steam, although some of the
59
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PYROLYSIS
OIL AND GAS
GAS
FRACTIONATOR
NAPTHA
GAS OIL
BOTTOMS
COKER
SULFUR
LPG SPECIAL
GAS TREATING
AND
SULFUR RECOVERY
LIQUID C 's
FUEL GAS
HYDROGEN
PLANT
GAS
NAPTHA
KYDROTREATER
GAS OIL
HYDROTREATER
IJ
AMMONIA
AMMONIA
SEPARATION
LOW SULFUR FUEL OIL
DIESEL FUEL
COKE
Fig. 3-2. Flow diagram for TOSCO II shale oil upgrading refinery
-------
higher heating value gas is used as feed material for the production of the
hydrogen needed in the upgrading. Before the retort gas is burned hydrogen
sulfide would be removed with subsequent sulfur recovery. Ammonia will be
separated out and recovered as a liquid from the sour water produced in the
hydrotreating, while the sulfur will be recovered from the hydrogen sulfide
which is drawn off as a gas. The upgrading and cleaning process described
for the TOSCO II refinery resembles standard refinery processing procedure.
3.3 Water Streams for Retorting
In this section, we consider the retort water streams for the specific
conceptual design discussed in Ref. 1 of a plant retorting 35 gallon per ton
shale with a 50,000 bbl per stream day output of upgraded shale oil. On
Fig. 3-1, reproduced from Ref. 1 with some small changes, we have summarized
our derived values of the water streams, with all figures in gallons per stream
minute (gpm). To obtain the corresponding-streams for a 100,000 bbl/day
plant, it-is sufficient to simply double all the input and output figures.
The water quantities shown in Fig. 3-1 were derived from the water flow chart
of Fig. 3-3-, which was taken from Ref. 1 and to which some clarifications
ft
were added. It is not completely straightforward to distinguish the retort-
ing and upgrading streams in Fig. 3-3. Moreover, of particular importance in
the TOSCO process is the feature noted earlier that the wastewater fed into
the moisturizer which is not vaporized is sealed into the processed shale.
It can be seen from Fig. 3-3 that the only specifically noted water
addition to the retorting step is the 90 gpm leaving the crusher dust sup-
pression unit that is added to the raw shale. All of the other dust suppression
* Personal communications with TOSCO personnel.
61
-------
-350
RAW SHALE SURFACE
PYROLYSIS
AND
OIL RECOVERY
UNIT
25
STRIPPED WATER
PURGE FROM
ft = RIVER WATER SUPPLY
ALL BATES IN 6PM
* = WILL INCREASE TO 700 GPM
IN It YEARS
TOTAL RIVER WATER SUPPLY =
FOR YEARS I - II : 4970 GPU
FOR YEARS 12-20^ 5600 6PM
FOR DESIGN PURPOSES, NO CREDIT
TAKEN FOR SURFACE RUNOFF.
PROCESSED AMMONIA SEPARATION
SHALE
MOISTURI2ING
Fig. 3-3. TOSCO II process water streams for upgrading shale oil output of 50,000 bbl
per stream day with feed of 35 gallon per ton oil shale
-------
water totaling 110 gpm ±s sent directly to the moisturizer. The only water
noted to be specifically coming out of the retorting is 150 gpm listed as
water of retorting,which we take to leave as foul water on the retorting diagram
of Fig. 3-1. This amount of retort condensate water equals 3.27 gallons per
ton of shale processed, which compares favorably with the "typical" value of
2 to 5 gallons per ton of shale given in Ref. 3.
Next we indicate how our estimates were made for the amounts of water
which are put into the preheat system and ball circulation system stack gas
scrubbers, along with how much water leaves in the sludge from these scrub-
bers. This water stream will be tabulated again in Section 8 in connection
with the water leaving with the disposed solids. Together with the previous
two streams we have discussed, this makes up the total imported and exported
retort streams. Table 3-1 is a tabulation of the streams from Fig. 3-3
put together in a manner designed to provide estimates on the scrubber
streams. The assumptions it was necessary to make along with the various
dry tonnage flow rates taken from Ref. 1 are indicated.directly in the table,
which is reasonably self-explanatory. We emphasize that the estimates we
have arrived at can be no more accurate than our interpretations of the
streams given in Fig. 3-3. We note further, that some divergences do exist
between the flow rates of Fig. 3-3 and those deduced from typical data pro-
*
vided in Ref. 1. Therefore, we would emphasize that the figures given in
Fig. 3-1 are to be treated as estimates and not precise values.
We have shown on Fig. 3-1 the stream flows we deduced that are associated
with the moisturizer unit. We do not consider the water leaving with the spent
shale chargeable to the retort section, but rather we treat this stream as part
of the spent shale disposal system and as such we will discuss it in Section 8.
* For example, Tables 3 and 21.
63
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Table 3-1. Determination of TOSCO II retort water streams for
upgrading shale oil output of 50,000 bbl per stream
day with feed of 35 gallon per ton shale, on basis
of water balance for combined retorting and upgrading
steps 1.
Individual Total Makeup
gpm gpm gpm_
Water out in cumulative sludge from scrubbers 100
Water in to processed shale moisturizing from
retorting and upgrading 1,350
Moisture out in processed shale
(.14 x 53,625 tpd) (1.250)
100
Vapor out in preheat and ball circulation stacks 660
Assumed sources of vapor in stacks:
Water of combustion 280
Natural shale surface moisture 75
Moisture on shale from dust suppression 9Q
Makeup water 215
660
Water in to preheat and ball circulation scrubbers 310 310
Makeup water (from vapor calculation) 215
Sludge water* ([.3B/.62][925] tpd) 95
310
Water in to moisturizer scrubber 15 15
Makeup water (same ratio to sludge as above) 10
Sludge water* ([.3S/.62] 43 tpd) 5
15
Total clarifier sludge equals 968 tpd (925 tpd from preheat and ball
circulation scrubbers plus 43 tpd from moisturizer scrubber), while net
water in the cumulative sludge equals 100 gpm or 600 tpd. Solids there-
fore represent 62% of sludge. Approximate split shown in Fig. 3-1
between preheat and ball circulation scrubbers is based on same relative
ratios of water to dry solids.
64
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Table 3-1 (continued)
Individual Total Makeup
gpm
Water in to moisturizer 1,740
Moisture out in processed shale 1,250
Water out in moisturizer scrubber sludge 5
Vapor out In moisturizer stack 500
Water in to moisturizer scrubber (15)
1,740
Assumed sources of water in to moisturizer:
Cooling tower blowdown 300
Utility boiler blowdown 130
Regenerant wastes from deionizer 100
Dust collection 110
Stripped water 580
Stripped water from ammonia unit 25
Makeup water _ 495 495
1,740
Foul water out of pyro lysis and upgrading 370
Water of retorting 150
Steam used in upgrading 220
Total assumed to leave as foul water 370
Total water makeup from river 820
The 95 gpm of water in the effluent sludge from the preheat and ball
circulation scrubbers,' when added to the 150 gpm retort effluent condensate,
constitutes the exported water stream. The influent streams to the scrubbers
of 310 gpm plus the 90 gpm put into the raw shale feed makes up the imported
stream which is seen to amount to about half of the 820 gpm makeup water.
65
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3.4 Water Streams for Upgrading
From Fig. 3-2 it is seen that the major operations of the upgrading
process are fractionation, delayed coking, hydrotreating, and gas cleanup
and recovery. It is evident that the major water needs in such a system
are the cooling waters required for the fractionator and coker and the water
required for the production of hydrogen by steam reforming. The principal
effluents will be the cooling tower and boiler blowdowns and the sour
water generated in the hydrotreating and gas treating units.
In evaluating the water streams from the overall flow diagram of
Fig. 3-3, the quantity most difficult to determine is the amount of steam
consumed in the hydrogen plant. In Fig. 3-3, there is 920 gpm shown as
steam consumed. As an upper limit we can assume that all of this amount
represents steam consumption in the hydrogen plant. An alternate estimate
*
obtained from steam usage figures is 279,000 Ib/hr or 558 gpm. Table 3-2,
which is a compilation of the influent and effluent streams for the refining op-
eration; lists both figures. We have carried out a water equivalent hydrogen
balance for upgrading shale oil and find a minimum net consumption of about
40 Ib H.O/ton of shale or somewhat less than half of the lower of the two
figures. This makes the 558 gpm figure the more probable value.
All of the stream quantities shown in Table 3-2 are self-explanatory
and for the most part have been taken directly from Fig. 3-3. The exception
is the 220 gpm of steam, which was assumed in our retort calculation to be
used in the upgrading and to be converted to foul water (cf. Table 3-1).
We would note here, that we have carried out an approximate overall heat
balance for the TOSCO II retorting and upgrading process. The raw shale
* Fig. 38, p. 151, Ref. 1.
66
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ft
was taken to have a heating value of 3,070 Btu/lb . The net output of
materials of significant heating value not used in the 50,000 bbl/day plant
was taken to be 47,000 bbl/day of fuel oil, 4,330 bbl/day of .liquified
petroleum gas and 800 tons/day of coke . In addition, about 5% of the heating
value of the shale was assumed to be unused, consistent with the amount of
carbonaceous residue that remains with the spent shale in the TOSCO process.
Table 3-2. Compilation of TOSCO II refinery water streams for
upgraded shale oil output of 50,000 bbl per stream
day with feed of 35 gallon per ton shale, on basis
of water balance for combined retorting and upgrading
steps .
Imported
Steam used in upgrading
Wash water to gas treating unit
Steam to coker
Cooling tower makeup
Steam consumed in hydrogen plant
Total
Exported
Foul water converted from steam used in upgrading
Foul water out of gas treating unit
Foul water out of coker
Cooling tower blowdown
Boiler blowdown
Total
220
180
30
1,300
558 - 920
2,288 - 2,650
220
180
30
300
130
860
67
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Assuming 1,200 Btu removed per pound of water evaporated, it was found that
the 1,000 gpm of water evaporated in the cooling tower corresponds to a
heat loss of about 20 to 25% of the total heat dissipated in the plant. The
upper limit assumes additional unaccounted losses of about 5%. This would
indicate a well designed cooling system that is probably not too far off
optimum.
3.5 Process and Cooling Water Consumption
From the water stream quantities detailed in the preceding two sections,
the net process and cooling water consumption for the TOSCO II plants can
be specified in a format consistent with that for the coal conversion
processes.
The net consumption of retort water associated with a 50,000 bbl per
stream day plant can be determined from Table 3-1. The retort water con-
sumption is made up of the 215 gpm of makeup water and 90 gpm of dust sup-
pression water leaving in the preheat and ball circulation stacks plus the
net of 490 gpm leaving as vapor out the moisturizer stack. The net consump-
tion is therefore 795 gallons per stream minute or 716 gallons per calendar
minute with a 90% load factor. Although the vapor leaving in the moisturizer
stack is charged to the retort, the processed shale moisture and scrubber
sludge waters are charged to solids disposal and as such are considered in
Section 8.
From Table 3-2 the net water consumption in the refining is seen to range
between 428 and 790 gpm, after subtracting the 1,000 gpm evaporated in the
cooling towers. From our discussion in Section 3.4 the lower value is the
more probable one but we have taken the average of 609 gallons per stream
minute to ensure the presentation of a conservative water consumption estimate.
With a 90% load factor this corresponds to 548 gallons per calendar minute.
68
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We have already discussed in Section 3.4 the evaporated cooling water
rate of 1,000 gpra. We assume that this figure also includes the drift and
leakage losses. For consistency with our own detailed cooling calculations
the drift and leakage losses are taken at 3% of the amount evaporated. In
that case, at a 90% load factor we would have a total of 900 gallons per
calendar minute lost in the cooling towers with 845 gpm evaporated and
26 gpm lost to drift and leakage.
As noted earlier the corresponding water rates for a nominal 100,000 bbl/day
plant are obtained by doubling the rates discussed.
References
1. Colony Development Operation, "An Environmental Impact Analysis for a
Shale Oil Complex at Parachute Creek, Colorado, Part 1 - Plant Complex
and Service Corridor," Atlantic Richfield Company, Denver, Colorado, 1974.
2. Metcalf & Eddy Engineers, "Water Pollution Potential from Surface Disposal
of Processed Oil Shale from the TOSCO II Process," Vol. I, a report to
Colony Development Operation, Atlantic Richfield Co., Operator, October 1975.
3. U.S. Department of the Interior, "Final Environmental Statement for the
Prototype Oil Shale Leasing Program," Vol. I, U.S. Gov't. Printing Office,
Washington, D.C., 1973.
4. Hendrickson, T.A. (editor), Synthetic Fuels Data Handbook, p. 30,
Cameron Engineers, Inc., Denver, Colorado, 1975.
69
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4. STEAM ELECTRIC GENERATION
In this section are described the methods used to determine the choice
between evaporative (wet), dry or wet-dry cooling for a coal-fired steam
electric generating plant at the six sites considered. The makeup water
requirements and residuals generated for evaporative or wet-dry cooling
towers are also specified. The consumptive water requirements (and total
residuals generated) for flue gas desulfurization, mining, and evaporation,
solids disposal and other uses for coal-fired steam electric generating
plants are discussed in Sections 6 through 9.
At each site dry cooled steam electric generating plants with mechanical
draft towers are compared to evaporative cooled plants using mechanical draft
towers. Only at Navajo/Farmington, New Mexico are wet-dry mechanical draft
towers compared to both dry and evaporative towers. The choice of a particular
cooling system is made on an economic basis, that is, by comparing the total
annual evaluated costs of dry, wet-dry and evaporative cooling systems. In
the cases of wet-dry and evaporative cooling systems the cost of water has
been included. The cost of water comprises the cost of supplying the makeup
water, the cost of treatment of the makeup and/or the circulating water in
the tower, and the cost of treatment and disposal of the blowdown in an
environmentally acceptable manner.
4.1 Costs of Cooling Systems
In an evaporative cooling tower the hot water from the condenser is cooled
by direct contact with air. The lowest possible temperature to which the hot
water can be cooled~~corresponds to the wet bulb temperature of the air. This
is not a practical limit since an infinitely tall cooling tower would be
70
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required. The difference between the temperature of the water leaving the
tower (or entering the condenser) and the wet bulb temperature is called the
approach temperature in an evaporative cooling tower. Since most evaporative
cooling towers operate over the same range the 'approach temperature determines
the size of the tower. For a given cooling range (difference between hot
water and cold water'temperatures) the smaller the approach temperature the
larger the tower with concomitant higher capital costs. This, and other
nomenclature, is shown in Fig. 4-1.
In a dry cooling tower the initial temperature difference primarily
determines the size and capital cost of the tower. The initial temperature
difference is defined as the difference in temperature between the tempera-
ture of the circulating cooling water entering the tower and the entering
air temperature (Fig. 4-1). The cooling range is the amount by which the
circulating water is cooled as it passes through the tower and is equal to
the temperature rise across the condenser. The larger the initial tempera-
ture difference, the less air-cooled area is required to reject a given amount
of heat, and the less the capital cost of the cooling system. However,
increasing the initial temperature difference increases the turbine exhaust
pressure which results in lower efficiency and a loss of generating capacity.
In dry cooling systems the cooling range is normally specified as a percentage
of the initial temperature difference, and for the purposes of this study was
taken to be 50 percent of the initial temperature difference. In the case of
surface condensers the capital cost of the cooling system and the performance
obtained with this system is also dependent on the terminal temperature
difference,which is the difference between the saturation temperature corres-
ponding to the turbine back pressure in the condenser and the circulating water
71
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AIR
STEAM
CONDENSER
CONDENSATE
AIR
Evaporative
Cooling
Dry
Cooling
Range
T - T
3 2
Approach
T_ - T. (wet bulb)
2 4
Initial Temperature Difference
(dry bulb)
Terminal Temperature Difference
(Sat.) -
(Sat.) -
Fig. 4-1. Cooling tower nomenclature.
72
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leaving the condenser (Fig. 4-1). The greater the terminal temperature
difference the less condenser heat transfer surface area required to reject
a given amount of heat, and the lower the capital cost of the condenser.
Since the performance of a power generating plant is dependent upon
the temperature of the steam condensing in the condenser, the lower the
condensate temperature the higher the plant efficiency. A cooling system
that is designed for a small range and a small approach for the cooling
tower would be very large with concomitant higher capital costs and capital
related charges and would allow the power generating plant to operate at
lower turbine back pressures (lower condensing temperatures) with lower heat
rates and concomitant lower fuel costs. Conversely, a cooling system designed
for a large range and a large approach for the cooling tower would be rela-
tively small with concomitant lower capital costs and lower capital related
charges; however the power generating plant would have to operate at a higher
turbine back pressure (higher condensing temperatures) with higher heat rates
and concomitant higher fuel costs. Economic evaluations of cooling systems
must therefore account for the effect of the size of the cooling tower on
the efficiency of the power generating plant. Loss of plant capacity due to
higher heat rates must be charged against the cooling system as a penalty
cost. The economic optimum design or minimum cost operation is dependent on
the climate and will vary from location to location.
Since only differences between wet and dry cooled systems are of interest
here, only those costs associated with the choice and design of the cooling
system are included in the analysis. The factors considered in an economic
optimization procedure include the size and annual capital charges of the
cooling system, annual performance of the turbine generator including loss of
73
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generating capability at higher ambient temperatures, annual fuel costs,
annual cost of auxiliaries, and annual operating and maintenance costs.
These factors are discussed in detail in Refs. 1, 2, 3 and 4 and will be
briefly discussed here together with the input pricing data used for the
numerical calculations.
In order to make a direct comparison it was assumed that the dry cooled
plant produced the same nominal generating output as the evaporative cooled
plant with which it was compared. At all sites but Rifle, Colorado, it was
assumed that a nominal 3000 MWe was generated; at Rifle, Colorado, a nominal
1000 MWe was assumed to be generated. It was further assumed that the
turbines operated at a constant throttle "full-load" condition during all
hours of operation except when the turbine generator was throttled back to
a part-load condition to avoid exceeding the specified turbine back pressure
limit. The load factor was taken to be 70 percent. The total annual hours
of operation was 6132 based on full operation during each month except for
the month of March, when the plant was completely shut down for maintenance,
and the month of April, when the plant was partially shut down for maintenance.
Energy was credited as an excess, or penalized as a deficit, if the plant
produced more or less energy than the nominal generating output.
Capital cost of cooling system. The capital cost includes the capital expen-
diture for installation and materials necessary to construct the cooling
system. The major components of the cooling system include the condensers,
the cooling tower (evaporative, dry or wet-dry) and associated equipment, and
circulating water facilities including piping, valves, pumps, pump drives
and storage tanks. For dry cooling systems, additional capital costs are also
included. These are associated with a supplemental mechanical-draft evaporative
74
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cooling system used for auxiliary cooling, the added cost of a turbine
generator suitable for operation at high exhaust pressures, and the addi-
tional steam supply required by the high exhaust pressure turbine in order
to produce its rated output.
The small supplemental mechanical draft evaporative cooling system
is used to supply cooling water for the plant auxiliary equipment during
hot weather when the temperature of the cooling water leaving the dry tower
exceeds 95 F, the present standard temperature for auxiliary cooling water.
The supplemental evaporative cooling system was designed with a heat rejec-
tion capacity of 1.3% of the condenser heat load. The heat rejection capa-
city of the supplemental cooling system is 195 x 10 Btu/stream-hr for the
3000 MWe plants, and 65 x 10 Btu/stream-hr for the 1000 MWe plant. The
total evaporative water loss for the supplemental cooling system was
calculated to be not more than 70 x 10 gallons per year. This is to be
9
compared to an evaporative water loss of 7.0 to 7.8 x 10 gallons per year
from an all evaporative cooling system for a 3000 MWe fossil fuel
generating plant (see Table 4-6). This corresponds to a supplemental cooling
system requirement for the dry cooling system of not more than one percent
of the 3000 MWe wet cooling system evaporation loss. Although the capital
cost of the supplementary evaporative cooling system as well as the power
costs were included in the capital and annual evaluated costs of the dry
cooling system the costs of water supply, treatment, and blowdown disposal
for the supplemental tower were not included in the total annual evaluated
costs of the dry cooling system. These water costs have been assumed to be
negligible.
75
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Dry cooling tower costs are based on the latest pricing information
furnished by Hudson Products Corporation for their "Power Tower" module
and are an update of the pricing data incorporated in the computer program
described in Ref. 3. Capital costs and fan power requirements for the
evaporative cooling system are based on the results presented in Ref. 4.
The costs presented in Ref. 4 for the so-called "Middletown" site are
January 1, 1973 national average costs and have, in the present study, been
escalated to mid-1975, in accordance with the Handy-Whitman Index for
miscellaneous power plant equipment, to correspond to the Hudson dry cooling
tower cost data. Pricing data for other components of the evaporative and
dry cooling systems are described in Ref. 1. The condenser tubes for both
the dry and evaporative cooling systems are made either of corrosion-resistant
Admiralty brass with an outside diameter of 1.0 inch and a wall thickness of
18 BWG, or of stainless steel,at the same cost. Single pressure operation
was assumed for the surface condensers. All costs are based on 1975 dollars.
Construction was assumed to be initiated in early 1975 with start-up of the
cooling tower scheduled by the end of 1977.
Annual capital cost; An annual fixed charge rate is applied to the capital
cost of the cooling system to determine the annual cost of interest, amor-
tization and other charges incidental to the acquisition and use of the initial
capital expense. An annual fixed charge rate of 15 percent was used in the
present study.
Annual cost of operation and maintenance: This is the cost of operating and
maintaining the cooling system and is figured as a percentage of the capital
76
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cost of the cooling system. In the present study, annual operating and
maintenance costs were taken to be one percent of the capital cost of
the cooling system.
Annual credit for excess power generation: As noted above the annual
operating profile assumed 6132 hours of operation per year at constant
throttle full-load conditions except when the turbine-generator was throttled
back to a part-load condition to avoid exceeding the specified back pressure
limit of the unit. At some ambient temperature conditions the cooling system
may operate at a lower turbine exhaust pressure and generate a greater output
than the nominal generating output of 1000 MWe or 3000 MWe. The annual credit
for excess power generation is the product of the average fuel cost per kwh
and the excess energy generated. The unit cost of fossil fuel was taken
to be $0.50 per 10 Btu; with an assumed heat rate of 10,000 Btu/kwh for the
conventional turbine generator, the fuel cost is 5 mills/kwh .
Annual cost of replacement energy: For each cooling system sufficient peaking
capacity must be installed to make up the difference in generator energy
output between the unit and the nominal output when the nominal output is not
obtained. It is assumed that the nominal capacity need not be met for the
ten highest temperature hours of the year. The'cutoff temperature for peaking
generation was taken to be 82°F (27.8°C); above this temperature replacement
energy is assumed to come from installed gas turbine units at a fuel cost of
35 mills/kwh and below this temperature replacement energy is assumed to be
provided by excess capability available elsewhere on the utility system at
a fuel cost of 6 mills/kwh. The capital cost of replacement capacity was
assumed to be $175/kw based upon the maximum kw; the annual replacement capacity
cost is calculated on the basis of an annual fixed charge of 15 percent.
77
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Annual cost of auxiliary power: This is the cost of the power necessary to
run the cooling system. The auxiliary power consists of the fan power
necessary to maintain air circulation through the cooling tower, and the
pumping power necessary to maintain water circulation through the cooling
system. The energy cost for the auxiliaries is based on the fuel cost for
the plant, and, as noted above, is taken to be 5 mills/kwh for a conventional
turbine generator, with an allowance of 0.2 mills/kwh for operation and
maintenance. The incremental cost of sufficient additional plant capacity
to provide the auxiliary power required is assumed to be $400/kw based on
the maximum auxiliary power; the annual cost of auxiliary power is calculated
on the basis of an annual fixed charge of 15 percent.
Annual fuel cost: As noted previously the unit cost of fuel is $0.50 per
10 Btu; with an assumed heat rate of 10,000 Btu/kwh for the conventional
turbine generator the fuel cost is 5 mills/kwh .
A summary of the unit price data is found in Table 4-1.
4.2 Comparison of Dry and Evaporative Cooling Systems Not Including the Costs
of Water
Two comprehensive computer programs developed at R. W. Beck and Associates
were used to facilitate the optimization analyses of the dry and evaporative
cooling systems. The general elements of the computer program for the dry
cooling system are described in Ref. 1; a detailed updated version of this
program is described in Ref. 3. The description of the computer program
developed by R. W. Beck and Associates for the evaporative cooling system has
not been published in the literature. Comparable input pricing data was used
for each computer program in order to obtain a meaningful comparison between
the dry and evaporative cooling systems at each site.
78
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Table 4-1. Summary of unit price data.
Annual Fixed Charge Rate (percent) 15
Unit Fuel Cost ($/106 Btii) 0.50
Replacement Capacity Charge Above
82°F ($/maximum kw) 175
Replacement Capacity Charge Below
82°F ($/maximum kw)
Replacement Energy Cost At and Above
82°F (mills/kwh) 35
Replacement Energy Cost Below
82°F (Mlls/kwh)
Auxiliary Power Capital Cost
($/maximum kw) 400
Auxiliary Energy Cost *
Interest During Construction (percent) 8
Construction Period (years) 2
Scheduled Start-up (year) 1977
* Based on average fuel cost plus operation and maintenance.
O&M is 4% of average fuel cost.
79
-------
The meterological data at five of the six sites were obtained from
either the Decennial Census of United States Climate' (Summary of Hourly
Observations) or from the National Climatic Center of the National Oceanic
and Atmospheric Administration, Asheville, North Carolina. This data con-
sists of 10-year average data of the mean annual dry-bulb temperature
over the range of relative humidities and the frequency of occurrence at
five degree intervals of dry-bulb and wet-bulb temperatures. Meterological
data for Kaiparowits/Escalante, Utah were based upon data gathered from
Southern California Edison Company at Nipple Beach, a plateau located in
Kane County, Utah, near the site of the proposed plants. This data was
collected over a three year period from November 1971 to February 1975.
At each site the dry cooling systems were optimized and evaluated
with high back pressure turbine-generators, that is, turbines limited to
15.0 inches Hg absolute exhaust pressure, as well as turbine generators of
conventional design, that is turbines limited to 5.0 in Hg absolute. Dry
cooling systems with high back pressure turbine-generators are generally smaller
in size, with concomitant smaller capital costs than those utilizing conven-
tional turbine generators; however, they are not as thermally efficient and
result in higher fuel costs. The evaporative cooling systems were optimized
and evaluated with turbines of conventional design. The results that are
presented in this section for the evaporative cooling system do not include
the costs of water. The water costs will be detailed in Section 4.3.
Figure 4-2 presents the annual evaluated costs for the dry cooling
system with high back pressure turbine-generators as well as turbine-generators
of conventional design at Navajo/Faraington, New Mexico as a function of the
initial temperature difference. Similar results have been obtained at the
80
-------
ta
8
13
11
CO
W
a
e
135
120
/ Conventional Turbine Generators
High Back Pressure Turbine
f Optimum Design
20
30
40
50
60
70
80
90
Temperature ( F)
Fig. 4-2. Annual evaluated cost of dry cooling system as a function
of the initial temperature difference for Navajo/Farmington, New Mexico.
o
o
•a
w
•p
M
X
>
W
93
90
I I
I I
I I I 1
20
25
I I t
30
Range ( F)
Fig. 4-3. Annual evaluated cost of evaporative cooling system as a
function of cooling range for Navajo/Farroington, New Mexico.
81
-------
other five sites. The total annual evaluated cost of the cooling system
Is the algebraic sum of the annual capital cost, the annual cost of opera-
tion and maintenance, the annual cost of replacement energy and capacity,
the annual cost of auxiliary power and the annual fuel cost, with credit
given for excess power generation. The optimum design corresponds to the
minimum annual evaluated cost. As expected, with the relatively low fossil
fuel costs the dry cooling system evaluated better with the high back
pressure turbine-generators in all cases.
The annual evaluated costs for evaporative cooling systems are presented
in Figure 4-3 as a function of the cooling range for a turbine-generator of
conventional design for the Navajo/Farmington, New Mexico site. The curve
has already been optimized relative to the approach temperature. For a
given design back pressure the lowest cooling range considered generally
resulted in the lowest annual evaluated cost. The curves are essentially
flat at the minimum range and therefore this condition can reasonably be
accepted as the optimum design condition. Similar results were obtained at
the other five sites.
The optimized results for the Navajo/Farmington, New Mexico site are given
in Tables 4-2 through 4-4. Table 4-2 presents a summary of design conditions
for the optimized dry and evaporative cooling systems. Table 4-3 gives a
summary of the capital costs for the optimized cooling systems while a summary
of the energy and power quantities are given in Table 4-4. It has been assumed
that the overall thermal efficiency of the power plant with conventional
turbines is 35 percent with approximately 48 percent of the heat dissipated
to either the wet tower or the dry tower. Of the 17 percent remaining heat,
82
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Table 4-2. Summary of design conditions for optimized cooling systems at Navajo/Farmington, New Mexico.
Average Annual Dry-Bulb Tempera ture,°F
Average Annual Wet-Bulb Temperature,°F
Design Wet-Bulb Temperature,0?
Ambient Temperature for Determination of
Peaking Capacity Requirement, °P
Initial Temperature Difference,°P
Design Cooling Range, °F
Design Approach Temperature , °F
Design Terminal Temperature Difference,°F
Design Inlet Temperature, °F
Turbine Exhaust Pressure, in Hga
Total Tower Heat Load, 106 Btu/stream hr
Condenser Duty, 10 Btu/stream hr
Circulating Water Flow, 103 gallons per
stream min.
Condenser
Surface Area, 103 sq.ft.
Number of Tubes, 103
Tube length, ft.
Velocity through tubes, ft/sec.
Dry Cooling
Conventional Turbine
51
97
31
15.5
6.0
79.6
2.0
13939.8
13761.0
1782
1653
129
49
6.95
Dry Cooling
High Sack
Pressure Turbine
51
97
67
33.5
5.0
85.0
3.8
15637.2
15438.3
912
1357
136
38
6.73
Evaporative
Cooling
51
40
64
26.4
28.0
7.0
92.0
3.5
14166.0
13983.0
1072
1314
156
32
6.81
-------
Table 4-3. Summary of capital costs for optimized cooling systems (10 Dollars) at Navajo/Farmington, New Mexico-
Cooling Tower
Circulating Water Facilities
Electrical
Condenser
Suplemental Evaporative Cooling
System for Auxiliary Cooling
Interest During Construction
Additional System Supply Required
by High Exhaust Pressure Turbine
Total Cooling System Erected
Capital Cost
Incremental Plant Capacity to
Provide Auxiliary Power
Replacement Capacity for Peaking
Total Capital Investment
Dry Cooling
Conventional Turbine
142.466
14.418
16.774
.751
27.141
201.550
37.533
15.192
254.275
i*xy ^ouxxn^
High Back
Pressure Turbine
75.979
7.237
12.125
.751
14.967
8.094
119.153
20.363
16.867
156.383
Evaporative
Cooling
11.911
7.492
2.477
11.824
4.968
38.672
7.703
6.750
53.125
CO
.e-
-------
Table 4-4. Summary of energy and power quantities for optimized cooling systems at Navajo/Farmington, New Mexico.
Gross Annual Energy Generation
of Plant, Mwh
Excess Energy Generation, Mwh
Replacement Energy
Above 82°F, Mwh
Below 82°F, Mwh
Maximum Replacement Capacity
Above 82°F, kw
Below 82°F, kw
Auxiliary Energy, Mwh
Maximum Auxiliary Power, kw
Dry Cooling
Conventional Turbine
18,602,334
215,790
9,765
0
78,870
-7,980
441,825
103,491
Dry Cooling
High Back
Pressure Turbine
18,631,773
255,096
19,629
0
104,445
6,939
306,339
55,506
Evaporative
Cooling
18,414,933
47,403
10,872
12,840
38,571
13,674
118,080
19,257
00
Ul
-------
approximately 10 percent is dissipated through the stack gases, 3 percent
to reheat the fuel gas after desulfurization, and approximately 4 percent
is dissipated through in-plant losses.
A breakdown of the annual evaluated costs for the optimized cooling
systems are presented in Table 4-5 for Navajo/Farmington, New Mexico. The
principal cost difference between the three systems considered is due to
the size or capital cost of the cooling tower, followed by the difference
in the cost of the auxiliary power arid energy. The annual plant fuel cost
is substantially higher for the dry cooling system with the high back
pressure turbine generator as compared to the other two systems. These
trends were found for the five other sites studied.
Table 4-6 compares the total evaluated costs of the optimum dry cooling
system with high back pressure and conventional turbines, with those of the
optimum evaporative cooling system at each of the sites. It is to be
emphasized that the cost of water is not included in the evaporative cooling
costs. The difference in the annual evaluated cost between the optimum dry
cooling system and the optimum evaporative cooling system is also shown in
the table. As noted previously the difference is due primarily to the
difference between the annual capital costs of the two systems. The break-
even water costs, expressed as $/1000 gallons of evaporated water, are also
shown in Table 4-4. This quantity is the ratio of the difference in the
total evaluated costs between the optimum dry and evaporative cooling system
to the total quantity of water evaporated in a year from the evaporative
cooling tower. The breakeven water cost represents the total cost of water
for which the total annual cost of an evaporative cooling system (including
the costs of water) is equal to the total annual cost of a dry cooling system.
86
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Table 4-5. Breakdown of Annual Evaluated Costs for Optimized
Cooling System at Navajo/Farmington, New Mexico (10^ dollars/yr),
Dry Cooling
Conventional High Back Evaporative
Turbine Pressure Turbine Cooling
Annual Capital and
Operation and
Maintenance. Cost of
Cooling System 31.664 18.163 6.187
Annual Plant Fuel Cost 82.239 88.081 82.218
Credit for Excess
Generation -0.952 -1.202 -0.210
Annual Replacement
Capacity and
Energy Cost 2.412 3.429 1.470
Annual Auxiliary Power
and Energy Cost 8.250 4.840 1.706
Total Annual Evaluated Cost 123.613 113.311 91.371
87
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Table 4-6. Comparison of total annual evaluated costs of optimized cooling systems and breakeven water costs.
SITE
COLSTRIP, MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO*
NAVAJO/FARMINCTON,
HEW MEXICO
KAIPAROWITS/ESCAL.1NTE
UTAH
COLSTRIP , MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARM1HGTON,
HEW MEXICO
KAIPAROWITS/ESCALANTE
UTAH
Total Annual Evaluated Costs
do6 dollars/yr)
Evaporative Cooling
Dry Cooling Without Costs of Water Difference
Conventional Turbines
123.204 91.122 32.082
124.605 91,554 33.O51
128.110 -90.426 37.584
43.451 30.482 12.969
123.612 91.371 32.241
127.971 92.001 35.970
High Back Pressure Turbines
112.467 91.122 21.345
112.362 91.554 20.808
112.140 90.426 21.714
38.284 30.482 7.802
113.310 91.371 21.939
114.753 92.001 22.752
Total Water
Evaporated
(10s gallons/yr)
7377
7023
7398
2567
7686
7764
7377
702J
7398
2567
7686
7764
Breakeven water
Costs (S/1000 gallons
of evaporated water)
4. 35
4.71
5.08
5.05
4.19
4.63
2.89
2.96
2.94
3.04
2.85
2.93
* 1000 MWe, all others 3000 MWe .
-------
If the actual water cost does not exceed the breakeven water costs, an
evaporative cooling system would be selected; if the actual cost of water
exceeds the breakeven water cost, dry cooling would be selected.
4.3 Costs of Water
The cost of water comprises the cost of supplying the makeup water,
the cost of treatment of the makeup and/or the circulating water in the
tower, and the cost of treatment and disposal of the blowdown in an
environmentally acceptable manner. In this section the water treatment
methods used to control the circulating water concentration and the blow-
down treatment and disposal methods used to meet the disposal regulations
are briefly delineated together with their costs. Water supply costs are
also discussed. A more extensive discussion is found in Reference 6.
Circulating Cooling Water Treatment and Blowdown Disposal
The treatment of circulating cooling water is intended to prevent the
problems of scaling, fouling, microbial growth and corrosion. Salts
dissolved in the makeup water to the cooling tower are concentrated often
to the point of precipitation because of the large evaporative losses. The
precipitate, which usually consists of carbonates, sulfates and phosphates
of calcium and magnesium together with silica, tends to adhere to heat
transfer surfaces forming a hard scale and lowering the heat transfer coef-
ficient. This must be prevented by limiting the concentration of the calcium,
magnesium and silica salts.
Suspended matter in the circulating water settles out in stagnant spots
in the pipes and heat exchangers. The circulating cooling water contains
an ever increasing amount of suspended matter in the form of silt in the
89
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makeup water and in the form of dust scrubbed out of the air by the circu-
lating water in its passage through the tower. The suspended matter must
continuously be removed from the circulating cooling water.
Circulating cooling water is warm and well oxygenated and receives a
steady supply of oxygen for air-borne growth. Untreated cooling systems
are subject to fungal rot of the wooden parts of the tower, bacterial
corrosion of iron and bacterial production of sulfide, and large growths
of algae in the sunlit portions of the tower. Biocidal chemicals must
be added to control growth.
The control of corrosion with chemicals has not been considered since
the condenser heat transfer surfaces are made of copper alloys or stain-
less steel which minimizes corrosion. However chlorides have been limited
to 3000 mg/1 to prevent corrosion on stainless steel. This does not apply
if copper-alloy condensers are used. This limitation on chloride also
restricts the drift salt concentration and minimizes damage to local vegeta-
tion and groundwater supplies.
Table 4-7 lists the control limits for cooling tower circulating cooling
water used in this study.
In a recent study general methods of treatment of the makeup and
circulating cooling waters to prevent scaling, fouling and microbial growth
have been presented together with their costs. Emphasis was placed on
finding water treatment disposal systems which minimize the total evaluated
cost. The results have shown that the total evaluated cost is minimized by
evaporating the highest possible fraction of the makeup water. Higher con-
centrations increase the cost of treatment of the circulating cooling water
but this is more than off-set by the reduced cost of supplying the makeup
90
-------
Table 4-7. control limits for cooling tower
circulating water composition.
Suggested at
high pH with
Conventional at
low pH*
pH 6-5 to 7.5
Suspended Solids (mg/1) 200 - 400
Ca x C03 (as CaCC>3) 1,200
Carbonates (mq/1) 5
high concentration Used in
and dispersants* this study
7.5 to 8.5
300 - 400 300
**
6,000 6,000
5 5
Bicarbonates (mg/1)
50 - 150
300 - 400
300
Silica (mg/1)
150
150 - 200
150
Mg x Si02 (mg/1)
Ca x SQ (as CaCO )
35,000
1.5 x 106 to
2.5 x 106
60,000
2.5 x 106 to
Q x 106
60,000
2.5 x 10
Chlorides
3,000
* From Ref. 1•
** Dtore data needed to confirm (footnote from Ref. 7) .
91
-------
water and disposing of the solid residuals in an environmentally acceptable
manner. Four sites were studied to illustrate minimum water consumption
and minimum cost treatment and disposal systems. The results of Ref. 6
have been extended to the six sites considered in the present study. These
results are presented below.
One of the major limiting factors requiring treatment is the dust that
is scrubbed out of the air in the cooling tower and concentrated in the
circulating cooling water. Treatment of the makeup water does not affect
this limit and it is for this reason that the makeup water, as distinct
from the sidestream of the circulating water, has not been treated. The
dust scrubbed out of the air has been estimated by a technique described
in Ref. 7. The dust flow is calculated to be 38 Ib/min; about 20 percent
of the dust is suspended in the water with the rest settling in the basin
or not being trapped. The resultant input dust rate is 7.6 Ib/min. With
this input dust rate and a suspended solids limitation of 300 mg/1 the
control of suspended solids only by blowdown would mean a blowdown'rate of
about 6000 gpm (for an evaporation rate of 20,000 gpm) and a maximum con-
centration of 4.3 cycles. Sidestream separation of suspended solids has been
used in every case. Clarifiers have been used with the overflow from the
clarifier assumed reduced to 100 mg/1 suspended solids. The underflow of a
clarifier that is used exclusively for dust and dirt removal is assumed to
be 1% suspended solids with an underflow rate not larger than 2% of the feed
rate. (Larger underflow rates reduce the concentration). When lime precipi-
tation also occurs the suspended solids concentration in the underflow can
be higher than 1%.
92
-------
Synthetic flocculants are added to the clarifier feed at a rate of
1 mg/1 at a cost of $1.60/lb. When lime is not added alum is added at a
rate of 20 mg/1 at a cost of 5.3c/lb.
In some designs a clarifier effluent concentration of 100 mg/1 sus-
pended solids is not good enough and a filter has been added. The supplied
costs of automatic backflushed gravity sand filters is approximately $150/ft
2
at a flow rate of 2 gpm/ft for a cost of $75/gpm.
Synthetic polymeric dispersant chemicals (antifoulants) are added to
the circulating water at a cost of 3C/1000 gallons of sidestream flow.
The usual way to prevent scaling when high cycles of concentration are
used is to remove calcium, magnesium, bicarbonate, phosphate and silica.
When the four ions and silica are removed calcium sulfate or the chloride
ion will usually be what limits further concentration. A common procedure
used to remove the calcium and magnesium ions is to precipitate with lime
and soda ash. This lime-soda softening procedure was used to treat the
sidestream flows at all of the sites considered. The quantities of lime
Q
and soda ash required are estimated from well known relations , and will
not be repeated here.
Silica is precipitated with magnesium hydroxide at a rate of about
++9'10
1 gm SiO~ per 7 grams Mg If more silica removal is required then
magnesium will have to be added. The ability to remove silica with magnesium
at a cooling water temperature of 80 F or more is illustrated in Ref. 11 (p. 84).
At Navajo/Farmington, New Mexico; Gillette, Wyoming; and Kaiparowits/Escalante,
Utah, dolomite was added to the clarifier to precipitate silica.
When the pH is raised to about 11 phosphate removal is quite complete,
requiring a consumption of 5 moles of lime for 3 moles of P Calculation
of the lime requirements must include the lime needed to raise the pH.
93
-------
Lime-soda softening involves a small investment in chemical feeders and
mixers and a large investment in clarifiers to settle out the precipitates.
Installed clarifier costs have been estimated using the cheaper of steel or
concrete tanks. The concrete cost was taken to be §175/cubic yard and
includes excavation, backfill, concrete, concrete forms, rebar and finish.
Steel tank costs depend upon the diameter of the tank. Clarifiers were
sized separately for each site study and depending on the particular con-
2
ditions linear velocities in the range of 0.4 to 1.3 gpm/ft were chosen.
A rule of installing two parallel clarifiers each having 65 percent of. the
required capacity was adopted.
Microbial growth was prevented by the addition of microbiocides to the
circulating water. The costs of Mocides having EPA, USDA and similar
approvals as non-dangerous materials lie in the broad range of 15
-------
in the cooling tower blowdown is at most 20% of the weight of the dry solids
in the flue gas desulfurization slurry, well within the reserve capacity of
the desulfurization thickener clarifiers. As a result the costs associated
with thickening the cooling tower blowdown are relatively small. The
thickened slurry is disposed of on-site by ponding or as land fill.
Table 4-8 shows the flow diagram, circulating cooling water concentration
and cost estimates for the Navajo/Farmington, New Mexico site. The makeup
water cdmposition for all the sites is found in Appendix B. Table 4-9
summarizes the annual evaluated costs of water treatment and blowdown
disposkl at each of the six sites. The costs range between $0,17 to $0.31 per
1000 gallons of water evaporated.
Water Supply
Water must be bought and brought to the plant. For the purposes of
this study the cost of the water rights were assumed to be zero.
In studying pipelines, data have been obtained from two sources.
Stone and Webster Engineering Corporation has recently estimated costs for
12
a 12 inch diameter pipeline in the Wyodak, Wyoming area . The line was
designed for a water flow of 2,200 gpm and runs for about 3.8 miles. The
total cost was estimated to be approximately one million dollars and includes
the cost of pipe metal, labor for installing, excavating and backfill. Extra
costs for going under or over roads, railroads, rivers, or bridges are not
included. The cost represents about $33,000/(inch diam-mile).
13
Data from a Bureau of Reclamation study of buried aqueducts showed
that the average costs vary from $21,000/(inch diam-mile) for pipelines to
84 inches in diameter to $32,000/(inch diam-mile) for diameters greater than
84 inches. For the present study an installed cost of $25,000/(inch diam-mile)
95
-------
Table 4-8. Flow diagram, circulating water concentration and estimated costs
for Navajo/Farmington, New Mexico cooling Cower ,
Evaporation
20,899 gpra**
1.80 Ib/min
21,290 gpra
T.D.S.=330 ppm
S.S.=100 ppm
Lime 20.1 Ib/min
Soda Ash 10.5 Ib/min
Dolomite 22.0 Ib/min
Dust
15.9 Ib/min
401 gpm
T.D.S.=6500 ppm
S.S.=3.3%
* Without additional thickening Of
clarifier underflow.
** All flow rates are expressed in gallons
per stream minute.
Concentration of Circulating Water
(in mg/1 as CaCO.)
Ca
„ +2
Mg
Na+
115
39
6572
636
co3
HC03~
•v1
-
124
6254
Si02 13 mg/1 (as Si02)
Costs
Capital Costs ($1000)
2 Lime and Dust Clarifiers
(approx. 169 ft. dia. each)
Evaluated Costs ($1000/yr)
15% of Capital
Chemicals
Lime
Soda Ash
Dolomite
Flocculant
Dispersant
Biocide
Sulphuric Acid (pH control)
Total Chemicals
Labor
Slowdown Disposal
TOTAL EVALUATED COSTS
1140
173
228
177
185
113
252
84
1
1040
300
6
1340
-------
Table 4-9. Summary of annual evaluated costs of water treatment and blowdown disposal.
SITE
COLSTRIP, MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON, NEW MEXICO
KAIPAROWITS/ESCALANTE, UTAH
Water Treatment
Capital
($1000/yr)
169
165
169
112
173
174
Chemicals ,
and Labor
(SlOOO/yr)
1060
1390
1280
468
1340
2215
Blowdown
Disposal
($1000/yr)
6
6
6
2
6
10
Total
($1000/yr)
1235
1561
1455
582
1519
2399
Total Costs
($71000 gallons
of water evaporated)
0.17
0.22
0.20
0.23
0.20
0.31
-------
and annual charges of 10% per year were assumed. Furthermore we have
assumed pumping energy costs of 10 mills/kw-hr (lc/kw-hr) , as compared to
the cooling tower auxiliary costs of 5.2 mills/kw-hr. It can be shown
that there is an optimum flow rate which minimizes the total evaluated
cost of supplying water to the plant. For the particular conditions cited
the optimum flow rate is 9.65 ft/sec.
At some of the sites the pipeline supplied not only the water for the
steam electric power plant but also supplied the water for some of the other
coal conversion plants. Table 4-10 lists the other plants supplied by the
same pipeline that supplied the steam electric power plant. The table also
lists the length of pipeline required at each site, L, together with the
difference in elevation, H, between the power plant site and the water source.
Note that two power plants are sited at Kaiparowits/Escalante, Utah, and a
different pipeline supplies water for each plant. The diameter of pipe, D,
required at each of the sites assuming peak flow rates is also shown. The
peak flow rates are based on the water consumption data presented in the
summary tables of Section 10 and the appropriate load factor. Table 4-11
shows the total annual evaluated costs of installing the pipeline and the
annual pumping energy costs. The total annual evaluated cost of supplying
water to the power plant is given in column 4 and is obtained by multiplying
the total evaluated cost of the pipeline by the fraction of water that is used
by the power plant. For example, at Colstrip, Montana, the total water consumed
by the power plant is 16,500 gallons per calendar minute while the water
consumed by the Synthane plant is 4,800 gallons per calendar minute. The cost
of supplying water to the power plant is
16,5004.800
98
-------
Table 4-10. Pipeline data.
1
SITE
COLSTRIP, MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON , NEW MEXICC
KAIPAROWITS/ESCALANTE , UTAH
Plants Supplied by Pipeline
3000 MWe Power Plant
250 x 106 scf/streaffl day Synthane
3000 MWe Power Plant
250 x 106 scf/stream day Lurgi
3000 MWe Power Plant
250 x 10^ scf/stream day Synthane
250 x 10^ scf/stream day Lurgi
1000 MWe Power Plant
3000 MWe Power Plant
250 x 106 scf/stream day Synthane
L. 3000 MWe Power Plant
I, 3000 MWe Power Plant
L
(miles)
35
20
170
10
15
45
25
H
(ft)
710
0
2000
2330
200
2780
2100
D
(ft)
2.9
2.6
3.0
1.6
3.1
2.8
2.8
-------
Table 4-11. Evaluated costs of supplying water.
SITE
COLSTRIP, MONTANA
BEOLAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON , NEW MEXICO
KAIPAROWITS/ESCALANTE , UTAH
Evaluated Coses ($10 /yr)
Pipeline Installation
3.06
1.58
15.43
0.47
1.38
3.75
2.08
Pumping
0.96
0.32
4.28
0.38
0.38
1.80
1.21
Total
4.02
1.90
19.71
0.85
1.76
5.55
.3.29
Total
Power Plant
3.11
1.66
13.48
0.85
1.36
5.55
3.29
Power Plant Costs
(S/1000 gallons
water evaporated)
0.42 (0.48)
0.24 (0.26)
1.82 (2.23)
0.33 (0.33)
0.18 (0.20)
0.71 (0.71)
0.42 (0.42)
o
o
-------
The last column is the cost of supplying water to the power plant divided by
the total amount of water evaporated during the year. The numbers in paren-
thesis are the results of Calculations done by assuming that the pipeline
supplies water only for 'the power plant and not for any of the Lurgi or
Synthane plants.
Table 4-12 summarizes the costs of water treatment, blowdown disposal
and water supply at each of the sites and compares them to the breakeven water
costs. In none of the cases does the cost of water exceed the breakeven water
costs indicating that wet cooling is preferred at each of the sites. Only at
Gillette, Wyoming, where the power plant is 170 miles from the water source and
the cost of supplying water is quite high, does the cost of water even begin
to approach the breakeven water costs, and even then only for the high back
pressure turbines.
We should note that our estimates of water costs are low. For example,
the cost of water treatment and blowdown disposal can be about a factor of
two or three higher, while the costs of water supply does not include the
costs of water rights. A typical range of water rights costs is $10/acre ft
to $100/acre ft or 3
-------
Table 4-12. Summary of evaluated water costs.
SITE
COLSTRIP, MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON, NEW MEXICO
KAIPAROWITS/ESCALANTE, UTAH
Evaluated Water Costs
($/1000 gallons of water evaporated)
Water Treatment
and Slowdown Disposal
0.17
0.22
0.20
0.23
0.20
0.31
Water
Supply
0.42
0.24
1.82
0.33
0.18
0.71
0.42
Total
0.59
0.46
2.02
0.56
0.38
1.02
0.73
Breakeven Water Costs
($/1000 gallons of water evaporated)
High Back
Pressure Turbine
2.89
2.96
2.94
3.04
2.85
2.93
Conventional
Turbine
4.35
4.71
5.08
5.05
4.19
4.63
o
to
-------
The purpose of this cooling system is to reduce the evaporative cooling tower
makeup water requirements as well as the capital costs of the dry cooling
tower. The system shown in Fig. 4-4 was analysed to show the effect of
makeup water requirements on the evaluated costs of the cooling system. The
cooling system uses a conventional mechanical draft wet tower and a separate
conventional mechanical draft dry tower; the cooling media for each tower flows
in separate circuits. The dry tower operates during the whole year with its
greatest operating efficiency in winter while the evaporative tower operates
in warmer weather during periods of peaking. The evaporative tower operates
only when the turbine back pressure would exceed 5 in Hg absolute with the
dry tower alone.
R. W. Beck and Associates performed the wet/dry tower calculations by
combining the separate evaporative and dry cooling tower computer programs
t
described previously into a single program. The dry cooling system is
designed for a whole range of ITD (dry tower initial temperature difference)
and TTD (condenser terminal temperature difference) (see Fig. 4-1) as is done
for the case of the dry tower alone, with the constraint that the turbine back
pressure not exceed 5 in Hg absolute. For a given ambient air temperature both
the heat rejection to the condenser and the heat load to the dry tower are
known; the difference between the two is the required heat load to the
evaporative cooling tower. The operating conditions.for the wet cooling
tower are also known. A series of wet towers are calculated varying the
range and approach temperature to meet the required .operating conditions and
heat load. The wet tower is sized to meet the maximum performance requirements
associated with the given range of operating conditions. For off-design con-
ditions it is assumed that the minimum required number of wet tower segments
103
-------
HOT WATER
HOT WATER
CONDENSER
DRY
COOLING
TOWER
COLD WATER
EVAPORATIVE
COOLING
TOWER
COLD WATER
HEAT
EXCHANGER
Fig. 4-4. Wet/dry cooling system.
-------
will be operated and that fan horsepower will be reduced in order to conserve
water and minimize auxiliary energy requirements. At each ITD, the total
evaluated costs for the combination wet and dry towers are optimized.
Table 4-13 lists the optimum wet/dry cooling tower combinations at
Navajo/Farmington, New Mexico for different water costs, as well as the dry
cooling system with an auxiliary tower and the all evaporative cooling system
presented in the preceding sections. Fig. 4-5 shows the total annual evaluated
costs of the wet/dry cooling system as a function of the water evaporated in
the evaporative cooling tower expressed as a percentage of evaporative loss
of the all evaporative cooling system. There is virtually no difference in
the evaluated cost with the cost of water to $1.00/1000 gallons of evaporated
water. The highest values of ITD considered correspond to points of inflection
in the curves shown in Fig. 4-5.
It is .shown on Fig. 4-5 that when water costs above about $2.20/1000 gallons
partial dry cooling is more economical than all wet cooling. The term
"breakeven cost" of water is the cost associated with that curve for which
the annual charge is equal at both ends, i.e., $4.19/1000 gallons (Table 4-6) as
shown on Fig. 4-5. The actual water cost at which partial dry cooling becomes
economical may be $0.20-$0.30/1000 gallons of water evaporated more than the
estimated value of $2.20/1000 gallons because of the increase in the total
annual evaluated cost with increasing water costs.
As was shown previously, the cost difference between a dry cooling system
and an ail wet cooling system is relatively insensitive to site, at least
for the sites considered in this study. If a water cost of $2.20-$2.50/1000
gallons of water evaporated were used at all the sites, then Table 4-12
indicates that except for Gillette, Wyoming, all evaporative cooling systems
105
-------
Table 4-13. Total annual evaluated costs for optimum wet/dry cooling systems at Navajo/Farmington, New Mexico.
Dry Tower
ITD TTD
(Op) (Op)
30 6
35 S
40 5
45 5
SO S
55 5
60 5
6S S
70 S
75 5
80 5
02 5
84 5
(1) 31 6
(2) -
Wet Tower
Range Approach
<°F> (°F>
16.2 20
29.9 19
29.9 19
30.0 19
29.9 19
29.8 19
29.7 19
29.6 19
2B.4 20
28.3 20
28.3 20
28.3 20
28. 3 20
* *
26.4 28
Wet Tower
Evaporative Lt/ss
<106 gallons/yr)
5.51
16.67
44.37
95.53
194.25
319.45
488.82
685.13
917.47
1158.69
1411.58
1514.22
1629.55
4.8S
7686.0
Total Annual Evaluated Costs (S106/vr)
($0/1000 gallons (SO. 50/1000 gallons (SI. 00/1000 gallons
water evaporated) water evaporated) water evaporated)
124.800 124.803 124. 800
121. 3O3 121.311 121.320
118.060 118.082 118.104
116.011 116.059 116.107
114.341 114.438 114.535
112.758 112.918 113.077
111.465 111.709 111.9S3
110.640 110.982 111.325
109.773 110.232 110.690
109.130 109.709 110.289
108.380 109.086 109.792
108.239 108.996 109.753
108.117 108.932
123.613 123.615 123.618
91.371 95.214 99.0B7
(1) Dry cooling system with auxiliary tower.
(2) Evaporative cooling system.
* Conditions not specified for auxiliary tower.
-------
126
120
o
.—(
en
o
w
I
H
O
110
o
H 100
90
$4.19/1000 gallons of
water evaporated
2.20-2.50
COMPUTER CALCULATIONS
SKETCHED IK
0.50
0.25 0.50 0.75
WATER EVAPORATED AS A PERCENTAGE OF WATER EVAPORATED FOR ALL EVAPORATIVE COOLING SYSTEM
1.0
Fig. 4-5. Total annual evaluated costs of wet/dry cooling system as a percentage of evaporative loss
of all evaporative cooling system at Navajo/Farmington, New Mexico.
-------
would be preferred if sufficient water is available. At Gillette, Wyoming
the choice of art all evaporative cooling system would be marginal. However,
a savings in total water consumed in the cooling tower of about 75% of that
required by all evaporative cooling would be made at the expense of only
50% of the difference in evaluated costs between dry and all evaporative
cooling.
4.5 Water Consumed and Solid Residuals Generated
The total water evaporated at each of the sites is shown in Table 4-6
and repeated again in Table 4-14. The tower calculations were made by
R. W. Beck and Associates using the computer program mentioned in Section 4.2,
which is based upon the method of Merkel (see p. 587 of Ref. 14). These
quantities are also repeated in the summary tables of Section 10. The total
cooling tower heat load as well as the heat dissipation rate is also shown
in Table 4-14. This is to be compared to the dissipation rates for the process
cooling water shown in Table 2-12.
As discussed in Section 4.3 the treatment of cooling water yields waste
sludges'which are about 40% solids - 60% water. These sludges are derived
primarily from lime—soda softening, dust concentration, and thickening. The
wastes produced at each site are shown in Table 4-15 and repeated again in
the summary tables in Section 10. The water evaporated is obtained from
Table 4-14.
Slowdown is not the only liquid waste effluent from a cooling tower.
Small droplets of cooling water having the same contaminants and concentrations
as the blowdown are entrained into the air flow and are carried out of the tower
onto the surrounding terrain. Local vegetation and groundwater supplies may
108
-------
Table 4-14. Water evaporated and heat dissipation rates for cooling towers.
SITE
COLSTRIP, MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON, NEW MEXICO
KAIPAROWITS/ESCALANTE, UTAH
Total Water
Evaporated
(106 gallons/yr)
7377
7023
7398
2567
7686
7764
Water Evaporated
(gallons/calendar minute)
14,040
13,360
14,075
4,867
14,617
14,770
Cooling Tower
Heat Load
(1012 Btu/yr)
86.87
86.87
86.35
28.96
86.87
86.87
Heat Dissipation
Rate
(Btu/lb water
evaporated)
1414
1484
1401
1354
1357
1343
-------
Table 4-15. Residuals generated at each site•
SITE
COLSTRIP , MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON ,
NEW MEXICO
KAIPAROWITS/ESCALANTE ,
UTAH
Wet-Solid
Slurry
(tons per
1000 gallons
of water
evaporated)
0.0075
0.0088
0.0090
0.0064
0.0081
0.0123
Dry Solids
in Slurry
(tons per
1000 gallons
of water
evaporated)
0.0030
0.0035
0.0036
0.0026
0.0032
0.0049
Water
in Slurry
(gallons per
1000 gallons
of water
evaporated)
1.079
1.271
1.295
0.911
1.175
1.774
Wet-Solid
Slurry
( tons/c . day)
151.6
169.3
182.4
45.0
170.6
261.6
Dry Solid
(tons/c. day)
60.6
67.3
73.0
18.3
67.4
104 . 2
Water in
Slurry
(gal/c- min)
15.1
17.0
18.2
4.4
17.2
26.2
-------
be affected by the deposition of the salt-containing droplets. The amount
of drift is measured as a percentage of the total circulating cooling water
through the tower. Until recently drift losses of less than 0.2 percent
were guaranteed by the tower manufacturers. Now, with the development and
addition of new drift eliminators, drift rates as low as 0.002 to 0.005 percent
have been measured on several new towers,with the lower drift rate attributed
to natural-drift towers and the higher rate to mechanical-draft towers. For
this study a drift rate of 0.005 percent was used. The circulating water flow
rates as well as the drift rates are summarized in Table 4-16; the drift rates
are repeated in the summary tables of Section 10.
The demineralizer waste is taken fco be 50% moisture and to have a solids
content of 1.6 times the total dissolved solids in the makeup water. This
corresponds to complete deionization of the makeup water with a regenerant
usage of 160% of the stoichiometric values. The boiler makeup water was taken
to be 300 gallons/stream minute (210 gallons per calendar minute) per 3000 MWe.
Table 4-17 shows the soluble wet-solids sludge generated from the demineralizer
waste.
Ill
-------
Table 4-16,Drift rates .
SITE
COLSTRIP , MONTANA
BEULAH, NORTH DAKOTA
GI LLETTE , WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON ,
NEW MEXICO
KAIPAROWITS/ESCALANTE ,
UTAH
Circulating
Flow Rate
(gallons per
stream minute)
1,071,870
1,032,795
1,147,152
344,265
1,071,870
1,032,795
Drift Rates
(gallons per
stream minute)
53.59
51.64
57.36
17,21
53.59
51.64
(gallons per
calendar minute)
37.51
36.15
40.15
12.05
37.51
36.15
(106 gallons/yr)
19.7
19.0
21.1
6.3
19.7
19.0
-------
Table 4---17. Demineralizer residuals.
SITE
COLSTRIP, MONTANA
BEULAH, NORTH DAKOTA
GILLETTE, WYOMING
RIFLE, COLORADO
NAVAJO/FARMINGTON,
NEW MEXICO
KAIPAROWITS/ESGALANTE ,
UTAH
Wet-Solids
Sludge
(tons/c.day per
1000 g/c. min)
7.95
8.22
7.56
4.61
5.76
11.06
Boiler
Makeup
(gal/c. min)
210
210
210
70
210
210
Wet-Solids
Sludge
(tons/c . day )
1.6
1.7
1.6
0.3
1.2
2.3
Dry Solids
(tons/c. day)
0.8
0.9
0.8
0.2
0.6
1.2
Water
in Solid
(gal/c. min)
0.1
0.1
0.1
0.03
0.1
0.2
-------
References
1. Rossie, J. P., Mitchell, R. D, and Young, R. 0., "Ecomomics of the Use
of Surface Condensers with Dry-Type Cooling Systems for Fossil-Fueled
and Nuclear Generating Plants," R. W. Beck and Associates, Denver,
Colorado, U. S. Atomic Energy Commission Report No. TID-26714 (UC-12),
December 1973.
2. Rossie, J. P., Cecil, E. A. and Young, R. 0., "Cost Comparison of
Dry-Type and Conventional Cooling Systems for Representative Nuclear
Generating Plants," R. W. Beck and Associates, Denver, Colorado.
U.S. Atomic Energy Commission Report No. TID-26007 (UC-80), March 1972.
3. Mitchell, R. D., "A Method for Optimizing and Evaluating Indirect
Dry-Type Cooling Systems for Large Steam-Electric Generating Plants,"
R. W. Beck and Associates, Denver, Colorado, U.S. Energy Research and
Development Administration Report No. ERDA-74 (UC-12), June 1975.
4. "Heat Sink Design and Cost Study for Fossil and Nuclear Power Plants,"
United Engineers and Constructors, Inc., U.S. Atomic Energy Commission
Report No. WASH-13600 (UC-13 & 80), December-1974.
5. Corey, G. R., "A Comparison of the Cost of Nuclear versus Conventional
Electric Gneeration," Commonwealth Edison Company, Boston, MA,
December 1975.
6. Gold, H., Goldstein, D. J. and Yung, D., "The Effect of Water Treatment
on the Comparative Costs of Evaporative and Dry Cooled Power Plants,"
Water Purification Associates, Cambridge, Mass., ERDA Report No.
COO-2580-1, June 1976.
7. Grits, G. J. and Glover, J., "Cooling Slowdown in Cooling Towers,"
Water and WastesEngineering, 45-52, April 1975.
8. Applebaum, B., Demineralization by Ion Exchange, pages 23-67,
Academic Press, 1968.
9. Mindler, A.B., Permutit Research and Development Center, Princeton, N.J.,
personal communication.
10. Kleusner, J., Heist, J. and Van Note, R. H., "A Demonstration of
Wastewater Treatment for Reuse in Cooling Towers at Fifteen Cycles of
Concentration," presented at AIChE Water Reuse Conference, May, 1975
11. Betg Handbook of Industrial Water Conditioning, Betz Laboratories, Inc.,
• Trevose, PA 19047.
12. Coraley, W. D., Private Communication, Stone and Webster Engineering
Corporation, Boston, Massachusetts (September 3, 1975).
13. "Appraisal Report on Montana-Wyoming Aqueducts," U.S. Department of the
Interior, Bureau of Reclamation, Washington, D.C. (April 1972).
14. Kern, D. Q., Process Heat Transfer, McGraw-Hill Book Co., Inc., New York (1950),
114
-------
5. SLURRY PIPELINE
The coal slurry pipeline is a method of hydraulically transporting
coal from the mine to its point of use. Long distance coal slurry transport
may involve distances of several hundred miles or as much as a thousand miles,
as in the case of the proposed ETSI piepline from Gillette, Wyoming to
White Bluff, Arkansas . In addition to the mining of the coal, the process
of slurry preparation involves size reduction by crushing the coal, adding
the slurry water to the crushed coal and then grinding it finely. Chemical
treatment may be added after grinding to improve the slurry characteristcs,
following which the slurry is sent to agitated storage tanks prior to pump-
2
ing . These processing steps are those which have been described for trans-
porting low ash, low sulfur coals as in the proposed Gillette pipeline or
3 4
in the operational Black Mesa piepline in Arizona ' . We suggest that where
the transport of a high ash coal such as from Farmington be involved, then
coal washing prior to grinding should be added to the processing steps.
By far the largest quantity of water is required for the slurrification
itself, in which about an equal weight of water and coal are mixed. The
process can be somewhat arbitrarily broken down into a mine and plant stage.
The mine stage is considered to include mining, breaking and first stage
crushing. The plant stage is taken to include processing and slurry prepara-
tion. A typical but by no means unique process description is as follows.
Mine
(i) Primary breakers reduce run-of-mine coal to a top size of, say,
4 to 8 inches.
(ii) First stage crushers reduce, coal to a top size of, say, 2 inches
for storage prior to preparation.
115
-------
Plant
(i) Storage bins of say, 2 hour capacity, receive belt fed coal from
storage piles.
(ii) Scalping (vibrating) screens receive belt fed coal from bins
and separate out oversize coal (say, > k inch) for transport to
impact crushers. Undersized coal (say, < V inch) joins product
from impact crushers.
(iii) Impact crushers reduce the product to 99% passing \ inch (80%
passing 5000 van).
(iv) Water at about 50 wt.% is added to the crushed coal in gravity
feed chutes.
(v) Wet rod mill receives mixture of water and coarse solids and
grinds coal down to a top size of all passing 28 mesh (80%
passing 300 ym). In no case should the top passing size be
greater than 8 mesh.
(vi) Agitated slurry storage tanks receive the slurry after pumping
from the sumps into which it is discharged from the mills. Any
coarse, fast-settling particles are either recycled or sent to
a dump pond, and the final product is sent into the pipeline.
The water requirements for the mine stage will be evaluated in Section 7,
along with the mining requirements for the other processes, since they all
differ only in quantity but not in kind. Similarly, the water requirements
for basin and reservoir evaporations, plant dust control and service and
potable water uses will be evaluated in Section 8 along with these same
requirements for the other processes considered in this assessment.
116
-------
The principal power requirements for the plant include
in-plant coal transfer
crushing
grinding
in-plant pumping
slurry mixing and agitation
pipeline pumping (first stage)
plant service electricity
Of these, the grinding power and power for the first stage of pumping far
exceed all the other requirements combined. For the example illustrated
2
the grinding power would be about 14.5 MWe based on 6.8 hp-hr/ton and
25 x 10 tons/yr. A first stage pump station would consume about 14.8 MWe •
The total electric power requirement is seen to be relatively small and will
therefore be assumed to be purchased, with no direct water consumption
charged to power generation. For the power consumption uses described
cooling water requirements will be negligible.
From the above discussion we conclude that the principal process water
requirement is for slurrification. Assuming a 50/50 mixture by weight of
coal and water,then to transport 25 x 10 tons/year of coal at a 100% load
factor the slurry water requirement is
25 x 10 tons x 2,000 Ibs x I gal x 1 yr x 1 day
yr min 8.33 Ibs 365 days 1440 mins
= 11,420 gal/calendar min.
117
-------
References
1. Odasz, F. B., "Coal Slurry Pipelines," Energy, Water and the West
(E.R. Gillette, ed.), P- 67, Am. Assoc. for Advance, of Science,
Washington, D.C., 1976.
2. Cowper, N. T., et al., "Processing Steps: Keys to Successful Slurry
Pipeline Systems," Chemical Engineering 79(3), 58-67, Feb. 7, 1972.
3. Ctvertnicek, T.E., Rusek, S.J., and Sandy, C.W., "Evaluation of Low-
Sulfur Western Goal Characteristics, Utilization, and Combustion
Experience," pp. 150-154, EPA-650/2-75-046 (NTIS PB-243 911), U.S.
Env. Prot. Agency, Office of Res. & Dev., Washington, D.C., May 1975.
4. Neihaus, E. D., "Water and Energy Requirements in the Mining and
Processing of Coal," in Proc. Conf. on Water Requirements for Lower
Colorado Basin Energy Needs, pp. 151-164, Office of Arid Lands Studies,
Univ. of Arizona, Tucson, Arizona, May 8, 1975.
5. Energy Transportation Systems, Inc., Unpublished Document, Casper,
Wyoming, Feb. 21, 1974. Summarized in memorandum of E. Rappaport,
Radian Corp., Austin, Texas.
118
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6. FLUE GAS DESULFURIZATIOH
6-1 Particulate and Sulfur Removal
Process steam is generated in coal-fired boilers for the electric power and
Lurgi plants examined in this study. In the Synthane process char is burnt to
generate process steam. The burning of coal, even low sulfur Western coal,
and of char generates both particulates and oxides of sulfur in the exiting
flue gases . Particulate removal to meet air quality standards need not involve
significant water consumption if electrostatic precipitators are used, although
some water will be consumed in disposing of the fly ash. We will therefore
reserve our discussion of the water needed for particulate removal to Section
8, where solids disposal is considered, since this need for water is for the
most part related to ash disposal.
Sulfur dioxide (S0«) represents 98% of the sulfur oxide pollutants and
its removal from the combustion gases before they are released to the stack
generally involves an important use of water. The most likely procedures for
use in the near future are the wet scrubbing systems that utilize limestone
(CaCO.,) , hydrated or slaked lime (Ca(OH)2) or both. In the wet limestone process
the flue gas contacts a wet limestone slurry in the scrubber and the SCL is
removed following the reaction
with
CaC03 + S02 - >- CaS03 4- C02, (-6.1)
CaS03 + hO 2 - »~ CaS04- (6.2)
The scrubber effluent generates a spent slurry following the reactions
CaS03 + hK20 - *- CaS03 • JjHjO | , (6.3)
CaS04 + 2H20 - 5- CaS04 • 2H20 j. (6.4)
119
-------
In the wet lime scrubbing system the gas containing the SO is reacted with
a wet lime slurry following the reaction
Ca(OH) + SO, * CaSO + HO. (6.5)
" *" -5 £,
Reactions (6.2) to (6.4) follow.
In any of these procedures water leaves the system as a vapor in the
flue gas and in the slurry of spent solids. In what follows we examine
these.two streams separately and present methods for estimating the water in
these streams independent of the specific scrubbing procedure or its details.
6.2 Water in Flue Gas
To estimate the quantity of water which leaves the scrubbed flue gas
we make the assumption that this gas is saturated with water vapor at the
temperature and pressure at which it leaves the scrubber in the final absorber
and before any reheat. The dependence on temperature and pressure of the
water content is illustrated in Table 6-1 which shows the moles of water vapor
per mole of dry gas at saturation.
Table 6-1. Moles of water vapor per mole of dry gas at saturation.
"""V^total Pressure
Temperature*"-*^
<°F)
120
130
140
150
160
(°0
49
54
60
66
71
(psia) 14.696
(in. H2
-------
From Table 6-1 it is clear that lack of knowledge of the pressure of
saturation in the range of interest will give an error of not more than -7%.
However if the temperature of saturation is 10 P higher than was assumed the
water content of the flue gas will be about 40% higher than calculated. This
indicates a severe limitation on the ability to estimate the quantity of water
in the flue gas without detailed and precise information on the gas temperature.
Moreover, this also shows that large variations in the flue gas water consump-
tion can be expected in the plants unless temperature control is very tight,
which it is generally not. After comparing with published results we have
selected for saturation conditions 120°F (49 C) and 10 inches of water gauge,
so that the fuel gas is calculated to contain 0.13 moles water per mole of
dry gas.
We next need to know the dry flue gas volume. Assuming negligible
carbon monoxide and nitrogen oxides the dry flue gas volume is given by the
formula derived in Table 6-2. As given there, the total moles of dry flue
gas per unit weight of coal or char, as fired, are
(4.76X1 + aXfj + |j) + (3.76 + 4.76a)(| - |j) , (6.6)
where a, c, s, h and x are the weights of each element as defined in
Table 6-2 per unit weight of coal of char. The water carried away by the gas which
was not in the gas before scrubbing, that is, the makeup water requirement
for gas saturation at 120°F and 10 inches of water then becomes in weight
per unit weight of coal or char as fired (Ib/lb coal or char)
(4.76) (0.13) (1 +a) (^- + ^-) (18) + (0.13) (3.76 + 4.76a) (|- - ^-) (18) - w - - .
(6.7)
121
-------
Table 6-2. Determination of total moles of dry flue gas
per unit weight of coal or char as fired .
Basis: Unit weight of coal or char containing:
Element
Carbon
Hydrogen
Oxygen
Sulfur-
Moisture
Wt.
c
h
x
s
w
Formula
C
H2
°2
S
H 0
Moles
c/12
h/2
x/32
s/32
w/18
The fraction excess air is a.
Flue gas component
Carbon dioxide, CO,
Moles in dry gas
12
Moles Cu required
c
12
Water, HO
Sulfur dioxide, SO,,
32
h x_
4 ~ 32
s
32
Oxygen, 0,
Total
,c h x s
a(12 + 4 ' 32 + 32*
12 4 32 32
Nitrogen, N,
Total
4.76(1 + al(~ + j) + (3.76 + 4.76a)
122
-------
The excess air, a, varies from about 0.05 to 0.2 and will very seldom
be known exactly. We take a = 0.15 recognizing that changes in this quantity
over the range indicated will generally not introduce an error into the results
of greater than 10%. However, for very high moisture content coals such as
lignites, where w is large, the relative error could be somewhat larger because
the absolute makeup requirement is small. Using the value of excess air noted,
Eq. (6.7) reduces to
makeup water 10 0,c s N , 1A _ ,h x , h /t 0\
_____= 12.8(_ + _) + 10>5(____ ) _w_ _ . (6>8)
In Table 6-3 we have used the above formula to calculate the weight of makeup
water required per unit weight of coal or char as fired, for the coals and char
considered in the present study. As already noted, the largest single factor
affecting the water requirement is seen to be the moisture content of the coal.
The quantities of flue gas desulfurization water leaving with the boiler flue
gases presented in Section 10 are based on the values shown in Table 6-3 multi-
plied by the- known coal or char feed rates to the boilers.
Table 6-3. Element weights per unit weight of coal or char
and makeup water requirements per unit weight of
coal or char for coals and char of present study.
Mine
Location c_ h_ _x s_ w_ Ib water/lb coal
Beulah, N.D. .404 .027 .119 .007 .360 .104
Gillette, Wyo. .494 .034 .128 .003 .280 .291
Colstrip, Mont. .506 .032 .098 .011 .247 .345
Kaiparowits, Utah .616 .043 .109 .004 .148 .583
Navajo, N.M. .473 .035 .096 .009 .124 .439
Rifle, Colo. .710 .054 .076 .006 .064 .806
All sites, Synthane char .636 .010 .014 .003 0 .700
123
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6.3 Water in Waste Solids^
As Indicated by Eqs. (6.3) and (6.4) there are two major solids wastes,
CaSO., • W-O and CaSO, • 2H20. In addition, unreacted limestone, CaCO-j, and
slaked lime, Ca(OH)2> are also wasted. The amount of water leaving in the
waste solids depends on the quantity of sulfur and the slurry concentration.
In Table 6-4 is shown for the two major products the weight of solid per
unit weight of sulfur and the weight of water per unit weight of sulfur.
Table 6-4. Weight of CaSO^H^O and CaS03-35H20,
and water of hydration per unit weight
of sulfur.
Crystal Form Ib solid/lb sulfur Ib water/lb sulfur
CaSO, • 2H00 5.38 1.13
4 i
CaS03 • ^0 4.03 0.28
Assuming a given solids concentration in the waste slurry, the weight
of slurry water per unit weight of sulfur can be calculated. In Table 6-5
the weight of the slurry water per unit weight of sulfur is shown for a
40 wt.% solids concentration, which represents a well dewatered waste obtained
by gravity thickening. Vacuum filtration could increase the percent solids to
60% and vacuum filtration plus centrifugation could raise this figure to
70% . However, these mechanical dewatering techniques would only be prac-
ticed if transport of the sludge to distant landfill were envisaged, which
is not the case for the Western sites considered in this study.
124
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Table 6-5. Weight of slurry water per unit weight of
sulfur for a 40 wt.% solids concentration.
Crystal Form lb slurry water/lb sulfur
CaS04 • 2H20 8.07
CaS03 - hK2Q 6.05
In Tables 6-6a and 6-6b we have given the compositions in weight fractions.
of lime and limestone scrubber sludges as reported in Ref. 1. In Ref. 1 the
calcium sulfite was assumed to be in the crystalline form CaSO.. • 2H?0. It is
now generally agreed that the form in the sludges is CaSO- • JjELO. We have
therefore corrected the weight fractions.given in Ref. 1 to the values
shown in Table 6-6.which correspond to the accepted crystalline form of
calcium sulfite. Also shown in these tables are the corresponding weight
fractions of sulfur and water of hydration, calculated using the values given
in Table 6-4. All values in Tables 6-6 are stated as pounds of solids, with
one pound of sludge solids as the basis, rather than as weight fractions.
Table 6-6a. Weight of components of lime sludge (dry) and
corresponding weights of sulfur and water of hydration,
Component lb solid lb sulfur lb water
CaC03
CaS03 • ^O
CaSO, • 2H 0
Ca(OH)2
Total 1.000 .194 .074
.058
.690
.126
.126
0
.171
.023
0
0
.048
.026
0
125
-------
.367
.533
.100
0
0
.132
.019
0
0
.037
.021
0
Table 6-6b. Weight of components of limestone sludge (dry) and
corresponding weights of sulfur and water of hydration.
Component Ib solid Ib sulfur Ib water
CaC03
CaS03 > »sH20
CaS04 • 2H20
Ca(OH)2
Total 1.000 .151 .058
From the data of Tables 6-6 we have calculated the weight of solids
and of the water of hydration per unit weight of sulfur for the lime and
limestone processes. These figures are given in Table 6-7.
Table 6-7. Weight of solids and water of hydration per
unit weight of sulfur in lime and' limestone sludges,
Process Ib solid/lb sulfur Ib water/Ib sulfur
Lime 5.2 0.38
Limestone 6.6 0.38
Table 6-7 shows that the unit weights of solids are reasonably close
and that we may with little error take the average of the two values as
representative of any wet lime, limestone or lime-limestone scrubbing
process, that is, 5.9 Ib solid/lb sulfur. It is also clear from the. table
that the water of hydration can represent only a very small fraction of the
total makeup water (slurry water plus water of hydration) so that we will
126
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neglect this contribution and assume that the makeup water equals the slurry
water. In this case we may write
Ib makeup water _ ,. Q ,1 -
m
Ib sulfur ~ 5'9(—T—)» (6-9)
where m is the weight fraction of solids in the waste (i.e., weight of
solids divided by the weight of water plus solids). Note that a change to
30% solids from 40% solids makes a 50% increase in the water in the waste,
since (1 - m)/m changes from 1.5 to 2.3. A change to 50% solids makes
(1 - m)/m equal to 1 and decreases the water in the waste by 33%.
In Table 6-8 we have tabulated for the coals and char of Table 6-3 the
slurry makeup water for m = 0.4,along with the total makeup water for the
waste disposal including the flue gas. water. It should be noted here, that
though the quantity of slurry makeup water is strongly affected by any change
in solids fraction this change has much less of an effect on the total quantity
of water makeup. It can be seen from Table 6-8 that with a solids fraction
even as high as 0.4, the water in the waste is only important with the higher
sulfur coals. Again the exception to this is the wet lignite (Beulah, N.D.)
where the flue gas water makeup is so small that even the small amount of
slurry makeup represents a sizeable fraction of the total.
6.4 Comparison of Present Approach
There is little reported data with which to directly compare the estimates
provided by the present approximate formulation for the coals examined. One
2
engineering design estimate has been given for the Kaiparowits coal . The
wet lime flue gas desulfurization design was made for a nominal 3,000 MWe plant,
and the estimates made in Ref. 2 are compared below in Table 6-9 with our
approximate estimates derived from Eqs.(6.8) and (6.9) with m = 0.4.
127
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Table 6-8. Weight of sulfur and makeup water requirements
per unit weight of coal for coals of present
study and with 40 wt.% solids in slurry.
Mine Ib water/lb coal
Location £ in solids total
Colstrip, Mont. .0109 .097 .442
Navajo, N.M. .0091 .081 .520
Beulah, N.D. .0070 .062 .166
Rifle, Colo. .0056 .050 .856
Kaiparowits, Utah .0042 .037 .620
Gillette, Wyo. .0032 .028 .319
All sites, Synthane char .0026 .023 .723
Table 6-9. Comparison of flue gas desulfurization makeup
water requirements for Kaiparowits coal from
design estimates of Ref. 2 and present approximate
formulation.
Ib water/lb coal
Estimate in solids in flue gas total
2
Impact statement .031 .514 .545
Present.calculation .037 .583 .620
The agreement as shown in Table 6-9 between the estimates is seen to
be quite good, although our result is somewhat higher than that from the
impact statement. A similar conclusion is borne out by a comparison with
experimental results for other coals. It should be noted that had the
present solids calculation been based on our wet lime result of 5.2 Ibs of
solids per Ib of sulfur, rather than the lime-limestone average of 5.9,
the water in the solids would have been .033 instead of .037. In summary,
128
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it is felt that our approach is sufficiently accurate for the present
purposes and gives a conservative picture of the water requirements.
References
1. Cooper, H.B., "The Ultimate Disposal of Ash and Other Solids from
Electric Power Generation," in Water Management by the Electric Power
Industry (E.F. Gloyna, H.H. Woodson and H.R. Drew, editors),
pp. 183-195, Center for Research in Water Resources, The University
of Texas at Austin, 1975.
2. Bureau of Land Management, "Final Environmental Impact Statement
Proposed Kaiparowits Project," Vol. I, pp. 1-89, 105, FES 76-12,
March 3, 1976.
129
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7. MINING
7.1 Categories
In the sections that follow we present the general methodology for
calculating the amount of water consumed in the mining of coal or shale and
in any subsequent land reclamation which may be required. The water quantities
for this category of usage generally will not be too strongly affected by
the conversion process, except as it determines the actual quantity of material
to be mined. However, the mine location and whether the mining is surface
or underground will be strong determinants of the quantity of water consumed.
We list below the principal categories of consumed water applicable to
coal or shale mining:
Road, Mine and Embankment Dust Control
Handling and Crushing Dust Control
Service and Fire Water
Sanitary and Potable Water
Revegetation
Coal Washing
In the following sections we will discuss separately each of these cate-
gories. When water is limited, its use or loss prevention becomes a matter
of economic tradeoff. The water quantities we will present will be characterized
as reasonable bounds for best available technology, with no effort to carry
out detailed cost estimating of the type done for cooling towers.
7.2 Coal and Shale Mining Rates
Before estimating the water quantities associated with the mining
operations it is necessary to know the rate at which the coal is mined to feed
the unit size plants examined in this study. Here it is important to recognize
130
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that the tonnage mined is not necessarily that which enters the process.
For example, coal which is mined underground must be washed and approximately
25% is disposed of as refuse. In the Lurgi process the gasifier cannot accept
coal fine's, although the boilers can, the result being that about 10% of the
mined coal is sold off as fines.
Basically the quantity of coal required is determined by the heat input
rate for the size plant considered and the heating value of the fuel. For
a Lurgi 250 x 10 scf per stream day plant the process needs from Section 2.4
9 9
are 17.7 x 10 Btu/hr, and the mine requirements are 19.67 x 10 Btu/hr as
detailed in Table 7.1. From Section 2.5,the Synthane requirement is
Q
17.1 x 10 Btu/hr, to which we add about 0.35% of additional heat input to
9
cover undefined losses,for a total input of 17.7 x 10 Btu/hr.
Table 7-1. Process heat requirements for
250 x 10° scf/stream day Lurgi plant,
109 Btu/hr
Gasifier 14.6
Boilers 2.6
Subtotal 17.2
Undefined losses (0.3%) 0.5
Total to process 17.7
Fines (10% mined coal) 1.97
Total from mine 19.67
Finally a 3,000 MWe plant at full load and 35% efficiency requires a heat
Q
input of 29.3 x 10 Btu/hr. All of those requirements are summarized in
Table 7-2, where if no distinction is made between process and mine, the
131
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requirements are the same. Knowing the higher heating value of the coal
(see Appendix A) it is then a simple matter using the values in Table 7-2
to determine the daily tonnage requirements.
Table 7-2. Mine and process requirements for
coal conversion plants.
10 Btu per 10 1 Btu per
Process Nominal Output stream day calendar day Factor
Lurgi
250 x 106 scf/day
.e 4.72
•cess 4.25
,ane 250 x 106 scf/day 4.25
ioil 100,000 bbl/day 8.38
4.25
3.82
3.82
7.54
0.9
0.9
0.9
0.9
Steam-Electric 3,000 MWe
Under. Mine 9.36 6.55 0.7
Surf. Mine &
Process 7.02 4.91 0.7
In the case of shale requirements, we must refer specifically to the
process and the kerogen content of the shale. From Section 3.2 we note that
for 35 gallon/ton shale that 66,000 tons per stream day (59,400 tons per
calendar day) are required for the TOSCO II process. The tonnage require-
ments will vary essentially in direct proportion to the shale kerogen content.
The coal slurry pipeline requirements are defined by the transport requirement
of 25 x 10 tons/year or 68,493 tons/calendar day. Of course, were ash
removal practiced prior to transport then the quantity mined would differ
from that transported. This, however, is not the case for present study in
which it is Gillette coal to be piped (see Section 5).
132
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Tables 7-3a and 7-3b summarize the coal and shale daily tonnage require-
ments derived, where appropriate, from Table 7-2 and the coal heating value.
Table 7-3a. Coal tonnage requirements for unit size
plants in tons per calendar day.
Lurgi
Mine
Process
Synthane
Synthoil
3,000 MWe
Slurry Pipeline
Beulah
Colstrip
Gillette
Navaj o
31,135
28,021
28,021
55,251
36,018
-
24,666
22,200
22,200
43,772
28,535
-
25,139
22,625
22,625
44,611
29,082
68,493
25,560
23,004
23,004
45,358
29,569
-
Table 7-3b. Coal and shale tonnage requirements
for unit size plants in tons per
calendar day.
3,000 MWe
Mine
Process
1,000 MWe
Oil Shale (50,000 bbl/day)
Kaiparowits
30,335
22,751
Rifle-
6,296
59,400
133
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7.3 Road, Mine and Embankment Dust Control
In estimating the water requirements for this category of dust control we
must distinguish between surface and underground mines. Let us first consider
surface mines which cover the majority of situations of interest in the present
study. The dust control we speak of here is primarily the fugitive dust generated
on haul roads and unpaved areas in the neighborhood of the mine such as the
mine benches and overburden placement areas. To a large extent, the length of
unpaved haul roads and mine bench areas will depend on the mine productivity,
as measured by the amount of coal recoverable per unit area of stripped land.
In Table 7-4 we have shown the coal yields per acre for the 5 sites considered
in the present study where the coal will be strip-mined. The value at Gillette
was arrived at by averaging the 92,000 ton/acre figure derivable from Ref. 1 and
the 88,000 ton/acre figure derivable from the information in Ref. 2. The value
for Beulah was derived from the data of Ref. 3, while that for Farmington was
obtained from Ref. 4. In a book prepared by the National Academy of Sciences ,
coal yield figures are given for all of the areas considered. However, these
values appear on average to be about a factor of 1.8 lower than those values ob-
tained from the various environmental impact statements. We have therefore used
the figures from Ref. 5 multiplied by a factor of 1.8 to derive the values for
Colstrip and Rifle, for which detailed statements were not available.
Table 7-4. Coal yields per acre.
Mine Location tons/acre
Beulah 25,000
Colstrip 40,000
Gillette 90,000
Navajo 37,000
Rifle 23,000
134
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In our assumed mine model we have estimated that the mining of 100 acres per
year would require 2 miles of 45 ft wide unpaved haul roads to serve as spurs
to conveyor belts that would feed the coal to the plant. Such a belt line
operation may be found described in Ref. 1. In addition, we assume the bench
area acreage that would have to be wet down to be approximately equal to 4 times
the daily acreage that is mined. The sum of the two unpaved areas determines
the area on which dust control must be practiced.
The simplest means of holding down fugitive dust is to wet down the mine
area and haul roads. We assume as a conservative estimate that the roads and
mine area can be kept in a wetted condition through an annual deposition of
water equal to the net annual evaporation rate. Any rainfall is taken to be
an additional safety factor, and is not subtracted from the amount of water
to be laid down, because how much of it is actually absorbed and how much runs
off is variable. The annual pond evaporation rates for the areas examined are
shown in Table 7-5 (see Appendix B).
Table 7-5. Annual pond evaporation rates.
Location inches/year
Beulah 45
Colstrip 49
Gillette 54
Navajo 61
Rifle 45
We can now calculate the lay down rate from the relation
lay down rate = disturbed area x evaporation rate. (7.1)
135
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f\
For our assumed mine model, 522,937 ft must be wetted down per 100 acres/year
disturbed. In Table 7-6 is shown the acreage it would be necessary to strip
mine yearly for the processes and sites considered. Using these average
figures and the evaporation rates given in Table 7-5 we have calculated the
required lay down water from Eq. (7.1). It is this quantity which is listed
in the tables of Section 10 as the "Road, Mine, Embankment Dust Control" water.
The exceptions to this are the Kaiparowits coal mines and the Rifle oil shale
mines, both of which are underground mines. The dust control requirements for
these mines are very different from a surface mine. Moreover,, we would note
that the actual acreage disturbed per year by an underground mine is relatively
small.
*
Table 7-6. Area strip mined annually in acres per year.
Beulah Colstrip Gillette Nava j o
Lurgi
Synthane
Synthoil
3,000 We
454
409
806
526
225
203
400
261
102
92
181
118
252
227
448
292
* 102 acres/yr for 1,000 MWe plant at Rifle and 278 acres/yr
for slurry pipeline at Gillette.
In Ref. 6 the shale mine dust suppression water consumed is given as 350 gal
per stream minute. The mining technique projected is underground room and
pillar mining. This is one of the methods envisaged in Ref. 7 for underground
coal mining at Kaiparowits. On the basis of 66,000 tons per stream day of
shale mined, this amounts to 1 lb^ of water for every 31 Ibs of as-mined shale.
On the basis of other estimates for mine dust suppression water, this value
136
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seems quite reasonable and we have used it to calculate the mine dust control
water for oil shale mining.
Somewhat less reasonable is the net consumed water for mine dust sup-
pression indicated in Ref. 7 for Kaiparowits. On the basis of a net consumption
of 621 gallons per calendar minute and a mining of 32,973 tons of coal per calen-
dar day a usage is indicated of 1 Ib of water for each 9 Ibs of as-mined coal.
If we assume this to include water for crusher dust suppression, which
generally takes place at the mine mouth, then we may compare this with 1 Ib
of water for each 19 Ibs of as-mined shale . The value of water usage indicated
for Kaiparowits appears to be quite high and we have chosen to use a combined
value for mining and crushing at Kaiparowits which is about 50%. larger than that for
the shale case or 1 Ib of water for every 13 Ibs of as-mined coal. The values
of mine water consumption listed in the Rifle shale tables and Kaiparowits
coal table are based on the usages indicated and the tonnages given in Table 7-3b.
7.4 Handling and Crushing Dust Control
We consider the water needs associated with the preparation of the coal
or shale as part of the estimate of the water requirements for a mining opera-
tion integrated with a synthetic fuel plant or a steam-electric power plant.
In all coal preparation plants dust is generated in the stages of loading and
unloading, breaking, conveying, crushing, general screening and storage. The
water required to hold down this dust will be considered here. Coal washing
will be treated separately in Section 7.9, because of the specialized nature
of the process and because of the high consumptions involved.
The ways of preventing dust from becoming airborne are through the appli-
cation of water sprays, the application of non-toxic chemicals, the use of dry
or wet dust collectors and the use of either partial or total enclosure. We
137
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shall assume that the principal dust generating sources will be enclosed and
that where feasible air will be circulated and dry bag dust collection employed.
Whenever coal pulverization is necessary we consider, as is normally the
case, that this will be done under conditions of total enclosure with no
fugitive dust or hold-down water requirements. We have seen in Section 5 that
water is added in the milling of coal for slurrification, however, this is
a requirement related to the slurrification itself. In inactive storage the
use of water for holding down dust can be minimized by the use of non-toxic
chemicals.
Despite the design precautions indicated, in large scale plants with
many transfer points, tranfer belts, surge bins, storage silos and active
storage sites it is necessary to employ water sprays to wet down the coal or
shale. This is also generally necessary with breaking and primary crushing
4
operations. An examination of the Wesco Lurgi plant design and the TOSCO
c.
oil shale plant design indicate that a consumptive use of 1 Ib of water for
every 50 Ibs of coal handled and crushed is a reasonably conservative estimate.
This estimate is essentially in agreement with the value derived from Ref. 6.
Using the tonnage figures of Tables 7-3 leads to the rates of water consumption
for handling and crushing given in the tables of Section 10.
7.5 Mine Personnel
A number of water requirements in the mine are a direct function of the
number of people employed in the mine. One such obvious requirement is water
for sanitary needs and potable usage. Of course, the number of personnel is
related to the tonnage mined but the number will also depend on the mine type
and location.
138
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In Ref. 8 estimates are given of the number of personnel needed in
model mines to strip 5 x 10 tons of coal per year. The locations considered,
that are relevant for this study, are the Southwest, Montana, Wyoming and
North Dakota. We have scaled up on a tonnage output basis, the number of
personnel recommended for these model mines to the outputs of Lurgi plant
•i f\ i
mines proposed for Wyoming , North Dakota and New Mexico , as well as to a
2
straight mining facility proposed for Gillette . The numbers of mining
personnel recommended by the mining companies in the environmental impact
statements were compared with those from the scaleup. In all cases the
recommended numbers of mine personnel were remarkably close to 50% more than
those derived from the model mines data. In this study we have used the
data of Ref. 8 to compute the number of mine personnel. However, we have
increased the requirements by 1.5 on the basis of the impact statements and
on the assumption that a certain number of additional personnel will be
required for the preparation facilities associated with the conversion plants.
In the absence of equivalent data on mine personnel for underground
shale mining in Rifle and underground coal mining in Kaiparowits, we have
found it necessary to rely on the figures given in Refs. 6 and 7. For the
Kaiparowits case, the number of personnel was scaled downward from that given
in Ref. 7 in proportion to the difference in tonnage outputs from the respec-
tive mines.
Tables 7-7 summarize the mine personnel requirements for the units of
the present study.
139
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Table 7-7a. Number of mine personnel for specific
mines integrated with coal conversion
plants and a slurry pipeline.
Process
Lurgi
Synthane
Synthoil
Nominal Output Beulah Colstrip Gillette Navaj o
250 x 106 scf/day 305
250 x 10 scf/day 275
100,000 bbl/day 540
Steam-Electric 3,000 MWe
Slurry Pipeline 25 x 10 tons/yr
350
255
230
455
295
260
235
465
300
715
345
310
610
400
Table 7-7b. Number of mine personnel for an underground
and surface mine integrated with a steam-electric
plant and for an underground oil shale mine integrated
with a shale oil plant .
Process
Steam-Electric
Steam-Electric
Oil Shale
Nominal Output
3,000 MWe
1,000 MWe
50,000 bbl/day
Kaiparowits
2,360
Rifle
85
400
140
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7.6 Sanitary and Potable Water
Sanitary and potable water usage is directly proportional to the number
of personnel. Our estimated usage figures per man-shift are given in Table 7-8.
The higher usage figure is for those areas with the higher rates of evaporation
minus precipitation.
Table 7-8. Sanitary and potable water usage per
man-shift and percent of usage consumed.
Usage Consumed
Location (gal/man-shlft) (% of usage)
Beulah, Colstrip, Gillette 30 25
Kaiparowits, Navajo, Rifle 35 30
In our calculations we have assumed 5 shifts per week per man. The
usage of water in gallons per calendar minute is therefore given by the relation
gallons usage 5 1 day gal f /7 o\
•a—= : r*— = T x , . .„ ^ .— x g , . ,' x no. of men (./ .2.)
calendar min 7 1440 mm man-shift
No account has been taken of shortened shifts or vacation time so as to provide
a conservative estimate.
The net consumption will be quite different from the usage, since we
assume that the sanitary and potable water effluent will go through water
treatment in order that it may be reused within the plant. In Table 7-8
we have given our estimates of appropriate water consumptions as a percentage
of water usage. Again a somewhat higher figure has been indicated for those
areas with higher rates of evaporation minus precipitation.
141
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Using the mine personnel data given in Tables 7-7, and the usage
figures in Table 7-8, the water usages can be calculated from Eq. (7.2).
The results were always rounded to the nearest gallon per calendar minute.
The net consumptions were then obtained by multiplying these rounded usage
figures by the appropriate fraction given in Table 7-8. The calculated net
consumptions were also rounded to the nearest gallon per calendar minute,
and it is those figures which are given in the tables of Section 10 under
the headings of "Sanitary & Potable Water."
We have calculated the quantities of sludge that would be generated in
the recovery of the sanitary and potable waters, even though the quantities
themselves are not large. A standard figure for suspended solids in sewage
9
is 0.25 lb/(person)(day) for a usage of 100 gal/(person)(day) . For our
assumed usage of 30 gal/man-shift this would correspond to a suspended solids
of .075 Ib/man-shift. Under the assumption that the sludge from the water
treatment plant is dewatered to 80% water,this would mean a generation of
0.375 lb wet sludge per man-shift. Taking, as before, 5 shifts per week
per man we find that 0-_27_ lb wet sludge is generated per man per calendar day.
This same figure was used for the 35 gal/man-shift consumption, since the
higher usage is associated with greater net evaporation rather than increased
suspended solids per man. The wet solid figures for mine sanitary and potable
water in the tables of Section 10 were calculated using the preceding wet
sludge figure and the mine personnel of Tables 7-7.
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7.7 Service and Fire Water
The service water usage in the mine such as for equipment washing,
maintenance, pump seals, etc., along with the fire water usage through
evaporation loss is a difficult quantity to estimate. However, an analysis
of a number of mine designs indicates that this usage, which is essentially
non-recoverable, can be related to the usage (not consumption) of sanitary
and potable water.
The estimated ratio for service to sanitary usage for a proposed
10 x 10 ton/yr surface mine near Gillette is about 1.6 . This same figure
for the proposed Kaiparowits underground mine is about 1.3, based on our
estimated sanitary water usage. We have used our estimate of sanitary water
usage, since Ref. 10 is in agreement with our estimate for their case, so
that by so doing this enables us to provide the same relative comparison
for the two sites. The two values are sufficiently close that we have taken
their average and assumed that the service water usage for the mine is 1.5 times
the sanitary water usage. Moreover, all of the water is taken to be consumed
since recovery in the mine work areas would prove quite difficult. The values
of fire and service water shown in the Tables of Section 10 were calculated using
the sanitary water usages developed in the preceding section (but not tabulated).
7.8 Revegetation
As part of any reclamation of mined land in arid and semi-arid regions,
there exists a potential requirement for supplemental irrigation water asso-
ciated with the establishment of soil stabilizing plant cover on mine spoils.
In Ref. 5 (p. 168) 'it is concluded that coal mined areas with greater than
10 inches of mean precipitation annually can be reclaimed without supplemental
irrigation. Where there is less than 10 inches of annual rainfall, partially
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reshaped coal mine spoils can be successfully revegetated with supplemental
irrigation of about 10 inches during the first growing season, with no
further requirement during subsequent growing seasons . The establishment
of plant growth on spent oil shale piles requires considerably more supple-
mental irrigation and this will be considered separately.
From the precipitation data given in Appendix B,it can be seen that of
the sites considered the only ones with less than 10 inches of annual rainfall
are Navajo and Kaiparowits. Strip mining is proposed only for the Navajo site
so that it is only there that significant irrigation water is needed. However,
some spoil revegetation will be necessary in Kaiparowits on the coarse
waste piles.
The areas to be revegetated annually at the Navajo site correspond to
the mining area rates listed in Table 7-6. In the proposed Kaiparowits
design of Ref. 7 (p. 1-196), which we here follow, it is estimated that the
coarse waste dump would occupy an area of 550 acres over the 35 year life
of the plant. Multiplying the average annual acreage, rate by the ratio of
the total refuse rate in our design (7,584 tpd, Table 7-36) to that in the
design of Ref. 7 (8,219 tpd) gives an annual coarse waste spoil area of
14.5 acres/yr.
With the area to be revegetated annually known, the supplemental irriga-
tion water expressed in gallons per calendar minute can be calculated from
the relation
n
Irr. waterC-fHr-)- - Area £&&) * 43,560 1L. x 10 in x 1" x 62.4
cal.min yr acre I/ in
1 yr 1 day
8.33 Ibs 365 days 1440 min
, acres v ._, „,
0.517 x Area(— — ) (7.3)
144
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The "Revegetation" water requirements given in the Tables of Section 10 for
Navajo and Kaiparowits were obtained from the above relation and the
acreage rates noted.
We have based the irrigation requirements for spent shale pile revegation
on an annual spoil area of 11.5 acres/yr for a 50,000 bbl/day plant, which is
the estimated acreage requiring reclamation during the first ten years of
operation . After this period the annual acreage rate would rise. Estimates
for the necessary irrigation water indicate that about 1 ft of water is
required initially to leach out the salinity, and then an additional 1 ft/yr
fi 10
for from 2 to 5 years ' On a continuous annual basis we shall therefore
consider a one time requirement of 6 ft of water. This is undoubtedly a
conservative estimate. Replacing 10 inches by 6 ft in Eq. (7.3) we have
Shale Irr. Water( fal 4 ) = 3.72 x Area(^~) (7'4)
- cal. min' yf.
For a 50,000 bbl/day oil shale plant, this gives an average consumption of
43 gallons per calendar minute.
7.9 Coal Washing
Often times it may be desirable or necessary to upgrade run-of-mine
coal by reducing the ash and sulfur levels through washing of the coal. For
all of the surface mined coal at the sites studied this is not considered
necessary. However, when coal is mined underground, as at Kaiparowits, coal
washing is normally employed and we shall take this to be the case. The
details of washeries can vary significantly, however, our estimate of water
consumption will be a generalized one based on the quantities of solids handled
and disposed, rather than on any specific design.
145
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From Ref. 7 we find that for the Kaiparowits coal, about 53% of the
refuse is coarse and the remainder is fine waste which ends up in the tailing
ponds. It is the coarse reject for which the revegetation water requirement
was calculated in the preceding section. The coarse reject amounts to 4,020 tons
per calendar day. Little water is added to the coarse reject, generally
not more than 10 wt. %, and this primarily to aid in dust control and the
subsequent compaction. On the basis of 10 wt. % of water this amounts to
75 gallons/calendar minute.
The fine refuse leaving the washery amounts to 3,564 tons/calendar day.
Consistent with our assumption throughout this study, we take the waste to be
a well dewatered one of 40 wt. % solids. This concentration is somewhat
higher than the more usual 30 to 35% but can be obtained without excessive
13
difficulty . Based on our assumed solids concentration, water enters the
t-
tailings pond at a rate of 1,005 gal/calendar min. We follow the design of
Ref. 7 and take 58% of this water to be lost, so tha't the net consumption is
583 gal/calendar min. This is consistent with a reasonably designed tailings
and clear waste overflow pond (Ref. 13, Chapter 17). Of the water lost,about
80% or 466 gal/calendar min is retained in the pond and the remaining 20% is
evaporated. We have sized a tailings and clear water overflow pond and
calculated the evaporation rate. V!e find the rate to be approximately con-
sistent with that given in Ref. 7, where a 3 year filling is assumed. The
evaporation rate could be reduced by assuming a 2 year filling, but we have
chosen to use the figures given as conservative estimates.
146
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References
1. Wyoming Coal Gas Co. and Rochelle Coal Co., "Applicant's Environmental
Assessment for a Proposed Gasification Project in Campbell and Converse
Counties, Wyoming," Prepared by SERNCO, October, 1974.
2. Geological Survey, "Proposed Plan of Mining and Reclamation - Cordero
Mine, Sun Oil Co., Coal Lease W-8385, Campbell County, Wyoming," Final
Environmental Statement No. 76-22, U.S. Dept. of the Interior,
April 30, 1976.
3. North Dakota Gasification Project for ANG Coal Gasification Co.,
"Environmental Impact Report in Connection with Joint Application of
Michigan Wisconsin Pipe Line Co. and ANG Coal Gasification Co. for a
Certificate of Public Convenience and Necessity, Woodward-Clyde
Consultants," Federal Power Commission Docket No. CP75-278, Vol. Ill,
March 1975.
4. Batelle Columbus Laboratories, "Detailed Environmental Analysis Concerning
a Proposed Gasification Plant for Transwestern Coal Gasification Co.,
Pacific Coal Gasification Co., Western Gasification and The Expansion
of a Strip Mine Operation Near Burnham, New Mexico Owned and Operated
by Utah International Inc.," Federal Power Commission, Feb. 1, 1973.
5. National Academy of Sciences, Rehabilitation Potential of Western Coal
Lands, pp. 32, 33, Ballinger Publishing, Cambridge, Mass., 1974.
6. Colony Development Operation, "An Environmental Impact Analysis for a
Shale Oil Complex at Parachute Creek, Colorado, Part 1 - Plant Complex
and Service Corridor," Atlantic Richfield Co., Denver, Colorado, 1974.
7. Bureau of Land Management, "Final Environmental Impact Statement Proposed
Kaiparowits Project," Chapter I, FES 76-12, U.S. Dept. of the Interior,
March 3, 1976.
8. Bureau of Mines, "Cost Analyses of Model Mines for Strip Mining of Coal
in the United States," Information Circular 8535, U.S. Dept. of the
Interior, 1972.
9. Metcalf & Eddy, Inc., Wastewater Engineering, p. 581, McGraw-Hill,
New York, 1972.
10. Atlantic Richfield Co., "Preliminary Environmental Impact Assessment for
the Proposed Black Thunder Coal Mine, Campbell County, Wyoming," and
"Revised Mining and Reclamation Plan for the Proposed Black Thunder Coal
Mine," 1974. Also "Black Thunder Mine, 10 Million Ton Per Year Water
Supply," (Personal Comnunication, Hugh W. Evans), Denver, Colorado,
March 6, 1975.
147
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11. Aldon, F. E., "Techniques for Establishing Native Plants on Coal Mine
Spoils in New Mexico," in Proc. Third Symposiumon Surface Mining and
Reclamation, Vol. I, pp. 21.28, National Coal Association, Washington, B.C.,
1975.
12. U.S. Dept. of the Interior, "Final Environmental Statement for the
Prototype Oil Shale Leasing Program," Vol. I, U.S. Gov't. Printing
Office, Washington, B.C., 1973.
13. Leonard, J. W.,and Mitchell, D. R., Coal Preparation, Chapter 12,
Am. Inst. of Mining, Metallurgical and Petroleum Engineers, New York,
1968.
148
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8, EVAPORATION, SOLIDS DISPOSAL AND OTHER USES
8.1 Categories
In this section we examine the water requirements associated with those
solids disposal problems not already considered. We will also determine the
quantity of residuals to be disposed. Of particular concern are the disposal
of bottom ash, fly ash and spent shale. Among the other uses of plant water
not included in the process estimate but to be treated here are the water
needs for dust control, service requirements, and sanitary and potable con-
sumption. Finally, since all the water which is used in the mine and plant
will generally have come from an onsite reservoir, and since it may have passed
through settling basins, it is also necessary to calculate the evaporation
losses from these holding areas. These losses are chargeable to the water
requirements for the mine-plant complex.
8-2 Bottom Ash and Spent Shale Disposal
Ash will enter a furnace or gasifier in the coal or char. Some of it
will leave as hot ash or slag from the bottom of the unit, and the remainder
will leave as fly ash in the flue gases. The specific gasifier or furnace
defines the temperature at which the hot bottom ash or slag is removed.
This temperature is important to water consumption since the ash or slag is
generally cooled down by quenching with water before disposal, mainly for
reasons of safety. We will take the ash to be quenched down to a temperature
somewhat below the boiling point of water, say around 200 F. In Table 8-1
we have listed our estimates of the temperature at which the bottom ash will
be removed from the various processes or units. Also listed are the ash
temperature drops on quenching (AT).
149
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Table 8-1. Temperature of bottom ash on removal
and ash temperature drop on quenching.
Ash Removal Ash Temperature
Process or Unit Temperature,°F Drop on Quenching,°F
Lurgi Gasifier 1,000 800
Dry-Ash Furnace 1,200 1,000
Synthane Furnace 1,200 1,000
Synthoil Hydrogen Unit 1,500 1,300
The rate at which water is evaporated in cooling down the ash can be
determined from the relation
heat removed/time = specific heat x temperature drop x ash quenched/time.
(8.1)
Dividing the heat removal rate by the heat of vaporization (1,000 Btu/lb)
determines the evaporation rate. Based on the analysis of bituminous ash
we have estimated the ash specific heat to be 0.2 Btu/(lb)( F). In terms of
water evaporated we then rewrite Eq, (8.1) as
( ? : ) = 3.33 X 10 A -DULLUm rt.SU Vj
cal. mm day
Water Evaporated (—fal . ) = 3.33 x 10 5 x Bottom Ash Or255-) x AT(°F).
pal. min U3V
(8.2)
In addition to the water evaporated, a certain amount of excess water
must be added to the ash both for handling and ease of disposal. The weight
of water remaining in the quenched ash is taken to be 30% of the ash weight
(23 wt. %). An expression for the amount of this remaining water is. given by
/ gal _x Ibs water /tons.
Water in Quenched Ash V~[—~-~) = 0.3 ib ash ~ x Bottom '
x 2000 i^s x . 1 gal x _l_..day _
ton 8.33 Ibs 1440 min
= 5 x 10~2 x Bottom Ash(-) - (8.3) .
day
150
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The two streams defined by Eqs. (8.2) and (8.3) are seen to be of the
same order and the sum of them specifies the net water requirement for the
bottom ash disposal. The water requirement is directly proportional to the
ash removal rate which must be known.
To determine the bottom ash removal rate it is first necessary to
calculate the total ash that will be removed. This quantity is simply the
product of the percent ash, as defined for each coal in Appendix A, multiplied
by the rate of coal input to the processes, as given in Tables 7-3. In the
present study we have assumed the use of pulverized coal fired dry-ash furnaces,
in which normally about 20% of the ash leaves as bottom ash and the remaining
2
80% leaves as fly ash . The exception to this rule in the present study is
when Navajo coal is used. In that case, Ref. 3 indicates that about 25% of the
ash leaves as bottom ash with 75% leaving as fly ash. This may be a consequence
of the high ash content of this particular coal. In the Synthane process the
same breakdown is assumed, with the ash entering the furnaces in the char,
which is recovered from the gasifier, rather than directly with the coal.
In the Lurgi process, according to Table 7-1 the fraction of the process coal
which is fed directly to the boilers is 2.6/7.9 or 15.1%. Of this fraction,
the same split is again taken between the bottom ash and fly ash, as defined
previously for the dry-ash furnaces. The remainder of the process coal comes
out as bottom ash from the gasifier. In the Synthoil process all of the ash
is assumed to come out as bottom ash in the hydrogen plant. In Table 8-2 we
have summarized the various ash quantities calculated on the basis of the rules
just given.
151
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Ul
N>
Table 8-2. Ash quantities in tons per day,
Steam-Electric (.3,000 MWe)''
* Except Rifle which is 1,000 MWe
Synthane (250 x 10 scf/day)
Location
Beulah
Co Is trip
Gillette
Kaiparowits
Nava j o
Rifle*
Bottom
535
555
326
319
1893
76
Fly
2138
2222
1303
1274
5677
302
Total
2673
2777
1629
1593
7570
378
Bottom
416
432
253
-
1472
—
Fly
1663
1728
1014
-
4417
—
Total
2079
2160
1267
-
5889
Lurgi (250 x 10 scf/day)
Synthoil (ICO,OOP bbl/day)
Location
Beulah
Colstrip
Gillette
Nava j o
Gasif ier
Bottom
1765
1833
1075
4999
Boiler
Bottom
63
65
38
223
Fly
251
262
154
667
Total
2079
2160
1267
5889
Bottom
4100
4259
2498
11100
Fl£ Total
4100
4259
2498
11100
-------
From Eqs. (8.2) and (8.3) and the data in Tables 8-1 and 8-2, we have
evaluated the bottom ash water consumption quantities and solids disposal
quantities given in the Tables of Section 10.
In Section 3.3 we have already discussed the spent shale disposal
problem. Both the quantity of shale and shale moisturizing water were
given in Fig. 3-1 and Table 3-1 for a 50,000 bbl/stream day output. It is
these quantities, corrected for a 90% load factor, which are listed in the
oil shale tables of Section 10.
8.3 Fly Ash and Shale Dust Disposal
In the present study we assume that dry electrostatic preclpitators
are used to remove the coal fly ash from the flue gas. In these precipitators
the collected ash is discharged into storage hoppers by rapping. The removal
process itself is dry but when the ash is withdrawn from the storage hoppers
or silos this is usually done by screw conveyors, with the ash wet down by
water sprays to prevent dusting and to make the handling easier. The water
sprayed on the ash would normally be about 25% by weight of the ash, that is,
20 wt. % of the mixture. We have used this figure to determine the quantity
of water leaving with the fly ash, the amount of fly ash itself having already
been specified in Table 8-2.
A fine particulate removal process is also necessary in the TOSCO shale
oil retorting, where shale dust must be removed from flue gases prior to their
discharge into the atmosphere. In the TOSCO process wet venturi scrubbers
are specified. Since this is part of the process design we must accept the
penalties in water consumption inherent in these scrubbers. We would only
note that the water which does leave with the scrubbed shale dust is mixed
153
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with the moisturized spent shale. The scrubber sludge water therefore serves
as part of the needed moisturizing water and, moreover, as we already discussed
in Section 3.3, it then becomes permanently cemented into the spent shale
and does not present a leaching problem. The quantities of water and sludge
have already been given for a 50,000 bbl/day plant in the footnote of Table 3-1.
The quantities listed in the shale tables of Section 10 have been appropriately
corrected for the 90% load factor.
8.4 Plant Dust Control
Within the boundaries of any of the plants considered in the present
study water will be needed for dust control at a certain number of points.
These points are similar to those described for the mines in Section 7.4,
namely transfer areas, active storage, surge bins, etc.
We may expect that somewhat less water would be required in the plants
than in the mines, since many of the operations tend to be enclosed. On this
basis we have assumed a consumptive use of one-third that applicable to the
mine areas, specifically 1 Ib of water for every 150 Ibs of coal handled and
transferred. We have compared this estimate with that deduced from the data
of Ref. 4 and find it to be about one-half of the estimated value used there.
The value noted has been used for all plants except the slurry pipeline and
the oil shale plants, where we have used half the water, that is, 1 Ib of
water for every 300 Ibs of coal or shale handled. This is because in-the shale
plants part of the dust control water has already been accounted for in the
usage calculated in Section 7.4. In the case of the slurry pipeline, the coal
is normally wet during much of the processing so that we can expect less dust
control water to be needed.
154
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8-5 Plant Personnel
In the plant, as in the mine (see Section 7.5), a certain number of
water requirements depend directly on the number of people employed. Determining
these numbers is difficult and we have relied upon the estimates of the com-
panies proposing to set up plants. In the cases where there are no estimates
we have extrapolated from similar plants. There is no reason to expect
significant variations in the numbers of people employed at a given type of
plant as a function of geographical location. Clearly, the largest single
influencing factor is the plant output.
In Table 8-3 we have listed the number of plant personnel, valid for all
of the plant-site combinations considered in this study. The figure for
the 3,000 MWe steam-electric plant has essentially been taken from Ref. 4.
The number of people for the 1,000 MWe plant has been reduced in proportion but
with 10% more people to account for the inefficiency of a smaller scale.
The figure for the Lurgi plants represents a rounded average derived from
the estimates given in Refs. 3, 5 and 6. We have used the same number of
personnel for the Synthane plants as for the Lurgi plants, since the output
and operations are similar. The number of personnel for the 50,000 bbl/day
shale plant was taken directly from the estimates provided by the designers
For the 100,000 bbl/day plant this number was simply doubled, since the plant
is essentially constituted of two 50,000 bbl/day units with little economy
of scale. The output from the Synthoil plant is the same as the larger oil
shale plant and many of the operations are similar to those carried out in. the
shale oil upgrading. -However, the material tonnage which must be taken in and
handled is less than half that of the shale plant, the solids to be disposed of
155
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are only a small fraction of the spent shale, and finally some economy of
scale is expected because of the unitary design. An analysis of these
factors indicates that about 30% fewer personnel than in the larger shale plant
could be expected.
Table 8-3. Plant personnel at all sites.
Plant Output Personnel
Lurgi & Synthane 250 x 106 scf/day 650
Synthoil 100,000 bbl/day 1,150
Steam-Electric 3,000 MWe 500
1,000 MWe 185
Oil Shale 50,000 bbl/day 820
100,000 bbl/day 1,640
8-6 Plant Sanitary and Potable Water
The calculation of the plant sanitary and potable water usage, cpnsump-
tion and solids residuals is exactly the same as for the mine. It is described
completely in Section 7.6 and will not be repeated here. The only information
needed is the number of plant personnel and that is given in the preceding
section in Table 8-3.
8.7 Plant Service and Fire Water
As in the mine (see Section, 7.7), a certain amount of water is required
in the plant for various service functions. We shall again assume that the
service water usage is related to the sanitary water usage. The rationale,
as for the mine, is that the larger the service functions the larger the number
156
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of personnel and sanitary usage. In general, more water will be needed for
the plant than for the mine service facilities, so that we have assumed the
service water usage for the plant is 2 times the sanitary water usage.
Unlike the mine case, some of the plant service water will be recoverable
after use. We assume that 1/3 of the service water used is consumed and 2/3- is
recovered after treatment. The used service water that is treated will be
9
considered to be a low to medium strength waste , containing about 300 ppm
of suspended solids which are removed in the treatment prior to the reuse of
the water. As in Section 7,6, the sludge from the water treatment plant is
assumed to be dewatered to 80% water. The wet sludge weight which must be
disposed of daily is then given by the relation
, /tons^ _ 300 Ibs solids 5 Ibs sludge R ~o Ibs water 1 ton
wet biuage^day ) 106 ibs water X. Ib solid xo"" gai x 2000 Ibs
x [Water Usage-Water Consumed] (—fal . ) x 1440 f^
cal. mm day
= 6 x 10~3 x Water Usage( fal . ) . (8.4)
6 cal. mm'
From the sanitary water 'usage the service water usage and consumption
are readily determined; while the generated sludge, which is quite small, is
calculable from Eq. (8.4) above. The site specific results are given in the
tables of Section 10.
8.8 Settling Basin Evaporation
If the surface feed water is sufficiently dirty or tutbid, it will
generally be appropriate to employ settling basins at the supply source to
settle out the suspended matter, prior to pumping the water to an on-site
reservoir for plant and mine use. In any settling basin,water will be lost
through evaporation and this loss is a penalty in water consumption chargeable
against the mine-plant complex.
157
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The quantity of water lost through evaporation will depend on the basin
area and the net evaporation rate. The basin area is given by the relation
r. • A Throughput x Settling Time ,0 cx
Basin Area = - " f. . - r - - — & - (8.5)
Water Depth
In the present, study we will assume that peak usage and surge periods can be
accounted for by designing for a throughput which is 50% greater than the mean
annual consumption. A conservative settling time to clarify a turbid surface
stream, especially where a precipitant such as lime is used, may be taken
to be 24 hours. Finally, we choose the settling basin water depth to be 3 ft,
which is a generally accepted value. Using these values Eq. (8.5) can be
written
Basin Area (ft ) = 1.5 x Consumption ( — °- - ; — ) x „ - ^ x 8.33 — -
r cal. mm 3 ft. gal
1 ft3 inin
X T-r — ; — 77; — X 1440 -r -
62.4 Ibs day
= 96.1 x Consumption ( — — — ) . (8.6)
v cal. nan
With the basin area determined, the quantity evaporated in gal/ calendar minute
is given by the relation
Quantity Evaporated( — !p — — ) = Basin Area(ft ) x Net Evaporation Rate( — )
Oct_L • lujLil J^
1 ft ,9 , Ibs water 1 gal i
X 12 in X ^ ft3 X 8.33 Ibs
1 yr 1 day
x 365 days X 1440 min
= 1.19 x 10~ x Basin Area(ft ) x Net Evaporation Rate(— ) .
(8.7)
158
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In Table 8-4 are summarized the pond evaporation rates minus the annual precipi-
tation for the sites of the present study. Also tabulated is the net evaporation
rate assuming some form of evaporation control such as the application of
monomolecular films to the water surface. This control may also be a natural
one resulting from the presence of impurities in the local waters. Experience
indicates that a reasonable maximum value to take for the effective reduction
in the evaporation minus precipitation rate is 25% . Also shown in Table 8-4
are the sites at which settling basins would be used based on the feed water
suspended solids concentrations given in Appendix B.
Table 8-4. Evaporation rates without and with evaporation
control and need for settling basin.
Location
Pond Evap.-Precip.
(in/yr)
Beulah
Cols trip
Gillette
Kaiparowits
Nava j o
Rifle
30
35
40
61
53
33
Net Evap.
(in/yr)
23
26
40
46
40
25
Settling Basin
Need
No
Yes
Yes
No
Yes
V ft
Yes
* Except for 100,000 bbl/day oil shale plant where groundwater is used.
159
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The calculation of the basin area cannot of course be carried out until
all the consumption figures are known. The calculation generally involves one iter-
ation, in that it is necessary to assume a figure for the evaporation losses
in the basin and the reservoir (see next section) to determine the through-
put. A loss rate from these sources is then determined and the result is
iterated. One iteration is usually sufficient.
8.9 Reservoir Evaporation
In this study we have assumed that the clarified feed water is pumped
to an on-site reservoir where it is stored prior to use. To determine•the
reservoir size, a one week supply for the mine and plant is assumed to be
held in storage. As a reservoir depth we take 21 ft. In that case it can
be seen that the storage time per unit water height (3 days/21 ft) is the
same as was chosen for the settling basin so that the reservoir is given by
the same expression as Eq. (8.6), that is,
•j gal
Reservoir Area(ft ) = 96.1 x Consumption(—= —) (8.8)
cal. mm
Similarly, the net evaporation rate is given by Eq. (8.7) with the basin area
understood to be replaced by the reservoir area.
For the reservoir characteristics chosen, it follows that in those cases
where both a settling basin and a reservoir are required that the quantities
evaporated will be the same. This simplifies somewhat the iterative calcula-
tion necessary to determine the losses that was described in the last section.
The results based on Eqs. (8.6) to (8.8) and the rates given in Table 8-4 are
summarized in the tables of Section 10.
160
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References
1. Hendrickson, T.A. (editor), Synthetic Fuels Data Handbook, Cameron
Engineers, Inc., Denver, Colorado, 1975.
2. Babcok & Wilcox, Steam - Its Generation and Use, 38th Edition, Revised,
pp. 18-1 ff., Babcok & Wilcox Co., New York, 1975.
3. Batelle Columbus Laboratories, "Detailed Environmental Analysis Concerning
a Proposed Gasification Plant for Transwestern Coal Gasification Co.,
Pacific Coal Gasification Co., Western Gasification and The Expansion
of a Strip Mine Operation Near Burnham, New Mexico Owned and Operated
by Utah International Inc.," Federal Power Commission, Feb. 1, 1973.
4. Bureau of Land Management, "Final Environmental Impact Statement Proposed
Kaiparowits Project," Chapter I, FES 76-12, U.S. Dept. of the Inte'rior,
March 3, 1976.
5. North Dakota Gasification Project for ANG Coal Gasification Co.,
"Environmental Impact Report in Connection with Joint Application of
Michigan Wisconsin Pipe Line Co. and ANG Coal Gasification Co. for a
Certificate of Public Convenience and Necessity," Woodward-Clyde
Consultants, Federal Power Commission Docket No. CP75-278, Vol. Ill,
March 1975.
6. Wyoming Coal Gas Co. and Rochelle Coal Co., "Applicant's Environmental
Assessment for a Proposed Gasification Project in Campbell and Converse
Counties, Wyoming," Prepared by SERNCO, October, 1974.
7. Colony Development Operation, "An Environmental Impact Analysis for a
Shale Oil Complex at Parachute Creek, Colorado, Part 1 - Plant Complex
and Service Corridor," Atlantic Richfield Company, Denver, Colorado, 1974.
8. Energy Transportation Systems, Inc., Unpublished Document, Casper,
Wyoming, Feb. 21, 1974. Summarized in memorandum.of E. Rappaport,
Radian Corp., Austin, Texas.
9. Metcalf & Eddy, Inc., Wastewater Engineering, p. 231, McGraw-Hill,
New York, 1972.
10. Office of Water Resources Research, "Evaporation Suppression, a Bibliography,"
WRSIC 73-216, Water Resources Scientific Information Center, U.S. Dept.
of the Interior, Washington, D.C., 1973.
161
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9. MUNICIPAL WATER REQUIREMENTS AND RESIDUALS
In this section we present a rough basis for the estimation of the net
municipal water requirements associated with an increased population in the
areas considered, resulting from the introduction of one or more of the
mine-plant complexes. In presenting these estimates it is to be understood
that we assume all sewage water effluent in any municipality will be treated
to enable its reuse within the mine-plant boundaries.
In Table 9-1 are shown our estimates of municipal water requirements
expressed on a gallons per capita per day basis. The total water requirements
are rounded average estimates derived from Ref. 1. The reasons for the some-
what higher figures for Montana and Wyoming compared with, say, Colorado are
not completely evident, since one might have expected the more arid region to
have a somewhat higher usage. One explanation may be that these data were
obtained from averaging in a considerable number of areas where there is a
large water consumption for animals. It should be noted that in some instances,
particularly in the case of Utah, the water consumption given' in Table 9-1
is lower than that cited in Ref. 1. The reason for this is that for the
municipalities to be associated with the mine-plant complexes, the water use
will be principally for domestic, commercial and public consumption, with
little requirement for the industrial portion of the total consumption that is
normally taken into account in municipal usage. On the other hand, the
Utah figure given in Ref. 1 averages in the relatively large industrial
consumption associated with the Salt Lake region which encompasses the major
portion of the state's usage.
162
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Table 9-1. Municipal water requirements in
gallons per capita per day .
Treated for
State Total Consumed Reuse
Montana, Wyoming 175 50 125
Colorado, New Mexico,
Utah 150 60 90
North Dakota 100 30 70
For Montana, Wyoming and North Dakota the consumptive use was estimated
at around 30%. The somewhat higher consumption of 40% was taken for Colorado,
New Mexico and Utah because of the more arid nature of the areas and the
concomitant higher rates of municipal consumption. The last column of Table 9-1
is the difference between the first two and represents that water which will
be treated for reuse.
We may also estimate the quantity of wet sludge which must be disposed of
after treatment for reuse (see also Section 7.6). A standard figure for
suspended solids in sewage is 0.25 Ib/capita/day (Ref. 1, p. 581). As in
Section 7.6,we assume that any increased water usage above the average value
of 100 gal/capita/day associated with this solids loading,does not increase
the suspended solids effluent. Furthermore we consider, as elsewhere in this
study, that the sludge from any water treatment plant is dewatered to 80%
water (20% solids). This yields a sludge rate of 1.25 Ibs of wet sludge per
capita per day. Once the population figures are specified this figure would
provide an estimate of the quantity of sludge to be disposed of daily.
Reference
1. Metcalf & Eddy, Inc., Wastewater Engineering, p. 25, McGraw-Hill,
New York, 1972.
163
-------
10. SITE-SPECIFIC RESULTS
The summary of the total water consumed and wet-solids residuals
generated at each site and for each unit size mine-plant complex are
given in Table 10-1. A detailed breakdown by water use category of
the water consumption and residuals generated for each plant-site
combination is presented in the tables following Table 10-1. Each
calculated quantity has been derived in the preceding sections. The
results are presented by site in alphabetical order and by process
in the order shown in Table 10-1.
164
-------
Table 10-1. Summary of total water consumed and residuals generated at each site.
FACILITY
SLURRY PIPELINE (25 x 106 tons/yr @ 100% load factor)
ACRE-FT/YR*
WET SOLIDS* - 10« TONS/YK
LURGI (250 x 106 scf/stream day ? 90% load factor)
ACRE-FT/YR*
WET SOLIDS1' - 106 TONS/YR
SYNTHANB (250 x 106 scf/stream day @ 90% load factor)
ACRE-FT/YR*
MET SOLIDS1' - 106 TONS/YR
SYNTHOIL (100,000 bbl/strcam day 8 90* load factor)
ACRE-FT/YR*
WET SOLIDS* - 10s TONS/YR
ELECTRICAL GENERATION ( 3,000 HWe @ 35% eff and
70% load factor)
ACRE-FT/YR*
WET SOLIDSf - 10s TONS/YR
ELECTRICAL GENERATION (1,000 HWe 0 35% eff and
70% load factor)
ACRE-FT/YK*
WET SOLIDS* - 106 TONS/YR
OIL SHALE (50,000 bbl/stream day 8 90% load factor)
ACRE-FT/YR*
WET SOLIDS'" - io8 TONS/YR
OIL SHALE (100,000 bbl/streaffl day S 90% load factor)
ACRE-FT/YR"
WET SOLIDS* - IO6 TONS/YR
BEULAH,
NORTH DAKOTA
3,307
1.20
7,671
1.08
10,085
2.00
23,884
2.65
CO) .STRIP,
MONTANA
4,618
1.27
7,808
1.12
10,296
2.07
26,659
3.01
GILLETTE,
WYOMING
19,171
4,206
0.72
7,776
0.71
9,227
1.23
25,842
1.32
KAIPARONITS/ NAVAJO/
ESCAIANTB
UTAH
29,816
5.30
FAKMIMGTON
NEW MKXICO
5,639
3.00
8,670
2.84
11,753
5.31
29,206
5.00
RIFLE,
COLORADO
9,494
0.38
6,480
20.40
12,924
40.81
* water Consumed
t Residuals
-------
SITE BEULAH
PLAMT TYPE Lurgi, 250 x 10 set per
stream day
199
2,050
:OMSUMED
(-769)
26
3
(-740)
3,0/6
3
2
87
3,168
169
706
16.8.
13
2
-
389
-
8
226
.. 16. ...
17
11
t
121
3,307
o
6
S
±
;-
o
o
i
i
„
WET-SOLID
120
27
147
18
13
31
438
.04
.04
5,374
311
.J3
.09
2.685
3,301
SOLIDS
DRY SOLID
24
14
38
9
7
16
175
' 1.B28 '
251
2,079
2,308
HATER IN SOLIt'
16
1
18
' ' 1.5 "~
"^viL-L.
2.6
44
1
91
10
101
166
FOOTNOTES
s,primarily soluble
inorganic waste
i,primarily insoluble
inorganic waste
o,primarily insoluble
organic waste
-------
SITE BEULAH
PIJUIT TYPE Synthane, 250 x 10 scf per
stream day @ 90Z load factor
PROCESS,
Net water consumed
Condensate Treatment Sludge
Boiler Demineralizcr Waste
SUBTOTAL
COOLING
Treatment Waste
Drift £ Leakage
SUBTOTAL
FLUK GAS DESUI.Ft'P.IZATION
MI MI KG
Road, Mine, Embankment Oust: Control
Handling £ Crushing Dust Control
Service 4 Fire Water
Sanitary £ Potable Water
Revegetation
Coal washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL £ OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service S Fire Water - Plant
Sanitary £ Potable Water - Plant
SUBTOTAL
TOTAL
WATER CONSUMED
GAL/C. HIM
658
14
2
674
ACRE-FT/YR
1,061
23
3
1,087
3.084 I 4.974
2
2
89
3,177
532
116
93
6
1
-
-
216
-
13
35
69
31
7
2
157
4,756
3
3
144
5,124
858
187
150
10
2
-
-
349
21
57
11J
50
11
3
253
7,671
r. , i t o
o
s
8
i
O
O
i
i
o
o
WET-SOLID
TONS/C. DAY
105
23
128
27
24
51
170
.04
.04
5"4i
2,077
.12
.09
2,619
2,968
SOLIDS
DRY SOLID
TONS/C, DAY
WATKR IN SOLID
GAL./C. MIN
.,, .^ ..... .-.--•__ _
21
12
33
14
i-2 —
26
68
416
1,663
2,079
2,206
14
1.9
16
2.3
4.3
17
21
69
90
127
FOOTNOTES
s, primarily soluble
inorganic waste
i, primarily insol'&le
inorganic waste
o, primarily insoluble
organic waste
-------
SITE BEULAH
PLANT Tm; Sytuhoil^ 100,000 bbl per
scream dav _@ 90* J.oad factor
PROCESS
Net Water Consumed
Condensate Treatment sludge
Boiler Dcfflineralizer Waste
SUBTOTAL
COOLING
Treatment Waste
Drift £ Leakage
SUBTOTAL
FLUE CAS DESULFUMZATION
MINING
Boad, Mine, Embankment Oust Control
Handling & Crushing Dust control
Service £ Fire Water
Sanitary £ Potable Water
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottora Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service c Fire Water - Plant
Sanitary £ Potable Water - Plant
SUBTOTAL
TOTAL
WATER <
(-72) .__
12
1
(-59)
5.254
2
""" ' "
244
8,729
-
368
297
19
3
-
-
687
_
26
616
-
58
J.8. .
6
764
10,085
0
S
S
i
o
o
i
a
o
WET-SOUD
TONS/C DAY
89
S
97
20
46 ' ""
66
.07
.07
5,330
-
.20
.15
5,330
5,493
SOLIDS
DKY SOLID
TONS/C. DAY
18
It
22
10
5J "
33
4,100
-
4,100
4,155
WATER IN SOLTU
GAL/C. KIN
12
0.7
13
1.7 1
3.?f~
5.6
-
205
-
205
224
FOOTNOTES
s(primarily soluble
inorganic waste
i,primarily insoluble
inorganic waste
o,primarily insoluble
organic waste
-------
SITE BEULAH
PLANT TYPE 3-°°° «"* @ 3« 6«- 3nd
70Z load factor
PROCESS
Nut Wator Consumed
Condensate Treatment sludge
SUBTOTAL
COOLING
Treatment waste
Drift £ Leakage
SUBTOTAL
FLOE GAS DESULFURIZATION
MINING
Road, Mine, Embankment Dust Control
Handling & crushing Dust Control
Service £ Fire Water
Sanitary £ Potable Water
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION. SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service s Fire Water - Plant
Sanitary & Potable Water - Plant
SUBTOTAL
TOTAL
WATER
6.1
0.1
P. 360
17
36
13,413
896
149
120
8
1
-
_
278
_
39
45
RQ
40
5
2
220
14,807
:ONSUMED
0.2
0.2
21,550
27
58
21,635
1,445
240
194
13
2
-
_
449
-
63
72.5
141 S
65
8
3
355
23,884
s
i
o
o
i
i
o
o
WET-SOLiU
TONS/C DAY
1.7
1.7
169
169
3,720
,05
.OS
697
2.672
.08
.07
3,369
7,260
SOLIDS
DRY SOLID
TONS/C DAY
0.*
0.9
~"~ ~6"?
67
1,488
535
2,138
2,673
4,229
WATER IN SOLID
GAL/C. MIN
6.1
0.1
17
17
372
27
89
116
505
FOOTNOTES
s, primarily soluble
inorganic waste
inorganic waste
o, primarily insoluble
organic waste
-------
SITE COLSTRIP
PLAOT TYPE Lurgl, 250 x 10 scf per
stream day @ 90Z load factor
PROCKSS
Condensate Treatment Sludge
Boiler Deraincralizer Waste
SUBTOTAL
COOLING
Evaporated
Treatment Waste
Drift £ Leakage
SUBTOTAL
FLUE GRS DESULFURIZATIOU
HIKING
Road, Mine, Embankment Dust Control
Handling & Crushing Dust Control
Service £ Fire Water
Sanitary s Potable Water
Revegetation
Coal Hashing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL fi OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service S Fire water - Plant
Sanitary t Potable Water - Plant
SUBTOTAL
TOTAL
WATER CONSUMED
GAiyC. MIN
183
12
2
197
2,004
2
1
57
2,064
233
69
82
6
1
-
-
158
9
9
146
11
27
7
2
211
2,863
ACRE-FT/YR
295
20
3
318
. 3.232
3
- J-6
92
3,329
376
__.. Ill
132
10
2
-
-
255
14.5
14.5
235
18
.. . 44
11
3
340
4,618
S, i, 0
o
S
s
f.
0
o
1
1
q
0
SOLIDS
WET-SOLID
TONS/C. DAY
89
24
113
DRY SOLID
TOKS/C. DAY
18
12
30
1 " '
19
14
33
540
.04
.04
2,470
326
J2
.09
2,796
3,482
10
7
17
216
1,9UU
260
2,160
2,423
WATER IN SOLID
CAL/C. HtH
12
1
14
1.6
— ,_.kL~-~
2.8
54
95
11
106
177
FOOTNOTES
S,primarily soluble
inorganic waste
i,primarily insoluble
inorganic waste
o,primarily insoluble
organic waste
-------
SITK COLSTR1P
PLANT TYPK Synthane,250 x 10 set per
stream day @ 90Z load factor
PROCESS
Net Water Consumed
Condensate Treatment Sludge
Boiler Demineralizer Waste
SUBTOTAL
COOLING
Treatment Waste
Drift £ Leakage
SUBTOTAL
FLUE GAS DESULFURI2ATION
MINING
Road, Mine, Embankment. Dust control
Handling £ Crushing Dust Control
Service s Fire Water
Sanitary S Potable Hater
Rcvegetation
Coal Mashing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service & Fire Water - Plant
Sanitary S Potable Water - Plant
SUBTOTAL
TOTAL
WATER (
658
14
2
674
3.240
2
2
93
3,337
517
63
74
5
1
-
-
143
14
14
36
72
25
7
2
170
4,841
rONSUMKD
1.061
23
3
1,087
5.226
3
3
150
5,382
834
102
119
8
2
-
-
231
23
23
5B
116
40
11
3
274
7,808
s i o
o
s
s
i
0
1
i
o
o
WET-SOLID
TONS/C DAY
103
22
127
27
24
51
170
.03
.03
564
2,160
,12
,09
2,724
3,072
SOLIDS
DRV SOLID
TONS/C DAY
21
11
32
14
12. , -, ,
26
68
432
1,728
2,160
2,286
WATER IN SOLID
GAL/C. KIN
14
1.8
16
2'3 „
2 _,.
4.3
17
22
72
94
131
FOOTNOTES
s, primarily soluble
inorganic waste
inorganic waste
o, primarily insoluble
organic waste
-------
ro
SITE COLSTRIP
PLAHT TYPE Synthoil, 100,000 bbl per
Stream day ? 903! load factor
PROCESS
Net Water Consumed
Condensate Treatment Sludge
Boiler Domineralizer Haste
SUBTOTAL
COOLING
Treatment Waste
Drift s Leakage
SUBTOTAL
FLUE GAS DESULFURIZATtOH
MINIMS
Road, Hinc, Embankment Dust Control
Handling £ Crushing Dust Control
Service £ Fire Water
Sanitary s Potable Hater
Revegetation
Coal Hashing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust control - Plant
Service £ Fire Hater - Plane
Sanitary s Potable Hater - Plant
SUBTOTAL
TOTAL
WATER (
526
9
I
536
4.9J,9
1
3
143
5,066
_
123
1*6
11
2
-
-
282
19
19
397
-
49
11
4
499
6,383
XJNSUMEO
848
15
1.6
865
7.934
1.4
5
231
8,171
198
236
18
3
-
-
455
31
31
640
-
79
18
6
805
10,296
.
o
s
8
i
o
o
1
o
o
WUT-SOLID
67
8
75
16
40
56
.06
.06
5,537
.20
.15
5,537
5,668
SOLIDS
DRV SOLID
13
4
17
8
20
28
4,259
4,259
4,304
WATER IN SOLID
GAL/C >!IN
9
U. °'6
10
1.3
.^2,3^.,.,.. .
4.6
213
213
228
FOOTNOTES
s, primarily soluble
inorganic waste
o,primarily insoluble
organic waste
-------
SITE COLSTRIP
PLAHV TYPE 3,000 MWe ? 35% off. and
70Z load factor
PROCESS
Not Water Consumed
Condcnsate Treatment Sludge
Boiler Demineralizel: Waste
SUBTOTAL
COOLING
Evaporated
Treatment Waste
Drift & Leakage
SUBTOTAL
FLUE GAS DESULFUMZATION
MIHIHG
Road, Mine, Embankment Dust control
Handling £ Crushing Dust Control
Service & Fire Water
Sanitary s Potable Hater
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL £ OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service 1 Fire Water - Plant
Sanitary £ Potable Water - Plant
SUBTOTAL
TOTAL
WATER
0.1
0.1
14,040
15
38
'4,093
1,975
81
95
6
1
-
-
183
49
49.
46
93
32
5
2
276
16,527
:ONSUMED
0.2
0,2
22.646
24
62
22,732
3,186
131
153
10
2
-
-
296
79
79
74
150
52
8
3
445
26,659
8
i
O
o
i
i
o
o
WET- SOLID
1.6
1.6
152
152
4,588
.04
.04
723
2,780
.08
.07
3,503
8,245
SOLIDS
DRY SOLID
TONS/C DAY
0,8
0.8
61
61
1,835
1
555
2,222
2,777
4,674
WATER IN SOLIU
GAL/Ct M1N
_
0,1
oa
15
15
459
28
93
121
595
i
FOOTNOTES
s, primarily soluble
inorganic waste
o, primarily Insoluble
organic waste
-------
SITE GILLETTE
PLANT TXPfi Slurry Pipeline,
250 x 10 tons/yr 8 100Z load facto:
PROCESS
Net Water Consumed
Condcnsato Treatment Sludge
Boiler Dcmineralizer Haste
SUBTOTAL
COOLING
Treatment: Waste
Drift s Leakage
SUBTOTAL
FLUE GAS DESULFURIZATIQN
HI!UHC
Road, Mine, Embankment Oust Control
Handling & Crushing Dust Control
Service £ Fire Water
Sanitary fi Potable Water
Re vegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL 8 OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Pust control - Plant
Service & Fire Hater - Plant
Sanitary t Potable Water - Plant
SUBTOTAL
TOTAL
WATER C
11,420
_
-
11,120
_
-
~
-
-
95
228
17
3
-
-
343
41
41
-
-
38
2
1
1?3
11,886
fflNSUMED
18,420
-
-
18,420
-
•
~
-
-
153
368
27
5
-
.
553
66
66
-
-
61
3
2
198
19,171
o
0
o
o
WET-SOLID
.10
.10
.04
.03
.17
SOLIDS
DRV SOLID
WATER IN SOLID
CAI/C . MTH
FOOTNOTES
s,primarily soluble
inorganic waste
i/primarily insoluble
inorganic waste
o,primarily insoluble
organic waste
-------
Ul
SITE GILLETTE
1-LANT TYPE Lurgi, 250 x 10 scl per
stream day g 90J load factor
PROCESS
Set Water Consumed
Condensate Treatment Sludge
Boiler Dcraineralizer Waste
SUBTOTAL
COOLING
Evaporated
Treatment Waste
Drift S Leakage
SUBTOTAL
FLUE GAS DESULFURIZATION
MINt:!C
Road, Mine, Embankment Dust Control
Handling £ Crushing Dust Control
Service & Fire Water
Sanitary £ Potable Water
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL £ OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service t Fire Water - Plant
Sanitary S Potable Water - Plant
SUBTOTAL
TOTAL
WATER C
38
13
2
53
2J344
2
1
58
2,105
178
34
84
6
1
-
-
125
9
9
86
6
28
7
2
147
2,608
;ONSUMED
61
21
3
85
3.297
3
1.6
93
3,395
287
SS
135
10
2
-
-
202
14.5
14.5
139
10
45
11
3
237
4,206
o
s
s
1
0
o
1
i
o
o
WET-SOLID
TONS/C. DAY
100
26
126
20
14
34
163
.04
.04
1.449
190
.12
.09
1,639
1,962
SOLIDS
DRV SOLID
TONS/C DAY
20
13
33
10
7
17
65
1,113
154
1,2'67
1,382
WATER IN SOLID
GAL/C. MIN
13
2
15
1.6
1.2 _, ^
2.8
16
__r
56
6
62
96
FOOTNOTES
s, primarily soluble
inorganic waste
o, primarily insoluble
organic waste
-------
SITE GILLETTE
PLANT TYPE Synthane, 250 x 10 scf per
stream day @ 90Z load factor
F.RDCESS
Net Water Consumed
Condensate Treatment Sludge
Boiler Demineralizer Haste
SUBTOTAL
COOLING
Evaporated
Treatment waste
Drift fi Leakage
SUBTOTAL
FLUE GAS DESULFURIZATION
KINING
Road, Mine, Embankment Dust control
Handling £ Crushing Dust control
Service 6 Fire Water
Sanitary & Potable water
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL & OTHERS
Settling Basin Evaporation
Reservoir. Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service & fire water - Plant
Sanitary £ Potable Water - Plant
SUBTOTAL
TOTAL
HATER CONSUMED
OM./C. MIN
658
14
2
67 tt
3,266
2
2
94
3,364
532
31
75
6
1
-
-
113
17
17
28
42
25
7
2
118
4,821
ACRE-FT/YK
1.061
23
3
1,087
5,268
3
3
152
5,426
858
50
121
10
2
-
-
163
, , ,27,5
27.5
45
68
40
11
3
222
7,776
s, i, o
0
s
s
i
o
0
1
1
o
o
SOLIDS
WET-SOLID
TOKS/C. DAi
105
23
128
28
24
52
170
.03
.03
...,. 331
1,266
.12
.09
1.597
1,947
DRY SOLID
TOKS/C, DAY
21
11
32
WATER IN SOLID
GAL/C. MIN
14
1.9 .
16
1
14
12
26
68
253
1,014
1.267
1,393
2.3
2
4.3
17
, I,, ^
13
42
55
92
FOOTNOTES
s,primarily soluble
inorganic waste
i,primarily insoluble
inorganic waste
o,primarily insoluble
organic waste
-------
SITE GILLETTE
PLANT TYPE Sjmthoil, 100,000 bbl per
stream day @ 90Z load factor
PRO£gss
Net Water Consumed
Condensate Treatment Sludge
Boiler Dcraineralizer Waste
SUBTOTAL
COOLIMG
Treatment Waste
Drift 6 Leakage
SUBTOTAL
FLUE CAS DESULFURI2ATION
MINING
Road, Mine, Embankment Dust Control
Handling f Crushing Dust Control
Service S Fire Hater
Sanitary & Potable Water
Rcvegotation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Ply Ash Disposal
Dust Control - Plant
Service £ Fire Water - Plant
Sanitary S, Potable Water - Plan.t
SUBTOTAL
TOTAL
HATER
290
8
1
299
4.718
1
4
i3>
4,860
62
149
11
2
-
-
224
20
20
233
-
50
11
4
338
5,721
CONSUMED
468
13
. 1
482
7.610
2
6
221
7,839
100
240
18
3
-
-
361
32
32
376
-
81
1H
6
545
9,227
o
s
a
i
o
0
i
6
o
WBT-SOLTD
61
8
69
15
46
61
.06
.06
3,248
-
.20
.15
3,248
3,378
SOLIDS
DRV SOLID
TOH^/C DAY
12
4
16
8
23
31-
2,49B
,
2,498
2,545
WATER IN SOLI
G7VJ./C . MI N
8
0.6
9
1.3
3.9
5.2
125
_
125
139
•QOTOOTES
s, primarily soluble
inorganic waste
, primarily insoluble
organic waste
-------
SJTE GILLETTE
PIJUJT TYPE 3,000 MHe g 35Z elf . and
70Z load factor
PROCESS
Not Water Consumed
Condensate Treatment Sludge
Boiler Domineralizer Waste
SUBTOTAL
COOUNG
Treatment Waste
Drift t Leakage
SUBTOTAL
FLUE GAS OESUI.FUMZATIOH
HIKING
Road, Mine, Embankment Dust Control
Handling £ Crushing Oust Control
Sanitary 6 Potable Water
Rcvegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL £ OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
fly Ash Disposal
Dust Control - Plant
Service & Fire Water - Plant
Sanitary 1. Potable Water - plant
SUBTOTAL
TOTAL
-WATER c
0.1
0.1
14,075
18
^b
14,133
1,512
40
97
8
1
-
-
146
55
55
27
54
32
5
2
230
16,021
-ONSUMED
0.2
0.2
22./03
29
65
22,797
2,439
65
156
13
2
-
-
235
89
89
43
87
52
8
3
371
25,842
s i o
i
o
o
1
i
o
o
WET-SOLID
1.6
1.6
182
182
1,373
.o£
.04
422
1,627
.08
.07 '
2,049
3,606
SOMtDS
DRY SOLID
TONS/C DAY
0.8
0.8
73
73
549
Jib
1,303
1,625
2,252
WATER IN SOLID
GAT'/C . HIM
0.1
0.1
18
18
137
16
54
70
225
s,primarily soluble
inorganic waste
i,primarily insoluble
inorganic waste
"jo,primarily insoluble
organic waste
-------
SITE KAIFAROWITS/ESCALANTE
PLANT TYPE 3'°°° W* $ 35Z efft and
702 Ififld factor
PROCESS
Not Water Consumed
Condcnsate Treatment Sludge
Boiler Demineralizer Waste
SUBTOTAL
COOLING
Treatment Waste
Drift £ Leakage
SUBTOTAL
FLUE GAS DESULFURIZATIOti
MINING
Road, Mine/ Embankment Dust Control
Handling fi Crushing Dust Control
Service E Fire Water
Sanitary 6 Potable Water
Revegetation
Coal Wash i no
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL £ OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Botton Ash Disposal
Fly Ash Disposal
Dust control - Plant
Service t Fire Water - Plant
Sanitary & Potable Water - Plant
SUBTOTAL
TOTAL
WATER <
0,2
0.2
14,770
26
36
14,832
2,313
38?
, ._ 62
12
8
658
1.J29
-
97
27
ST
>1
A
3
211
18,485
:ONSUMED
0.3
0.3
23,824
42
58
23,924
3,731
628
100
19
13
1 061
1,821
-
156
44
85
40
10
5
340
29,816
8
i
0
i
i,o
i
i
o
o
WET-SOLID
2.3
2.3
262
262
1,410
-- -?2
4,467
6,359
10.826
415
1.592
,10
.07
2,007
14,507
SOLIDS
DRY SOLID
1.2
1.2
104
104
564
4,020
3,564
7.584
319
1,274
1,593
9,846
HATKR IN SOLID
GAL/C fclN
0.2
0.2
26
26
141
75
Abb
5* '
16
53
69
777
COARSE REJECT
'AIL1NGS
FOOTNOTES
Srprimarily soluble
inorganic waste
.
o, primarily insoluble
organic waste
-------
CO
o
SITE NAVAJO/FARMINGTON
HJVNT TYPE Lurgl, 250 x 10 acf per
stress day 9 90S load factor
PROCESS^
Net Water consumed
Condensate Treatment Sludge
Boiler Dcniineralizer Waste
SUBTOTAL
COOLING
Treatment Waste
Drift s Leakage
SUBTOTAL
FLUE GAS DESULFURlZftTION
MIMING
Road, Mine, Embankment Dust Control
Handling £ Crushing Dust Control
Service & Fire Water
Sanitary S potable Hater
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL G CITHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service * Fire Hater - Plant
Sanitary S Potable Water - Plant
SUBTOTAL
TOTAL
WATER
526
11
2
539
1.792
1
1
52
1,8*6
289
97
85
9
2
130 .
323
16
16
401
28
28
7
3
499
3,496
COHSUHED
848
18
3
869
2r89l
1.6
J..6
84
2,978
466
156
137
i5
3
210
_
521
26
26
647
45
45
11
5
805
5,639
o
s
S
i
o
o
i
i
o
o
WET-SOLID
80
18
98
17
;3
30
468
.05
.05
6,787
835
.13
.09
7,622
8,218
SOLIDS
DRV SOLID
TONS/C DAY
16
9
25
9
6
15
187
5,222
667
5,889
6,116
WATER IN SOLID
GAL/C. M1K
11
1.5
13
1.4
1.1
2.5
47
2bl
28
289
352
FOOTNOTES
s,primarily soluble
inorganic waste
i,primarily insoluble
inorganic waste
o,primarily insoluble
organic waste
-------
CO
SITE NAVAJO/FARMINCTON
P1.ANT TYPE Synthane, 250 x 10 scf per
stream day @ 903! load factor
PROCESS
Net Water Consumed
Condensate Treatment Sludge
Boiler Dcmincralizer Waste
SUBTOTAL
COOUNG
Treatment Waste
Drift & Leakage
SUBTOTAL
FLUE GAS DESULFURI2ATJON
MIN1IIG
Road, Mine, Embankment Dust "Control
Handling fi Crushing Dust Control
Service & Fire Water
Sanitary C Potable Water
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION , SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service £ Fire Water - Plant
Sanitary £ Potable Water - Plant
SUBTOTAL
TOTAL
HATER C
658
14
1
673
3,384
2
2
98
3,486
532
. 87
77
8
2
117
-
291
25
25
123
_ 184
26
7
3
393
5,375
XWSUMED
1.061
23
1.6
1,086
5.459
3
3
158
5,623
858
140
124
13
3
189
-
469
40
40
199
297
42
11
$
634
8,670
o
s
B
T.
a
o
1
i
o
rp
WET-SOLID
105
17
122
27
24
51
170
•°4
.04
1.416
5.S21
.11
.09
7.437
7,780
SOLIDS
DRY SOLID
__, .. ?!—„.„.
8
29
14
12
26
68
1 477
4 417
5.889
6,012
WATER IN SOLID
GAL/C HIM
^<>
1,4
Tj
2.3
i
4.3
17
74
184,
258
294
FOOTNOTES
s, primarily soluble
inorganic waste
inorganic waste
o, primarily insoluble
organic waste
-------
CO
SITE HAVAJO/FARMTNnTON
PLANT TYpKSynthoi1' 1°°.000 bbl Per
stream day @ 90Z load factor
PROCESS
Net Water Consumed
Condensate Treatment Sludge
Boiler Dcmincralizer Waste
SUBTOTAL
CODLING
Treatment Waste
Drift s Leakage
SUUTOTAL
FLOE GAS OESULFURIZATION
MINING
Road, Mine, Embankment Dust Control
Handling £ Crushing Dust Control
Service £ Fire Water
Sanitary £ Potable Water
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service £ Fire Water - Plant
Sanitary « Potable Water - Plant
SUBTOTAL
TOTAL
WATER C
625
7
1
633
4.765
1
4
138
4,908
172
151
17
3
232
-
575
33
33
1.035
_
50
13
6
1.170
7,286
XINSUMED
1.009
11
. 1.6
1,021
7.686
2
6
223
7,917
278
244
27
5
374
-
928
53
53
1.670
_
80
21
10
1.887
11,753
c i o
O
s
e
i
o
o
1
o
o
WET-SOLID
52
6.
58
13
41
54
.08
.08
14,430
_
.24
.15
14.430
14,542
SOLIDS
DRY SOLID
10
3
13
7
21
28
11,100
-
11,100
11,141
WATER IN SOLID
GAL/C . MIN
7
O.S
8
1.1
3.5
4.6
555
-
555
568
FOOTN?OTES
s,primarily soluble
anorganic waste
i,primarily InsolubZL>s
inorganic waste
o,primarily insoluble
organic waste
-------
SITE NAVAJO/FARMINGTON
PLANT TYPE 3,000 MWe @ 35Z eft. and
70X load factor
PROCESS
Not Water Consumed
Condensatc Treatment Sludge
Boiler Dcmineralizer Waste
SUBTOTAL
COOLING
Treatnent Waste
Drift £ Leakage
SUBTOTAL
FLUE GAS DKSULFURIZATION
MINING
Road, Mine, Embankment Dust Control
Handling (• Crushing Dust Control
Service £ Pirc Hater
Sanitary 6 Potable Water
Revegetation
Coal Washing
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL £ OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service t Fire Water - Plant
Sanitary i Potable Water - Plant
SUBTOTAL
TOTM.
WATER C
0.1
0.1
14.617
17
38
14,672
2,456
]1?
•59
11
2
151
-
375
83
83
1SS
?17
\\
6
3
603
18,106
rONSUMED
0.2
0.2
23.577
28
61
23,666
3,961
1R1
160
18
3
244
-
606
134
134
255
382
53
10
5
973
29,206
s i o
1
0
o
i
i
o
0
WET-SOLID
TONS/C DAY
1.2
1.2
171
171
3,970
.05
.05
2.463
7,099
.11
.oi
9,562
i3';m
SOLIDS
DRY SOLID
TONS/C DAY
0.6
0.6
67
~"
67
1,588
•
1.893
5,677
7,570
9,226
WATER IN SOLID
GAL/C. MIN
0.1
0.1
17
17
397
-
__
95
237
332
746
FOOTNOTES
s, primarily soluble
inorganic waste
o, primarily insoluble
organic waste
-------
CO
SITE RIFLE
PLANT TYPE 1.000 Mtfe @ 3SZ etf. and
70* load factor
PROCESS
Net Water Consumed
Condensate Treatment Sludge
Boiler Dcmineralizer Waste
SUBTOTAL
COOLING
Evaporated
Treatracnt Waste
Drift (• Leakage
SUBTOTAL
FLUE GAS DESULrURIZATION
KtKIUC
Road, Hine, Erabanknent Dust Control
Handling * Crushing Dust Control
Service S Fire Water
Sanitary & Potable Water
Revegetation
Coal. Washing
SUBTOTAL
EVAPORATION! , SOLIDS DISPOSAL & OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Bottom Ash Disposal
Fly Ash Disposal
Dust Control - Plant
Service fc Fire water - Plant
Sanitary S Potable Water - Plant
SUBTOTAL
TOTAL
HATER CONSUMED
GAL/C. MIN
0.03
0.03
4,867
L *
12
4,883
884
29
21
3
1
-
-
54
17
17
7
13
7
2
1
64
5,885
ACRE-FT/XR
0.05
0.05
7_,851
7
19
7,877
1,426
, 47 ___
34
5
2
-
~
88
27.5
27. S
11
21.. __
11
3
2
103
9,^94
s, i, o
S
i
i
i
o
SOLIDS
WET-SOLID
TONS/C. DAY
0.3
0.3
45
45
520
.01
.01
100
380
.04
.03
480
1,045
DRY SOLID
TONS/C. DAY
0.2
0.2
18
18
208
>6
302
378
604
WATER IN SOLIC
GAL/C. KM
0.03
0.03
4
4
52
4
13
17
73
FOOTNOTES
s/primarily soluble
anorganic waste
i,primarily insoluble
inorganic waste
o/priiaarily insoluble
organic waste
-------
I-1
OO
Ui
SITE RIH,E
PLANT WE Shal6' 50'00° b" P0r
scream day @ 90% load factor
PROCESS
Wet Water Consumed
Retort
Refinery
SUBTOTAL
COOLING
Treatment Waste
Drift c, Leakage
SUBTOTAL
FLUE CAS DESULFURIZATJCM
HIKING
Road, Mine, Enjbankmcnt Dust Control
Handling & Crushing Dust Control
Service fi Firo Water
Sanitary £ Potable Water
Revegetation
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL £ OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Spent Shale Disposal
Venturi Scrubbing Dust Control
Dust control - Plant
Service s Fire Water - Plant
Sanitary £ Potable Water - Plant
SUBTOTAL
TOTAL
WATER CONSUMED
GAL/C. HIM
716
548
1,264
ACRE-PT/YR
_ 1,155
884
2,039
874 I 1.410
-
L 26
900
315
198
11
2
43
569
12
12
1,125
90
33
9
4
K285
4,081
.
42
1,452
SOS
319
18
3
69
917
19
19
1,815
145
51
15 .
§
2.072
6,480
s, i, o
a
o
i.sdlubTe org .
i.soluble orft.
0
o
SOLIDS
KBT-SOUD
TONS/C. DAY
.05
.05
55,022
871
.17
.11_.._
55.893
55,893
Dfiy SOLID
TONS/C. DAY
48,263
331 "
48,594
48,594
WATER IN SOLID
. GAL/C. HIN
1,127
90
1,217
1,217
FOOTNOTES
s, primarily soluble
inorganic waste
i, primarily insoluble
inorganic waste
o, primarily insoluble
organic waste
-------
CO
SITE RIFLE
PLANT TYPE Shale, 100,000 bbl per
stress day at 90Z load factor
PROCESS
Met Wator Consumed
Retort
Refinery
SUBTOTAL
COOLING
Evaporated
Treatment Waste
Drift 4 Leakage
SUBTOTAL
FLUE GAS DfiSULFURIZATION
MINING
Road, Mine, Embankment Dust Control
Handling S Crushing Dust Control
Service fi Fire Water
Sanitary s Potable Water
Revegetation
SUBTOTAL
EVAPORATION, SOLIDS DISPOSAL S OTHERS
Settling Basin Evaporation
Reservoir Evaporation
Spent Shale Disposal
Venturi Scrubbing pust Control
pust Control - Plant
Service t Fire Kater - Plant
Sanitary s Potable Water - Plant
SUBTOTAL
TOTAL
WATER CONSUMED
GM./C. KIN
1,432
1,096
2,528
1,748
1
52
1,801
630
396
21
4
86
1,137
2")
J.?™
180
66
19
8
2,546
8,012
ACKE-FT/YR
2,310
1,768
4,078
-
2.819
1.6
84
2,905
1,016
639
34
6
139
1,834
37
.. -trfi?q
290
107
31
13
4,107
12,924
s, i , o
o
o
t, soluble ore
L, soluble ors
0
0
SOLIDS
WET-SOLID
TONS/C. DM
9
9
.11
.11
110,045 ._
1,742
.34
.22
111,788
111,797
DHY SOLID
TONS/C. DAY
5
5
96.526
662
97,188
97,193
WATER IN SOLID
GM./C. M1K
1
0.7
0.7
2,254
180
2,434
2,435
FOOTNOTES
s,primarily sellable
inorganic waste
i,primarily insoluble
inorganic waste
o,primarily insoluble
organic waste
-------
11. FINDINGS
The findings of this study are presented in the following sections
on the basis of total site-specific water consumption and residuals, a
breakdown of these quantities, and regional water consumption and
residuals.
11.1 Total Site-Specific Water Consumption and Residuals
Table 10-1, repeated here as Table 11-1, summarizes the study find-
ings on the net annual water consumption and wet solid residuals generated
at each site for the unit size mine-plant complexes assumed to be located
there.
The largest variation in water consumption as a function of site
(a factor of about 1.7) is for the Lurgi process. This is principally a
consequence of the differences in coal moisture at the different locations,
The lowest consumption is at Beulah, North Dakota where the net consumed
f) O
water is found to be 2.96 x 10 gal/day (3.31 x 10 acre-ft/yr) or about
one-third the lowest published design estimates. The corresponding
variations in water consumption for the Synthane and Synthoil facilities
are found to be relatively small being no more, respectively, than 13%
and 16%. However, for the steam electric power generating plants
a maximum difference in water consumption of 25% is noted. These same
findings do not hold for the residuals, as we shall discuss below.
Since both the products and outputs of the Lurgi and Synthane plants
are the same, these two facilities may from this point of view be
compared directly. It is found that a Synthane complex uses from 1.5 to
2.3 times the water that a Lurgi facility does at the same site. This
is a consequence of comparing unlike technologies. It is related in part
187
-------
Table 11-1. Summary of net annual water consumption and wet solid residuals generated at each site.
FACILITY
SLUKJW PIPELINE (25 x ID6 tons/yr @ 100* .load factor)
NET WATER CONSUMED - 103 ACRE-PT/YR*
WET SOLID RESIDUALS - 105 TON'S/YR
IURGI (250 x 10* set/stream day @ 90* load factor)
NET WATER CONSUMED - 103 ACRE-FT/YR
WET SOLID RESIDUALS - 10s TONS/YR
SYMTHAHE (250 x 1C6 set/stream day @ 90% load factor!
NET KATSR COMSUV£D - 103 ACRE-FT/VR
KET SOLID RESIDUALS - 106 TOHS/YR
EYKTIIOIL (100,000 bbl/streara day @ 90% load factor)
IIET HATER CONSUMED - 103 ACRE-FT/YR
KtT SOLID RESIDUALS - 106 TONS/YR
ELECTRICAL GSNERATION (3,000 NKC 8 35% eff, 70% load factor)
KET KATER CONSUMED - 103 ACRE-FT/YR
KET SOLID RESIDUALS - 106 TONS/YR
ELECTKICAi GENERATION (1,000 KWe 6 35% e££, 70% load factor)
NET WATER CONSUMED - 103 A'CRE-PT/YR
VmT SOLID RESIDUALS - K>6 TONS/VR
OIL SHALE (50,000 bbl/stream day 6 90% load factor)
IIET WATER CONSUMED - 103 ACRE-PT/YR
hTT SOLID RESIDUALS - 10& TONS/YR
OIL SIIALE (100,000 bbl/stream day @ 90% load factor)
NP.T HATER CONSUMED - 103 ACRE-FT/YR
WET SOLID RESIDUALS - 106 TONS/YR
BEULAH,
NORTH DAKOTA
3.31
1.20
7.67
1.08
10.09
2.00
23.88
2.65
COLSTRIP,
MONTANA
4.62
1.27
7.81
1.12
10.30
2.07
26.66
3.01
GILLETTE,
WYOMING
19.17
4.21
0.72
7.78
0.71
9.23
1.23
25.84
1.32
KRIPAROWITS/
ESCALANTE,
UTAH
29.82
5.30
NAVAJO/
FARMINGTON,
NEW MEXICO
5.64
3.00
8.67
2.84
11.75
5.31
29,21
5.00
RIFLE,
COLORADO
9.49
0.38
6.48
20.40
12.92
40.61
O3
O3
•To convert 103 acre-ft/yr to 106 tons/yr multiply by 1.36,
to convert 103 "aesre-ft/yr to 1Q& gal/day multiply by 0.894.
-------
to the fact that the Lurgi process accepts wet coal and therefore the
moisture is utilized, but at a cost. This same water could in principle
also be recovered in Synthane plants from coal drying, but also at a cost.
Nevertheless, with the water treatment designs of this study, the absolute
consumptions of the Synthane plants are still below the lowest published
water consumption estimates for gasification plants of this size.
The products of the 100,000 bbl/day Synthoil and TOSCO II oil shale
facilities are roughly the same, so that they may with reason be compared
between themselves. It is of interest that their net water consumptions
are roughly comparable, with the shale oil facility about 20% higher. How-
ever, the solid residuals from the oil shale processing are very much
higher, as we shall discuss below.
In comparing the absolute water requirements between processes
caution must be exercised, since generally the fuel inputs and product
outputs are not directly comparable. One means of comparison among
processes, whose outputs are fuels to be used for their heating value, is
to express the net water consumptions in terms of gallons per million Btu
of fuel produced (gal/10 Btu). We may include the slurry pipeline in
this comparison if we take the output to be the heating.value of the
coal being transported. In a. rough manner, we may likewise include
electric power generation in the comparison by expressing the net water
consumed in terms of the heating value of the input coal, that is,
gal/10 Btu of input. In Table 11-2 are shown the water requirements
in gal/10 Btu, with no distinction made as to consumption between the
sites but with overall ranges given instead.
189
-------
Table 11-2. Net water consumed for Western coal sites
per million Btu of heating value in product,
Net Water Consumed
Facility (gal/10 Btu)
Lurgi 14-24
Synthane 32-36
Synthoil 15-19
Oil Shale 23
Slurry Pipeline 14
Electric Generation 43-54*
*gal/10 Btu of heating value of input coal.
As a very approximate finding, Table 11-2 would seem to show that
with the design procedures used in this study and with proper water
treatment design the Lurgi, Synthoil, oil shale and slurry pipeline water
requirements are roughly the same when expressed per unit of heating out-
put. The slurry pipeline requirement is at the lower end of the spread,
while oil shale is at the upper end. The Synthane facilities require
about.2 times more water and electric power generation at least 2.5 times
more, as measured in terms of the heating value of the input coal.
As shown in Table 11-1, for a given facility the quantity of solid
residuals is very site dependent. For each of the coal conversion
processes including electric generation, the largest variation between
sites is more than a factor of 4. This large variation occurs for all the
processes between Navajo/Farmington, New Mexico and Gillette, Wyoming
principally as a result of the relatively high ash content of the Navajo
coal compared to that at Gillette (and the other sites). A big fraction
190
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of the large quantity of residuals generated at Kaiparowits is coal
refuse, a consequence of the fact that the coal.is underground mined.
Outstripping all the coal conversion residuals by an order of magni-
tude are those from shale oil processing, where the primary residual
is the wet spent shale. Comparing the 100,000 bbl/day Synthoil and
TOSCO II oil shale facilities, the quantities of shale residuals are
from 8 to 33 times those from the coal conversion plants.
11.2 Site-SpecificWater Consumption and Residual Breakdowns
To clarify how the water is consumed and from where the residuals
arise, in Figs. 11-1 to 11-3 are shown breakdowns of the consumed water
by use and of the wet solid residuals by type. The breakdowns are given
in Fig. 11-1 for the production of 250 x 10 scf/day of synthetic natural
gas by the Lurgi and Synthane processes; in Fig. 11-2 for the production
of 100,000 bbl/day of synthetic fuel oil by the Synthoil process and
from oil shale by the TOSCO II process; and in Fig. 11-3 for the genera-
tion of 3,000 MWe of electricity by coal-fired steam generation. The
sites are those discussed throughout the study.
For clarity of graphical presentation, the five major water con-
sumption categories and their subcategories are combined into three
principal use groups: (1) process and flue gas desulfurization (FGD),
(2) cooling and (3) solids disposal, mining and other. Although in the
detailed analyses solids disposal is broken down into a large number
of categories, for simplicity of presentation they are here combined into
the following'main groups: (1) ash, (2) flue gas desulfurization (FGD)
sludge, (3) spent shale, (4) coal refuse and (5) other wastes. In the
graphs of Figs. 11-1 and 11-3, generally only two types of waste are
191
-------
250 X |06SCF/DAY
10 r
•SVNTHANE
6 -
2 -
LURGI
WATER (IOSACRE-FT/YR
SYNTHANE
SYNTHANE
DISPOSAL
MINING,
OTHER
SYNTHANE
LURGI
PROCESS (-)
—I/ a F60
BEULAH
COLSTRIP
GILLETTE
NAVAJQ
3r
WET SOLIDS (I06TONS/YR)
'ASH
V '
OTHER,
BEULAH
COLSTRIP
GILLETTE
NAVAJO
Fig. 11-1. Breakdown of net annual water consumption and
wet solid residuals generated in the production
of 250 x lO^ scf/stream day of synthetic
natural gas by the Lurgi and Synthane processes
at different Western sites.
192
-------
14 r
12
100,000 BBL/DAY
WATER (I03 ACRE-FT/YR}
OIL SHALE
MINING, DISPOSAL,
OTHER
WET SOLIDS (I06TONS/YR)
RIFLE
Breakdown of net annual water consumption and
wet solid residuals generated in the production
of 100,000 bbl/stream day of fuel oil by the
Synthoil process at different Western sites and
by the TOSCO II oil shale process at Rifle,
Colorado.
193
-------
3,000 MWe
16
WATER (!03ACRE-FT/YR )
DISPOSAL, MINING,OTHER
FGD
BEULAH
COLSTR1P
GILLETTE
KAIPAROWITS
NAVAJO
ASH
WET SOLiDS (I06TONS/YR)
FGO
SLUDGE
I J...I I
•ttf-
CC~
.
o:-
•-o.-.1
BEULAH
Fie. 11-3.
COLSTR1P
GILLETTE
KAIPAROWITS
NAVAJO
Breakdown of net annual water consumption and
wet solid residuals generated in the production
of 3,000 MWe/stream day of electricity by coal-
fired steam-electric generating plants at
different Western sites.
194
-------
indicated and in Fig. 11-2 only one type, because the contributions
of the remaining types are negligibly small on the scales of the
figures.
Process and flue Gas Desulfurizatioji (FGD) Water
The process water requirement relates to the fact that hydrogen
is needed for the fuel conversions, and its source is water. The
water consumed depends on the difference between the hydrogen to carbon
ratio in the coal or shale to this same ratio in the product fuel. A
second factor in determining net consumed process water is the moisture
present in the coal or shale, which is not treated as a water input but
which may be recovered in the process.
The consequence of these facts is evident in the findings that the
Synthane process water requirements are independent of site, amounting
to about 4.5 gal/10 Btu (1,087 acre-ft/yr). As noted, the coal moisture
could be recovered at a cost prior to its conversion, but this is an
economic question. The Synthane process makes maximum use of the
hydrogen in the coal in contrast to the Lurgi process. On the other
hand, the Lurgi process accepts wet coal and the coal moisture over-
shadows the process requirement, though the resulting dirty process
condensate must be treated at a cost. The Lurgi process water is found
to range between a net consumption of 3,6 gal/10 Btu (869 acre-ft/yr)
at Navajo, New Mexico to a net production of 3.1 gal/10 Btu (740 acre-ft/yr)
at Beulah, North Dakota. As we point out below, the Lurgi flue gas
desulfurization water also depends directly on the coal moisture, while
in the Synthane.process it does not because dry char is used in the
boilers. These results taken together explain the constancy of the
Synthane process and FGD water in Fig. 11-1 and the variability with site
of the corresponding Lurgi requirements.
195
-------
The crude oil product of the Synthoil plant has a hydrogen to
carbon ratio not much greater than that of the coal. As a result,
the process water is found to range from a net consumption of only
1.6 gal/10 Btu (1,021 acre-ft/yr) at Navajo, New Mexico to a net
production of 0.15 gal/10 Btu (95 acre-ft/yr) at Beulah, North Dakota.
This variation, illustrated in Fig. 11-2, is associated with variations
in the oxygen content of the coal. The principal loss of water is as
a consequence of water vapor released up the stack when light hydro-
carbons produced in the process are burnt. The process water require-
ment for the 100,000 bbl/day TOSCO II oil shale plant shown in Fig. 11-2
is about 7.3 gal/10 Btu (4,078 acre-ft/yr). This result is large and
cannot be compared directly with the Synthoil results because the
biggest part of the consumption includes water that is vaporized and
lost in wet scrubbing of the stack gases, in moisturizing the spent
shale and in removing sulfur in the upgrading process.
Process steam is generated in the Lurgi, Synthane and electric
power generating facilities with the concomitant generation of sulfur
dioxide in the combustion gases. The procedures considered for the
removal of the SC>2 before it is released to the stack are wet scrubbing
utilizing lime, limestone or both. In these procedures water leaves
the plant as vapor in the flue gas and in the slurry of spent solids.
By far the largest quantity of water leaves as saturated vapor in the
scrubbed flue gas and the amount is found to depend critically on the
flue gas temperature. In this study a temperature of 120°F was assumed,
but a variation of 10°F could give a 40% higher water quantity. This
is important since generally tight temperature control will be difficult
196
-------
to achieve. Apart from temperature, the largest single factor affecting
the water requirement is the moisture content of the coal fed to the
boilers. For example, at Beulah, North Dakota only 0.10 Ibs water/lb coal
is required compared to 0.44 Ibs water/lb coal at Navajo, New Mexico
and 0.7 Ibs water/lb char in the Synthane process. The water leaving
in the waste solids is proportional to the sulfur content in the coal
but is generally a small fraction of the total FGD requirement. The
exception to this is when a very wet North Dakota lignite is used and the
total flue gas makeup is so small that the slurry makeup becomes a sizable
fraction of the total.
Cooling Water
The largest quantity of water consumed in all facilities, except
oil shale, is the water evaporated for cooling. As is shown in Fig.
11-3, in electric power generation the cooling water dominates the total
requirement as it does to a somewhat lesser extent in the Synthoil
facilities (Fig. 11-2). Air cooling does exist as an alternative to
cooling by evaporation, and the quantity of water used for cooling is
dictated by economic considerations.
The process of converting coal or oil shale to another fuel or to
electricity is not, and cannot be 100% efficient. The product fuel or
electricity always has a lower heating value or energy content than the
coal or shale input. In the conversion of coal-to-electricity about 35%
of the energy in the feed coal leaves the plant as electricity. In the
Lurgi or Synthane coal-to-gas plants about 65-70% of the heating value
of the feed coal leaves the plant as gas plus by-products. In Synthoil
coal-to-oil plants about 70-75% of the heating value of the feed coal
197
-------
leaves the plant as fuel oil plus other products. In shale-to-oil plants
the efficiency is somewhat higher. For the same energy input, the most
important factor in determining the water required for cooling in two
different plants at the same site is overall plant efficiency. It is
for this reason that the water requirements for electrical generation
are high when compared to other processes.
Some of the heat which is not recovered in the product or by-products
may be dissipated by evaporating cooling water. Some of the unrecovered
heat cannot be used to evaporate water and leaves the plant in hot gases
up a flue, as water vapor from coal drying, as convective and radiant
losses from machinery and container surfaces, and in other direct ways.
About 25% of the unrecovered heat in all of the fuel-to-fuel and coal-to-
electricity plants is lost directly as described.
In the fuel-to-fuel conversion plants (Lurgi, Synthane, Synthoil
and oil shale) another 25-50% of the unrecovered heat is dissipated at
temperatures that are over 140°F in locations where wet evaporative
cooling is both wasteful of water and uneconomical. In these cases, air
or dry cooling should be practiced.
Whether or not to use wet evaporative cooling to dissipate the
remaining 25-50% of the unrecovered heat in the fuel-to-fuel plants and
the roughly 75% of the unrecovered heat in the electric generating
plants depends on the cost of water, buying water rights and transporting
the water to the plants, as well as the cost of treating the circulating
cooling water and disposing of the cooling tower residues. In the sites
of this study, these costs total in the range of from $0.40 to $2.00
per 1000 gallons of water evaporated. It is also found that to within
198
-------
about 5% at all the sites, 1500 Btu are dissipated per Ib of water
evaporated in the fuel-to-fuel plants, while 1400 Btu are dissipated
per Ib of water evaporated in the electric generating plants. This
translates into a range of $0.03 to $0.17 per 10 Btu of unrecovered
heat dissipated.
To save the water cost dry cooling must be used. However, when
cooling to low temperatures the capital cost of such cooling is high.
In addition, in all of the plants a large part of the unrecovered heat
is dissipated in the condensers of steam turbines used to drive gener-
ators, gas compressors and other machinery. The lower is the condenser
temperature, the less is the steam requirement for a constant shaft
power in a steam turbine. The result, therefore, is that dry cooling
also involves a fuel penalty, since it does not cool down to as low a
temperature as does wet cooling.
In the electric generating plants the most important point of loss
of unrecovered energy is in the turbine condensers. The heat lost in
these condensers is about 48% of the heating value of the feed coal and
about 75% of the unrecovered heat lost from the plant. The character-
istics of the turbines are such that the added capital cost of dry
cooling plus the fuel penalty dictate wet cooling, unless cooling water
costs about $4.63 per 1000 gallons evaporated. The water quantities
listed in this study are all based on wet cooled condensers.
At Navajo/Farmington, New Mexico a wet/dry tower calculation for
electric generation is carried out. It is shown that when water costs
about $2.20 per 1000 gallons, partial dry cooling is more economical than
all wet cooling. If a water cost of $2.20 per 1000 gallons of water is
199
-------
used at all the sites, then except for Gillette, Wyoming all evaporative
cooling systems would still be preferred if sufficient water is avail-
able. At Gillette the choice of an all evaporative cooling system is
marginal. However, a savings in total water consumed in the cooling
tower of about 75% of that required by all evaporative cooling is made
at the expense of only 50% of the difference in evaluated costs between
dry and all evaporative cooling.
In the Synthoil and Synthane plants wet cooling is used at all
sites for the steam turbine condensers, gas compressor interstage coolers
and selected final cooling of process streams. Depending on the site
and process, between 42 and 54% of the unrecovered heat is taken to be
dissipated by wet cooling. Cooling water requirements for the Lurgi plants
are taken from existing designs and are about 2/3 that for Synthane except
at Navajo, New Mexico where they are about 1/2. Wet/dry combination
cooling is not examined. Wet/dry cooling can reduce the cooling water
requirement to about 25% of that used and probably becomes economically
viable when cooling water costs $1 to $1.50 per 1000 gallons evaporated.
Thus at a site such as Gillette, Wyoming the stated cooling water require-
ments are certainly generous.
In Lurgi process plants, 28% of the unrecovered heat is assumed to
be dissipated by wet cooling at all sites. This number comes from
designs made for New Mexico and may be uneconomical, for example, in
North Dakota.
Water for Solids Disposal, Mining and Other Uses
All solid residuals that leave the plant boundaries generally do
so wet, and this water constitutes most of the water consumption associated
200
-------
with disposal. From the study findings, the weight of water as a
fraction of the total weight of wet solid residuals is found to vary
with site over the ranges indicated in Table 11-3.
Table 11-3. Weight of water as a percent of total
weight of wet solid residuals.
Water in Wet Solids
Facility (wt. %)
Lurgi 25-31
Synthane 22-29
Synthoii 24-25
Electric Generation 32-43
Oil Shale 13
As an approximate estimate we may say that the Lurgi, Synthane and
Synthoii facilities average a weight percent of water in the wet solids
in a range around 25%, with the Lurgi facility at the high end of the
range. This figure is simply related to the fact that the predominant
solid waste from these processes is ash, as ""illustrated in Figs. 11-1 and
11-2. The variation in range relates to the fraction of waste that is
bottom ash, fly ash or FGD sludge, since they each require somewhat
different quantities of water for disposal. The percent water in the wet
solids is in a range around 38% for electric power generation. This is
related to the fact that in most cases, except for the very high ash
Navajo coal, the FGD sludge represents about half the solid waste. The
other exception is at Kaiparowits where the largest fraction of the
solid waste is coal refuse from coal cleaning with a 30% weight of water.
201
-------
Both at Navajo and Kaiparowits the weight percent of water is at the
low end of the range. The 13 weight percent water for the TOSCO II
oil shale facility simply represents the weight percent water in the
spent shale, which constitutes essentially the entire solids disposal.
In surface mining the largest use of water is for dust control at
the mine, on the roads, in crushing and in handling. The exception to
this is when water is required for revegetation, which for the sites
examined is only necessary at Navajo/Farmington, New Mexico. In under-
ground mining, which is considered only for Kaiparowits, the largest
quantity of water is required for coal washing. The actual quantities
of water needed are quite site and process specific, depending on the
rate of coal mined and area stripped. Other losses include evaporative
losses which are, of course, site-specific. As a very rough rule, for
the Lurgi, Synthane and electric generation facilities in the graphs of
Figs. 11-1 to 11-3, the mining water at Navajo is about 65% of that for
solids disposal and other uses. At Gillette and Colstrip it is about
75% and at Beulah about 130%. The corresponding figures for the
Synthoil facilities are 50%, 60% and 90%. These percentages are quite
approximate and intended only to give some idea as to how the mining
and solids disposal categories break down in the summary graphs. The
oil shale mining and disposal use in Fig. 11-2 is split between
3 3
1.8 x 10 acre-ft/yr for mining and 4.1 x 10 acre-ft/yr for solids
disposal and other uses. At Kaiparowits, because of the coal cleaning
requirements, most of the water shown in Fig. 11-3 for disposal,
mining and other uses is actually for mining, into which category coal
washing is placed.
202
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Residuals
As shown in Fig. 11-2, by far the largest residual is the spent
shale generated in surface oil shale processing. The dry weight of
the spent shale is 82% of the originally mined shale and with the
moisturizing water it has a weight equal to 94% of the feed shale. Of
particular environmental importance in the TOSCO II process is that
the moisturizing water added to the spent shale leads to cementation
of the shale and freezing in of the water after compaction. Were this
not the case, severe leaching problems could ensue.
In the Synthane, Lurgi and Synthoil processes, ash is the principal
solid residual. The quantities of ash are very site-specific because
of the differences in coal heating values and ash content. The Navajo,
New Mexico coal with an ash content of 25.6% is a particularly high
ash coal, so that the quantities of wet-solid residuals at this site
are several times those from the other sites with the same facilities.
Particularly large quantities of solid wastes in electric power
generation are generated by flue gas desulfurization. The weight of
the resultant wet sludges ranges from 70-130% the weight of the wet
ash, except at Navajo/Farmington where it is 42%. Large quantities of
solid waste are also generated whenever it is necessary to clean the
coal, as is the case in the electric power generation facility at
Kaiparowits. The weight of wet coal refuse there is more than 3 times
the combined weight of the FGD and ash residuals.
Emphasis is placed here on the quantities of material to be disposed
of and not on their toxicity or hazardous character. In this regard
it is to be emphasized that although the residuals discussed are in
203
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general harmless, they nevertheless do contain trace quantities of
harmful elements and compounds. It is possible that the disposal
of the large quantities of residuals noted could lead to a collective
problem in the dispersion of the hazardous materials.
11.3 Regional Water Consumption and Residuals
Fig. 11-4 summarizes the study findings on the aggregated net
annual water consumption and wet solid residuals generated in the region
of the West in which energy development is focused. The three levels
of energy development are based on the Stanford Research Institute
energy model with low end-use demand, nominal end-use demand and low
nuclear availability.
For each level of energy development, it is found that the aggre-
gated net water consumption increases by a factor of 9-10 between the
years 1980 and 2000, while during the same period the wet solid residuals
increase by a factor of 75-100. This large increase in residuals beyond
1980 is associated with the spent shale from surface oil shale processing.
On the basis of the quantities of water consumed and residuals
generated, -Colorado appears to be the state most affected by energy
development in the Rocky Mountain Region. This is due principally to
the projected rapid growth of a surface processing oil shale industry.
Montana is the most affected state in the Powder River Region, princi-
pally because of the projected growth of slurry pipeline development and
electric power generation. The actual environmental impacts of siting
synthetic fuel and electric power generation facilities cannot, however,
be properly assessed without an appropriate determination of local and
regional water supply and demand data, and residual disposal methods.
204
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2600
2200
1800
1400
1000
600
200
WATER (I03ACRE-FT/YR)
320
240
160
80
LOW DEMAND
[ 1 NOMINAL DEMAND
LOW NUCLEAR
1980
1985
1990
WET SOLIDS (IO$TONS/YR)
SPENT SHALE .<-_
I
1980
Fig. 11-4.
1985
1990
2000
2000
1600
1200
800
400
2000
Regional net annual water consumption and wet
solid residuals generated in the Western coal and
oil shale areas between the years 1980 and 2000
for three levels of energy development.
205
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APPENDIX A. COAL ANALYSES
Coal analyses are required for carrying out the hydrogen
balances described in Section 2, for determining the solid resi-
duals in flue gas desulfurization, as described in Section 6,
for determining mine and process coal tonnage requirements
(Section 7), and for calculating the quantity of bottom and fly
ash to be disposed of (Section 8). The coal analyses are given
in Table A-l on a wet and dry basis for each of the six sites.
References
1. Michigan Wisconsin Pipe Line Co. and ANG Gasification Co.,
Application for Certificates of Public Convenience and
Necessity," Exhibit Z-6, p. 4, Federal Power Commission
Docket CP75-278, 1974.
2. Ibid.,p. 2.
3. Converted to dry basis from data given in Ref. 1.
4. "Trials of American Coals in a Lurgi Gasifier at Westfield,
Scotland," p. 55, Research and Development Report No. FE-105,
Energy Research and Development Administration, Washington,
B.C., November 1974.
5. Converted to dry basis from data given in Ref. 4.
6. SERNCO, "Applicants' Environmental Assessment for a Proposed
Gasification Project in Cambell and Converse Counties, Wyoming,
Prepared for Wyoming Coal Gas Co. and Rochelle Coal Co.,"
p. E-34, October 1974.
7. Converted to dry basis from data given in Ref. 6.
8. "Kaiparowits Project Final Environmental Impact Statement,"
Vol. I, p. 1-92, Bureau of Land Management, U.S. Department
of the Interior, Washington, B.C., March 3, 1976.
9. Converted to dry basis from data given in Ref. 8.
206
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10. Batelle Columbus Lab oratories, "Detailed Environmental Analysis
Concerning a Proposed Gasification Plant for Transwestern Coal
Gasification Co., Pacific Coal Gasification Co., Western Gasi-
fication Co., and ttie Expansion of a Strip Mine Operation Near
Burnham, New Mexico Owned and Operated by Utah International
Inc.," p. 3.11, Federal Power Commission, Feb. 1, 1973.
11. Approximation from data in El Paso Natural Gas Company, "Second
Supplement to Application for Certificate of Public Convenience
and Necessity," Section Z-2, p. II-C-1, Federal Power Commission
Docket CP73-131, 1973, to conform with proximate analysis.
12. A high volatile B b±tuminous coal as is appropriate to the region.
13. Hamshar, J.A., Terz±an, H.D., and Scotti, L.J., "Clean Fuels from
Coal by the COED Process," in Symp. Proceedings: Environmental
Aspects of Fuel Conversion Technology (May 1974, St. Louis, Mo.),
p. 174, EPA Technology Series Rept. No. EPA-650/2-74-118, Office
of Research and Development, Environmental Protection Agency,
Washington, D.C., October 1974.
14. Converted from dry basis from data given in Ref. 13.
207
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Table A-l, Coal analyses.
As received
Proximate Analysis, Wet Basis
Moisture, wt. %
Ash, wt, %
Volatile Matter, wt. %
Fixed Carbon, wt. %
Volatile Matter -f Fixed Carbon, wt. 7,
Total
Sulfur
Higher Heating Value, BTU/lb
Ultimate Analysis, Dry Basis
Carbon, wt. %
Hydrogen, wt. %
Nitrogen, wt. 7,
Sulfur, wt. %
Chloride, wt. %
Ash, wt. %
Oxygen by Difference, wt. %
Total
BEULAH,
NORTH DAKOTA
Ref. 1
35.98
7.42
56.6
100.0
0.71
6,822 2
Ref. 3
63.17
4.25
1.27
1.11
0.02
11.59
18.59
100.0
COLSTRIP,
MONTANA
Ref. 4
24.70
9.73
29.20
36,37
100.0
1.16
8,611
Ref. 5
67.15
4.22
1.20
1.45
0.04
12.92
13.02
100.0
GILLETTE,
WYOMING
Ref. 6
28.0
5.6
32.7
33.7
100.0
0.32
8,449
Ref. 7
68.63
4.70
0.69
0.45
0.04
7.75
17.74
100.0
KAIPAROWITS/
ESCALANTE,
UTAH
Ref, 8
14.8
7.0
36.0
42.2
100.0
0.42
10,800
Ref. 9
72.24
5.08
1.15
0.49
0.02
8.22
12.80
100.0
NAVAJO/
FARMINGTON ,
NEW MEXICO
Ref. 10
12.4
25.6
28.2
33.8
100.0
0.91
8,310
Ref. 11
53.97
3.95
0.89
1.04
29.22
10.93
100.0
RIFLE, 1?
COLORADO
Ref. 13
6.4
6.0
39.0
48.6
100.0
13,010
Ref. 14
75.8
5.8
1.7
0.6
0.004
6.4
9.7
100.0
o
00
-------
APPENDIX B. WATER ANALYSES AND PRECIPITATION
AND EVAPORATION RATES
Feed water analyses are required to determine the solid
residuals found in the blowdown of process water treatment
plants and cooling towers and the need for settling basins.
Table B-l shows the source of feed water for each of the plant-
site combinations considered in the assessment. Table B-2 gives
the quality of each of the source waters. Unless otherwise indi-
cated, the analyses have been supplied to us by the Radian Cor-
*
poration, Austin, Texas.
Precipitation and evaporation data at each of the six sites
are presented in Table B-3. These data have been used to estimate
the water requirements for dust control on the mine area and haul
roads (Section 7.3), supplemental irrigation water required for
revegetation (Section 7.8), and the evaporation losses from settling
basins (Section 8.8) and reservoirs (Section 8.9).
References
1. "Environmental Impact Report, North Dakota Gasification Project,"
for ANG Coal Gasification Co., p. 2-244, FPC Docket No. CP75-278,
Vol. Ill, March 5, 1975.
2. Data is weighted average for Bighorn River at Bighorn,Montana
(Yellowstone River Basin near Colstrip) from "Quality of- Surface
Waters of the United States, 1968, Part 6: Missouri River Basin,"
p. 125, Geological Survey Water-Supply Paper 2098, 1973. Average
based otiyearly discharge and load.
Sethness, E.D., private communication.
209
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3. Ibid., p. 65. For Bluewater Creek at Fromberg, Montana based
on yearly discharge and load.
4. Ibid., p. 158. For North Platte River at Orin, Wyoming. Time
weighted average over year.
5. Weighted average data for Colorado River at Lees Ferry, Arizona
taken from "Quality of Surface Waters of the United States, 1968,
Parts 9 and 10: Colorado River Basin and the Great Basin," p.
156, Geological Survey Water-Supply Paper 2098, 1973.
6. Ibid., p. 157. Lower value most probable. Upper value time
averaged.
7. Data is averaged for San Juan River at Farmington, New Mexico
from U.S. Geological Survey, Water Supply Papers No.2015 (1967),
2098 (1968), and 2148 (1969).
8. Data for Colorado River above Grand Valley from "An Environ-
mental Impact Analysis for a Shale Oil Complex at Parachute
Creek, Colorado, Part I: Plant Complex and Service Corridor,"
Table 7, p. 43, Colmy Development Operation, Atlantic Rich-
field Co., Denver, 1974.
9. Ibid, Appendix 12 (Chemical Water Quality Characteristics of
Parachute Creek, p. 29). Straight average of raw data.
10. For Colorado River near Cisco, Utah based on yearly discharge
and load. "Quality of Surface Waters of the United States,
1968, Parts 9 and 10: Colorado River Basin and the Great Basin,"
p. 48, Geological Survey Water-Supply Paper 2098, 1973.
11. According to Weeks, et al., "Simulated Effects of Oil Shale
Development on the Hydrology of Piceance Basin, Colorado,"
U.S. Geological Survey Professional Paper 908, 1974, only
tract C-b could supply sufficient ground water from the mine
to meet development plans. In this case, 2/3 of discharge
is from upper aquifer and 1/3 from lower aquifer. Data
given represents 2/3 - 1/3 weighting of mean from upper and
lower aquifers as given in Table 6, p. 35 of cited reference.
12. Geraghty, J.H. et al., Water Atlas of the United States, Plate
12, Water Information Center, Inc., Port Washington, New York,
1973.
13. Climates of the States, Vol. II - Western States, p. 757,
Water Information Center, Inc., Port Washington, N.Y., 1973.
210
-------
Table B-l. Source of feed water.
PROCESS
SLURRY PIPELINE
LURGI GAS
SYNTHANE GAS
SYNTHOIL GAS
ELECTRICAL GENERATION
3000 MWe
1000 MWe
OIL SHALE
50,000 bbl/day
100,000 bbl/day
BEULAH,
NORTH DAKOTA
Lake
Sakakawea
Lake
Sakakawea
Lake
Sakakawea
Lake
Sakakawea
COLSTRIP ,
MONTANA
Yellowstone
River
Yellowstone
River
Yellowstone
River
Yellowstone
River
GILLETTE,
WYOMING
North Placte
River
Yellowstone
River
Yellowstone
River
North Platte
River
Yellowstone
River
KA1PAROWITS/
ESCALANTE,
UTAH
Lake
Powell
NAVAJO/
FARMINGTON,
NEW MEXICO
San Juan
River
San Juan
River
San Juan
River
San Juan
River
RIFLE,
COLORADO
White
River
Colorado
River
Groundwater
-------
Table B-2. Source water quality.
Dissolved Calcium
(mg/£ as CaCOj)
Dissolved Magnesium
(og/£ as CaCOj)
Dissolved Sodium
(rng/i as CaCOj)
Dissolved Chloride
(mg/i as CaCOj)
Dissolved Bicarbonate
(mg/Z. as CaCOj)
Dissolved Sulfate
(mg/i as CaCOj)
Dissolved Silica
Total Dissolved Solids
(n.g/1)
Suspended Sediment (mg/i)
Hardness (mg/£ as CaCOj)
pH Units
BEULAH,
NORTH DAKOTA
Lake
Sakakawea
123
78
•129
13
148
177
7
428
21
201
8.1
COLSTRIP,
MONTANA
Yellowstone
River
99
56
75
8
113
113
10
284
365 2
155
8.2
GILLETTE,
WYOMING
Yellowstone
River
115
66
98
10
131
148
12
364
371 3
181
7.7
GILLETTE,
WYOMING
North Platte
River
153
82
109
17
139
197
10
414
320 4
235
8.2
KAIPAROWITS/
ESCALANTE,
UTAH
Lake
Powell
213
122
205
99
149
292
105
677
5-15 6
335
7.6.
KAVAJO/
FASMINGTON,
NEW MEXICO
San Juan
River
138
37
68
12
117
118
12 7
300
278
175
7.8
RIFLE,
COLORADO
White
River
99
35
19
13
93
47
10
181
663
134
8.0
RIFLE,
COLORADO
Colorado
River
158
53
205
168
118
134
12 9
454
2087 10
211
8.0
RIFLE,
COLORADO
Cround-
Wacer
115
41
3198
666
2788
250
3773
156
-------
Table B-3. Precipitation and evaporation data (inches/year).
Precipitation
Lake Evaporation Rate
(70% Pan)
Pond Evaporation Rate
(90%^ Pan)
Pan Evaporation Rate
BEULAH,
NORTH DAKOTA
15 I
3512
45
50
COLSTRIP ,
MONTANA
14 13
38 12
49
54
GILLETTE,
WYOMING
14 14
42 14
54
60
KAIPAROWITS"/
ESCALANTE,
UTAH
g15
54 12
69
77
NAVAJO/
FARMINGTON,
NEW MEXICO
816
47.5 12
61
68
RIFLE,
COLORADO
12 17
35 12
45
50
-------
APPENDIX C. LOAD FACTORS
A load factor for a plant is defined as the percentage of time
that a plant is on-stream throughout the year. The load factor for
each of the unit size mine-plant complexes is given in Table C-l.
Throughout this report rate quantities are specified based on either
a "stream" time unit or a "calendar" time unit; for example, gallons
per stream minute or gallons per calendar minute. The ratio of a
calendar time to a stream time is the load factor. For example, for
a plant having a load factor of 90%, 10 gallons per stream minute =
9 gallons per calendar minute. All rate quantities based on a cal-
endar time unit can be converted to a yearly basis by multiplying
the quantity by 365 days, or 365 x 24 = 8760 hours, or 365 x 24 x 60
= 525,600 minutes. For example, 10 gallons per calendar minute =
5,256,000 gallons per year. The year as a time unit is a calendar
time unit.
Reference
1. Raye, T.D., Memorandum to J. White, Radian Corporation, Austin,
Texas, April 26, 1976.
215
-------
Table C-l. Load factors.
Load Factor
Slurry Pipeline 100%
Lurgi 90%
Synthane 90%
Synthoil 90%
Steam-Electric Generation 70%
Oil Shale 90%
216
-------
APPENDIX D. TOTAL WATER CONSUMED AND RESIDUALS
GENERATED FOR THREE ENERGY SCENARIOS
BY STATE AND COUNTY
Reference 1 establishes the temporal and spatial regional sce-
narios for levels of western energy development used in this assess-
ment. The scenarios are based on the Stanford Research Institute
energy model with nominal end-use demand, low end-use demand, and
low nuclear availability cases. The regional scenarios focus on
the Powder River Region, which includes the states of Montana, North
Dakota, and Wyoming; and the Rocky Mountain Region, which includes
the states of Colorado, New Mexico, and Utah. Further disaggregation
of regional facilities to Counties within the States was performed on
the basis of published resources. For each level of western energy
development and for each region, the time frames considered are the
years 1980, 1985, 1990, and 2000. The total water consumed and
residuals generated by State and County are presented in this appendix.
The results of the regional scenarios are based on the results
of the site-specific scenario calculations presented in Section 10.
The total water consumed and residuals generated for each plant-County
combination given in Ref. 1 were the same as for one of the (site -
specific) plant-site combinations considered in Section 10. A plant-
County combination was matched to a plant-site combination on the
basis of coal type, water source, and climate. We found the base
quantities to be the same for all Counties considered within a given
217
-------
State. Table D-l shows the base quantities used to calculate the
total water consumed and wet-solids residuals generated by State
for the unit size mine-plant complexes shown in the table.
Table D-2 shows the page number on which the results for
specific scenarios are presented in this appendix.
Reference
1. Conine, W.D., "Regional Scenario Definitions for Levels of
Western Energy Development Corresponding to Nominal Demand
Low Demand, and Nuclear Moratorium Assumptions," Radian Cor-
poration, Report No. 100-090-07-01, Austin, Texas, June 22
JL./ / O »
21-8
-------
Table D-l. Base quantities ass
-------
Table D-2. Location of results for specific scenarios by
region, energy demand, and year.
Nominal Demand
1980
1985
1990
2000
Low Demand
1980
1985
1990
2000
Low Nuclear
Availability
1980
1985
1990
2000
Page Number
Rocky Mountain
Region
221
222
223
224
225
226
227
228
229
230
231
232
Powder River
Region
233
234
235
236
237
238
239
240.
241
242
243
244
220
-------
CASE
NOMINAL DEMAND
FACILITIES SITED It! ROCKY MOUNTAINS REGION BY 1980 (AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Gar fie Id
TOTAL
NEW MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAL
UTAH
Garfield
Kane
Uintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*
WET SOLIDS'
106 TON/YR
LURGI GAS
ACRli-
FT/YR*
WET SOLIDS*
106 TON/YR
SYNTHAI..: GAS
ACKE-
FT/YR*
WET SOLIDSt
106 TON/YR
SYNTHOIL
ACRE-
FT/YR*
WET SOLIDSt
106 TON/YR
ELECTRICAL GENERATION
ACRE-
FT/YR*
29,206
29,206
29,816
29,816
WET- SOLIDSt
106 TON/YR
5.00
5.00
5.30
5.30
OIL SHALE
ACRli-
PT/YR*
WET SOLIDS"
106 TON/YR
to
* Water Censured
t Residuals
-------
NOMINAL DEMAND
FACILITIES SITED IN ROCKY MOUNTAINS REGION BY 1985 (AFTER 197i
STATS/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
NEW MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAL
UTAH
Garfield
Kane
Uintah
TOTAI.
SLURRY PIPELINE
ACRE-
FT/YR*
19,171
19,171
«ET SOLIDS1'
106 TON/YR
_
-
LURGI GAS
ACRE-
FTAR*
WET SOLIDSt
106 TON/YR
SYNTHAIT: GAS
ACRE-
PT/YR*
rfET SOLIDSt
106 TON/YR
SYNTHOIL
ACRE-
FT/YR*
WET SOLIDSt
106 TON/YR
ELECTRICAL GENERATION
ACRE-
FT/YR*
28,482
28,482
29,206
29,206
29,816
29j8l6
MET SOLIDSt
106 TON/YR
1.14
1,14
5.00
S.OO
5.30
5.30
OIL SHALE
ACRE-
PT/YR*
25,848
25,848
VET SOLIDST
106 TOH/YR
81.62
81.62
* Kator Consumed
t Residuals
-------
NOMINAL DEMAND
FACILITIES SITED IN ROCKY MOUNTAINS REGION By
(AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
NEW MEXICO
San Juan
Lea
Poosevelt
Cftavos
Eddy
TOTAL
UTAH
CarfUld
Kane
Uintah
TOTAL
SLURM PIPELINE
ACRE-
FT/YR*
19,171
19,171
WET SOLIDS1'
106 TONAR
-
-
EORGI GAS
ACRE-
PT/YR*
WET SOLIDSt
106 TON/YR
SYNTHA..E GAS
ACRE-
FT/YR*
MET SOLIDSt
106 TON/VR
SYHTHOII.
ACRE-
FT/YR*
WET SOLIDSt
106 TON/lfR
ELECTRICAL GENERATION
ACRE-
FT/YR*
28,482
28,482
29,206
29,206
29 , 816
29,816
59,632
MET SOLIDSt
10* TON/YR
1.14
1.14
5.00
5.00
5.30
5.30
10.60
OIL SBRLE
ACKE-
FT/YR*
51,696
12,924
64,620
WET SOLIDS'?
106 TOM/XR
163.24
40.83
204.05
* Water Consumed
t Residuals
-------
CASE
NOMINAL DEMAND
FACILITIES SITED IN ROCKY MOUNTAINS REGION BY 2000 (AFTER 1975}
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
NEW MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAL
UTAH
Garfield
Kane
Dintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*
19,171
19,171
WET SOLIDS'
106 TON/YR
-
-
LURGI GAS
ACRE-
FT/YR*
5,639
5,639
WET SOLIDSt
106 TON/YR
3.00
3.00
SYNTHAiffi GAS
ACRE-
FT/YR*
8,670
8,670
WET SOLIDS*
106 TON/YR
2.84
2.84
SYNTHOIL
ACRB-
PT/YR*
WET SOLIDST
106 TON/YR
ELECTRICAL GENERATION
ACRE-
FTAR*
28,482
28,482
29,206
29,206
29,816
29,816
59,632
WET SOLIDSt
106 TON/YR
1.14
1.14
5.00
5.00
5.30
5.30
10.60
OIL SHALE
ACRE-
FT/YR*
336,024
155,088
491,112
51,696
51,696
-------
CASE
FACILITIES SITED IN FQCKY MOUNTAINS REGION BY 198° (AFTER I97S)
STATE/COOHTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Gar fie Id
TOTAL
t!EW KEXIOO
San Juan
Lea
Boose velt
Chaves
Eddy
TOTAL
OTAH
Garfield
Kane
Uintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*
WET SOLIDS'
106 TON/YR
LUR6I GAS
ACRE-
FTAR*
WET SOLIDSt
106 TON/YR
SYNTIIAT:E GAS
ACRE-
FTAR*
WET SOLIDSt
106 TON/YR
SYNTHOIl
ACRE-
PT/YR*
WET SOLIDSt
106 TON/YR
ELECTRICAL GENERATION
ACRE-
PT/YR*
29,816
29,816
WET SOLIDSt
ZO6 TON/YR
5.30
5.30
OIL SHALE
ACRE-
PT/YR*
»CT SOLI^St
106 TON/YR
to
K>
Ul
* Water Consuned
t Residuals
-------
CASE LOW DEMASP,
FACILITIES SITED IN BOCKY MOUNTAINS REGION BY 1985 (AFTER 1975}
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
HSW MEXICO
San Juan
Lea
Koosevelt
Chaves
Eddy
TOTAL
• UTAH
Garfield
Kane
Uintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*
19,171
19,171
WET SOLIDS1'
106 TON/YR
-
-
LURCI GAS
ACRE-
FTAR*
WET SOLIDSt
106 TON/YR
SYNTHAi:; GAS
ACRE-
FT/YR*
WET SOLIDSt
106 TON/YR
SYNTHOIL
ACRE-
FTAR*
WET SOLIDS'^
106 TON/YR
ELECTRICAL GENERATION
ACRE-
FT/YR*
29,206
29,206
29,816
29,816
WET SOLIDSt
106 TON/YR
5.00
5.00
5.30-
5.30
OIL SHALE
ACRE-
FT/YR*
25,848
25,848
VET SOLI!3at
O6 TOM/YR
81.62
81.62
* Hater Consused
t Residuals
-------
CASE
LOW DEMAND
FACILITIES SITED IN ROCKY MOUNTAINS REGION BY 199° (AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
NEW MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAL
UTAH
Cat-field
Kane
Uintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*
19,171
19,171
rfET SOLIDS'-'
106 TON/YR
-
-
LURGI GAS
ACRE-
FT/YR*
WET SOLIDSt
106 TON/YR
SYNTIiATIE GAS
ACRE-
FT/YR*
WET SOLIDSt
106 TON/YR
SYNTHOIL
ACRE-
FT/YR*
WET SOLIDSt
106 TON/YR
ELECTRICAL GENERATION
• ACRE-
FT/YR*
29,206
29,206
29,816
29,816
WET SOLIDSt
106 TON/YR
5.00
5.00
5.30
5.30
OIL SHM-S
ACRE-
FT/YR*
51,696
12,924
64,620
«£" SOLIBST
106 TON/YR
163,24
40.81
204.05
to
S3
* Kater Consumed
t Residuals
-------
CASE LOW
FACILITIES SITED IN' ROCK! MOUNTAINS REGION BY
2000
(AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huecfano
Rio Blanco
Gar fie Id
TOTAL
NEW MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAt.
UTAH
Garfield
Kane
Uir.tah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*
19,171
19,171
rfET SOLIDS'5'
106 TON/YR
-
-
LURGI GAS
ACRE-
FTAR*
5,639
5.639
WET SOLIDSt
106 TON/YR
3.00
3.00
SYNTMME GftS
ACRE-
FT/YR*
WET SOLIDSt
106 TON/YR
SYNTHOIL
ACRE-
FT/YR*
WET SOIJDST
106 TON/YR
ELECTRICAL GENERATION
ACRE-
FT/YR*
29,206
29,206
29,816
29 , 816
iET SOLIDSt
106 TON/YR
5.00
5.00
5.30
5.30
OIL SHALE
ACKE-
FT/YR*
271,404
142,164
413,568
38,772
38,772
VET SOLICST
106 TON/YR
857.01
448.91
1,305.92
122.43
122.43
CO
* Water Constimed
t Residuals
-------
CASE LOW HUCLEAR AVAILABILITY
FACILITIES SITED IS SOCKY KOUHTAINS REGION BY . 1-980 {AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
HSU MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAL
UTAH
Garfield
Kane
Uintah
TOTAL
SLURRY
ACRE"
FT/YR*
PIPELINE
HET SOLIDS*
106 TON/YR
LURGI GAS
ACRE-
FT/VR*
WET SOLIDgt
106 TON/YR
SYNTHAME GAS
ACEE-
FT/YR*
WET EOLIDSt
106 TON/YR
SYNTHOIL
ACRE-
FT/YR*
WET SOLIDSt
106 TONAR
ELECTRICAI. GENERATION
ACRE-
FT/YR*
29,206
29,206
29,816
29,816
WET SOLIDSt
106 TON'/YR
5.00
S.OO
5.30
5.30
OIL SHALE
AC8E-
PT/YR*
WET SOI.ID5T
106 TON/YR
NJ
VO
* Katcr Consuaed
t Reiiduals
-------
CASE LOW NUCLEAR AVAILABILITY
FACILITIES SITED IN ROCKY MOUNTAINS REGION BY 3.985 (AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Hucrfano
Rio Blanco
Garfield
TOTAL
NEK MEXICO
San Juan
Lea
Soosevelt
Chaves
Eddy
TOTAL
UTAH
Garfieid
Kane
Ointsh
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*
19,171
19,171
WET SOLIDS7
106 TONAR
_
„
LURGI GAS
ACRE-
FTAR*
WET SOLIDSt
106 TON/YR
SYN-MAI.3 GAS
ACRE-
PT/YR*
VJET SOLIDSt
106 TON/YR
I
SyNTHOIt
ACHE-
FT/YR*
•)ET SOLIDS+
106 TON/YR
ELECTRICAL GENERATION
ACRE-
FT/YR*
28,482
28,482
58,412
58,412
29,816
29,816
59,632
VET SOLIDSt
O6 TON/YR
1.14
1.14
10.00
10.00
5.30
5.30
10.60
OIL SHALE
ACRE-
FT/YR*
25,848
25,848
vET SOLIDST
106 TOM/YR
81.62
81.62
ro
w
o
* Water Consumed
t Residuals
-------
CASE tOW NUCLEAR AVAILABILITY
FACILITIES SITED IN ROCK* MOUNTAINS REGION BY 1990 (AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
NEW MEXICO
San Juan
Lea
Koosevelt
Chaves
Eddy
TOTAL
UTAH
Garfield
Kane
Uintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*
19,171
19,171
WET SOLIDS'^
106 TON/YR
-
-
LURGI GAS
ACRE-
FT/YR*
WET SOLtDSt
106 TON/YR
SYNTHA"E GAS
ACRE-
FTAR*
WET SOLIDSt
106 TON/YR
SYNTHOIL
ACRE-
FT/YR*
WET SOLIDSt
106 TONAR
ELECTRICAL GENERATION
ACRE-
FTAR*
28,482
28,482
58,412
58,412
59,632
29,816
89,448
WET SOLIDSt
106 TON/YR
1.14
1.14
10.00
10.00
10.60
5.30
15.90
OIL SHALE
ACRE-
FT/YR*
51,696
51,696
WET SOLIDST
106 TON/YR
163.24
163.24
* Water Consumed
t Residuals
-------
CASE'
NUCLEAR AVAILABILITY
FACILITIES SITED IN ROCKY MOUNTAINS REGION DY 200° (AFTER 1975)
STATE/COUNTY
ARIZONA
COLORADO
Huerfano
Rio Blanco
Garfield
TOTAL
NEW MEXICO
San Juan
Lea
Roosevelt
Chaves
Eddy
TOTAL
UTAH
Garfield
Kane
Uintah
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*
38,342
38,342
VET SOLIDS*
106 TON/YR
-
-
LURGI GAS
ACKE-
FTAR*
5,639
5,639
WET SOLIDSt
106 TON/YR
3.00
3.00
SYNTllANi! GAS
ACRE-
PT/YR*
8,670
8,670
«IET SOLIDSt
106 TON/YR
2.84
2.84
SYNTHOIL
ACRE-
FTAR*
WET. SOLIDS*
10S TON/YR
ELECTRICAL GENERATION
ACRE-
FT/YR*
28,482
28,482
56,964
87,618
87,618
59,632
59,632
119,264
ET S'OLIDSt
O6 TON/YR
1.14
1.14
2.28
15.00
15.00
10.60
10.60
21.20
OIL SHALE
ACBE-
FT/YR*
323,100
155,088
478,188
51,696
51,696
ET SOLIDST
O6 TOM/YR
1,020.25
489.72
1,509,97
163.24
163.24
N>
to
IS5
" Hater Consumed
t Residuals
-------
NOMINAL DEMAND
FACILITIES SITED IN POWDER RIVER REGION BX 1980 (AFTER 1975)
STATE/COONTY
MONTANA
Povdcr River
Big Horn
Rosebud
Custer
Wlbaux
Richland
Mccone
TOTAL.
NORTH DAKOTA
Billings
Bovoian
Dunn
Hettinger
KcKenzie
Mctean
Mercer
Morton
Oliver
Slope
Stark
Ward
William
TOTAL
WYOMING
Caccbell
Johnson
Sheridan
TOTAL
SLURRY PIPELINE
ACRE-
FTAR*
19,171
19,171
WET SOLIDS'
106 TONAR
-
-
LOSS! GAS
ACRE-
FTAR*
WET SOLIDS T
106 TON/YR
SYNTHA..E GAS
ACRE-
PTAR*
WET SOLIDSt
106 TONAR
sin
ACRE-
PTAR
THOII,
HET SOLIDS"
106 TONAR
.EUrVTRIC'A • f;rai~UATTf»i
ACRE-
FTAR*
26,659
26,659
53,318
23,884
23,884
47,768
25,842
25,842
HET SOLIDS'
106 TON'AR
3.01
3.01
6.02
2.65
2.65
5.30
1.32
1.32
SI!i W1&
ACRE-
FTAR*
TOT SOLIDS7
io5 TO^AR
to
w
OJ
* Hater Consumed
t Residuals
-------
CASE MflHTHflT.
FACILITIES SITED IN POWDER RIVER REGION BY 1985 (AFTER 1975)
STATE/COUNT*
MONTANA
Powder River
Big Horn
Rosebud
Cuscer
wibaux
Richland
XcCone
TOTAL
HORTH DAKOTA
Billings
Bowman
Dunn
Hettinger
KcXenzie
X=Loan
Kcreer
Korton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Campbell
Johnson
Sheridan
TOTAL
ST.URRY PTPftLINK
ACRE-
fT/YR*
19,1'1
19,171
19,171
57,513
19,171
19,171
WET SOLIDS'
106 TOH/VR
_
"
-
•1
-
-
LURCI GAS
ACRE-
FT/YR*
HET SOLIDST
106 TOH/YR
pYNTHAKfi GAS
ACRE-
FT/YR*
WET SOLIDSt
106 fON/YR
SYN
ACRE-
FTAR*
HOIt,
WET SOLIDS1
O6 TON/YR
F,y,F,erttjc;!^
ACRS-
FT/YR*
53,318
26,659
26,659
106,636
23,884
23,884
23,884
23,884
23,884
119,420
51,684
51,684
fif-NFUHTTON
i*ET SOLIDST
O6 TON/YR
6.02
3.01
3.01
12.04
2.65
2.65
2.65
2.65
2.65
13.25
2.64
2.64
cvn, (ME
ACRE-
PT/YR*
CT SOLIDS'
O5 TOS/YR
to
OJ
* Water Consumed
t Residuals
-------
CASE HOHINAL DEMAND
FACILITIES SITED IN POWDER RIVER REGION BY 1990 (AFTER 1975)
STATE/COUNTY
MONTANA
Povder Rivet
Big Horn
Rosebud
Custer
Kibaux
Richland
KcCone
T07AL
NORTH SAKOTft
Billings
Bovsar.
E'jnn.
Hettinger
McKenzie
McLean
Kercar
Morton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Campbell
Johnson
Sheridan
TOTAL
SLURRY PIPET.INK
ACRE-
FT/YR*
38,342
19,171
19,171
76,684
38,342
38,342
WET SOLIDST
106 TON/YR
-
_
_
--
-
-
LURCt CAS
ACRE-
FT/YR*
4,618
4,618
3,307
3,307
6,614
WET SOLIDST
106 TON/YR
1.27
1.27
1.20
1.20
2.40
SYNTH \K~ GAS
ACRB-
FTAR*
WET SOLIDSt
106 TON/YR
SY
ACRE-
FT/YR*
THOU,
WET SOLI OS 1
106 TON/YR
EIiEWICft r,t^ii?R»TTO'i
ACR£-
FT/YR*
53,318
53,318
26,659
133,295
23,884
23,884
23,884
23,884
23,884
23,864
143, 304
51,684
51,684
WET SOLIDS7
106 TON/YR
6.02
6.02
3.01
15.05
2.65
2.65
2.65
2.65
2.65
2.65
15.90
2.64
2.64
"IL S1'-'**.1"
ACBE-
FT/YR*
WET SOLZ3S '
1C6 TON/YR
CO
u>
Ul
• Water Consumed
t Residuals
-------
CASE
FACILITIES SITED IN POWDER RIVER REGION BY 2000 (AFTER i97S)
STATE/COUNTY
MONTANA
Powder River
Big Hfejrn
Rosebud
Duster
ttibaux
Rithland
TOTAL
NORTH DAKOTA
Billings
Bowman
Dunn
Hettinger
McKenzie
KcLaan
Kercer
Morton
Oliver
Slope
Stark
Ward
William
TOTAL
WYOMING
CaajiBell
Johnson
Sheridan
TOTAL
' SLURRY
biCRE-
VT/YR*
76,684
76,684
57.513
210,881
76,684
19,171
19,171
115,026
PIPELINE
WET SOLIDS1"
106 TON/YR
_
-
_
-•
-
-
-
-
T.DWT GAS
ACRE-
FTAR*
18,472
13,854
13,854
46..J80
3,307
3,307
6,614
3,307
3,307
6,614
6,614
3,307
6,614
3,307
46,298
16,824
4,206
4,206
25,236
WET SOLIDS!
106 TONAR
5.08
3.81
3.81
12.70 -
1.20
1.20
2.40
1.20
1.20
2.40
2.40
1.20
2.40
1.20
16.80
2.88
0.72
0.72
4.32
SYNTKAN,-: GAS
ACRE-
IS, 616
15,616
7,808
39,040
7,671
7,671
15,342
15,342
7,671
53,697
13,552
7,776
23,328
WET SOUDSt
106 TON/YR
2.24
2.24
1.12
5.60
1.08
1.08
2.16
2.16
1.08
7.56
1.42
0.71
2.13
SYN
ACRE-
FTAR*
5,148
5,148
10,085
10.085
THOU.
«3T SOLIDSl
1O6 'TON/YR
1.04
1.04
2.00
2,00
ET.ErTRJfCM GSNEHATTONI
ACRE-
FTAR*
53,318
53,318
53,318
159,954
23,884
47,768
23,884
47,768
47,768
23,884
214,956
51,684
25,841
77,525
•ET SOLIDS1'
O6 TON/YR
6.02
6.02
6.02
18.06
2.65
5.30
2.65
S.30
5.30
2.65
23.85
2.64
1.32
3.96
OT, ,SM F
ACBE-
FT/YR*
JET SOLIDS7
ro
CO
CTi
* Water Consuracd
t Residuals
-------
T.flU nFHAND
FACILITIES SITED IN POWDER RIVER REGION BY 1980 (AFTER 1975)
STATE/COUSTY
MONTANA
Powder River
Big Horn
Rosebud
Ouster
Wibaux
Richland
HcConc
TOTAL
NORTH DAKOTA
Billings
Bowman
Dunn
Hettinger
McKenzie
KcLoan
Kerccr
Xorton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Campbell
Johnson-
Sheridan
TOTAL
SLURRY PIPELINE
ACRE-
FT/YR*
19,171
19,171
WET SOLIDST
106 TONAR
-
-
LtlRGT GAS
ACRE-
FT/YR*
WET SOLIDS T
10^ TON/YR
SYHT--AI-? GAS
ACRE-
FT/YR
WET soLiost
106 TONAR
SY
ACRE-
FT/YR*
WET SOLIDSt
106 TON/YR
rrpTTBT^
ACSE-
FT/YR*
26,659
26,659
23,884
23,884
47,768
25,842
25,842
r CEMFRATOBl
WET SOLIDST
106 TONAR
3.01
3.01
2.65
2.65
5.30
1.32
1.32
nrr CPJ^
ACRE-
ET/YR*
WET SOLIDS'
106 TO.\'/yR
IsJ
CO
* Water consumed
t Residuals
-------
CASE LOW DEMAND
FACILITIES SITED IS POWDER RIVER REGION BY 1985 (AFTER 1975)
STATE/COUNTY
MONTANA
Powder River
Big Horn
Rosebud
Custer
Wibaux
Richland
KcCor.c
TOTAL
NORTH DAKOTA
Billings
Bo-ir-an
Dunn
Hettimjer
KcXenzie
McLean
Mercer
Xorton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Caspbell
Johnson
Sheridan
TOTAL
SLtiPRY PTPEI.TNK
ACRE-
FT/YR*
19,171
19,171
38,342
19,171
19,171
WET SOLIDS1"
106 TON/YR
_
_
-
-
-
LURGT CAS
ACRE-
FT/YR*
WET SOLIDST
106 TON/YR
SYNTIIANii GAS
ACRE-
FT/YR*
WET SOLIDSt
106 TON/YR
SYN
ACRE-
PT/YR*
TIIOTT,
SffiT SOLIDSt
106 TON/YR
!f!,.»:(7TpT^AT RFNFHATTON
ACRE-
FT/YR*
26,659
26,659
26,659
79,977
23,884
23,884
23,884
23,884
95,536
51,684
51,684
WEf SOLIDS7
106 TON/YR
3.01
3.01
3.01
9.03
2.65
2.65
2.65
2.65
10.60
2.64
2.64
OIIl 5HAT.T
ACRE-
FT/YR*
HEX SOLIDS'
106 TON/YR
t"J
u>
00
* Water Consumed
t Residuals
-------
CASE LOW DEMAND
FACILITIES SITED IN POWDER RIVER REGION BY 1990 (AFTER 1975)
STATE/COUNTY
MONTANA
Powder River
Big Horn
Rosebud
Custer
Wiba-JX
Richland
McCone
TOT At
NORTH DAKOTA
Billings
Bowman
Dunn
Hettinger
HcXenzie
McLean
Mercer
Morton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Carapbo 1 1
Johnson
Sheridan
TOTAL
SLURRY
ACRE-
FT/YR*
19,171
19,171
19,171
57,513
38,342
38,342
PIPELINE
WET SOLIDS1*
106 TON/YR
-
_
-
-.
-
-
LURCT GAS
ACRE-
FT/YR*
3,307
3,307
6,614
WET SOLIDST
106 TON/YR
1.20
1.20
2.40
SYNTHAhR fiAS
ACRE-
FT/YR*
WET SOLIDS^
10& TON/YR
SYh
ACRE-
FT/YR*
THOIT.
WET SOLIDS!
106 TON/YR
Ki.^rTRTrAt
ACRE-
FT/YR*
26,659
26,659
26,659
79,977
23,884
23,884
23,884
23,984
95,536
51,684
25,842
77,526
^P-MFRAT^pM
WET SOLIDS7
106 TON/YR
3.01
3.01
3.01
9.03
2.65
2.65
2.65
2.65
10.60
2.64
1.32
3.96
OIL
-------
CASE LOU DEMAND
FACILITIES SITED IN POWDER RIVER REGION BY 2000 (AFTER 1975)
STATE/COUNTY
MONTANA
Powder River
Big Horn
Rosebud
Custer
Wibaux
Richland
KcCone
TOTAL
NORTH DAKOTA
Billings
Scvsvan
Dunn
Hettinger
McKenzie
McLean
Xercer
Morcon
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Campbell
Johnson
Sheridan
TOTAL
SLURRY
ACRE-
FT/YR*
57,513
57,513
57,513
172,539
38,342
19,171
19,171
76,684
PXPRUNR
WET SOLIDST
106 TON/YR
_
_
-
-
-
-
-
-
r,uft<-r GAS
ACRE-
FTAR*
13,854
9,236
4,618
27,708
3,307
3,307
3,307
3,307
3,307
3,307
3,307
3,307
26,456
8,412
4,206
12,618
WET SOLIDS'
106 TONAR
3.81
2.54
1.27
7.62 .
1.20
1.20
1.20
1.20
1.20
1.20
1.20
1.20
9.60
1.44
0.72
2.16
SYNTIW..R GAS
ACRF.-
FT/YR*
7,808
7,808
7,808
23,424
7,671
7,671
7,671
7,671
7,671
38,355
7,776
7,776
15,552
WET SOLIDSt
106 TONAR
1.12
1.12
1.12
3.36
1.08
1.08
1.08
1.08
1.08
5.40
0.71
0.71
1.42
SYI.
ACRE-
FT/YR*
10,296
10,296
9,227
9,227
TIIOIL
WET SOLIDSt
106 TON/YR
2.07
2.07
1.23
1.23
ET.KrrpICAT
ACRE-
FT/YR*
53,318
53,318
26,659
133,295
23,884
23,884
23,884
23,884
23,884
23,884
143,304
51,684
25,842
77,526
GFN-ESJVTTftN
WET SOLIDST
106 TON/YR
6.02
6.02
3.01
15.05
2.65
2.65
2.65
2.65
2.65
2.65
15.90
2.64
1.32
3.96
QTT. pijay.r
ACRE-
FT/YR*
WET SOLIDS'
106 TON/YR
S3
-P--
o
* Water Consumed
t Residuals
-------
CASE LOW MUCLEAR £VAILABIUTY
FACILITIES SITED III POWDER RIVER REGION BY 1980 (AFTER 1075)
STATE/COUNT*
MONTANA
Powdar River
Big Horn
Rosebud
Custer
Kiiaux
Richland
KcCor.e
TOTAL
NORTH DAKOTA
Billings
Bowjnaa
Dunn
Hettinger
KcKenzie
KcLean
Kercer
Morton
Oliver
Slope
Stark
Bard
Williaas
TOTAL
WYOMING
Ca.-r.pbeU
Johnson
Sheridan
TOTAL
SLURRY PIPEMNF.
ACRE-
?T/SfR*
19,171
19,171
WET SOLIDS1"
106 TOS/VR
-
- .
. 1URGI GAS
ACRE-
FT/YR*
1«T SOLIDS!
106 TON/VR
SYNTHAN- GAS
ACRE-
FT/YS*
vIET SOLIDSt
106 TONAH
?Y
ACRE-
PT/YS*
THOIL,
MET SOLIDS
106 TOtVYR
ET.Efp-Rjf^T. r;gMp:R«Tro
ACRE-
FT/VR*
26,659
26,659
53,318
23,884
23,884
47,768
51,684
51,684
WET SOLIDS
106 TON/I R
3.01
3.01
6.02
2,65
2.65
5.30
2.64
2.64,
Off. SHALE
ACRE-
FT/YR*
WET SOLIDS'
106 TONAR
* Water Consumed
t Residuals
-------
CASE
KUCLEAR AVAILABILITY
FACILITIES SITED IN POWDER RIVER REGION BY 1985 (AFTER 1975)
STATE/COUNTY
KO:;TM;A
Powder River
Big Horn
Rosebud
custer
Wibaux
Richland
KcCone
TOTAL
NORTH DAKOTA
Billings
Sovnan
Dunn
Hettinger
KcKenzie
McLean
Kercer
Morton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Campbell
Johnson
Sheridan
TOTAL
SF.URRY
ACRE-
PTAR*
38,342
19,171
19,171
76,684
38,342
38,342
PIPELINE
VET SOLIDST
10& TONAR
_
.
-
-
_
-
ACRE-
PTAR*
I GAS
WET SOLIDST
IO6 TONAR
SYNTHAN-: CAS
ACRE-
PT/YR*
WET SOLIDSt
106 •SONAR
SYHTHOII.
ACKE-
PTAK*
•IET SOLIDSt
IO6 TONAR
FIPrTRTrM
ACRE-^
33,318
53,318
26,659
133,295
23,884
23,884
23,884
23,884
23,884
23,884
23,884
167,188
„-
51,684
51,684
GEUFFMISSa.
rfET SOLIDS1
IO6 TOSAR
6.02
6.02
3.01
15.05
2.65
2.65
2.65
2.65
2.65
2.65
2.65
18.55
2.64
2.64
IJJi «M.P
ACRE-
FTAR"
ET SOLIDS'
O6 TONAR
* Water Consumed
t Residuals
-------
CASE tnu NUCKFAR AVATLABrlTTY
FACILITIES SITED IN POWDER RIVER REGION BY 1990 (AFTER 1975)
STATE/COUNTY
MONTANA
Powder River
Big Horn
Rosebud
Custer
Vibaux
Ricnland
XcCor.e
TOTAL
NORTH DAKOTA
Billings
Bownan
Dunn
Hettinger
McKer.zie
KcLsan
>!ercer
Korton
Oliver
Slope
Stark
Ward
Williams
TOTAL
WYOMING
Campbell
Johnson
Sheridan
TOTAL
SLURRY
ACRE-
FT/VR*
38,342
38,342
38,342
115,026
76,684
76,684
PIPELINE
WET SOLIDS T
106 TON/YR
-
'
-
-
-
-
MIRGI GAS
ACRE-
FT/YR*
4,618
4,618
3,307
3,307
WET SOLIDST
106 TON/YR
1.27
1.27
1.20
1.20
SYNTHANn GAS
ACRE-
FT/YR*
WET SOLIDSt
106 TON/YR
pYl
ACRE-
FTAR*
TjiOfL
WET SOLIDS1
106 TON/YR
ELECTRJCA .GE^^F!^.'lTIP^'
ACRE-
FT/YR*
53,318
53,318
53,318
159,954
23,884
23,884
23,884
23,884
23,884
23,884
23,884
23,884
191,072
77,526
77,526
WET SOLIDS1"
106 TOM/YR
6.02
6.02
6.02
18.06
2.65
2.65
2.65
2.65
2.65
2.65
2.65
2.65
21.20
3.96
3.96
OIL .CiM*.c'
ACRE-
FT/YR*
WET SOLIDS'
106 TON/YR
,
* Hater Consumed
t Residuals
-------
CASE LOW KUCLEAH AVAILABILITY
FACILITIES SITED IN POWDER WVfiR REGION BY 2000 (AFTER 1975)
STATE/COUNTY
MONTANA
Powder River
Big Horn
Rosebud
Custer
Wibaux
Rich land
McCor.e
TOTAL
NORTH DAKOTA
Billings
Bovnan
Dunn
Hettinger
McKenzie
McLean
Mercer
Korton
Oliver
Slope
Stark
Ward
Williaos
TCTAL
WYOMING
Caapfcell
Johnson
Sheridan
TOTAL
SMRRY
ACRE-
FT/YR*
115,026
115,026
115,026
345,078
115,086
38,342
19,171
172,539
PIPEt.IHE
WET SOLIDST
106 TON/YR
-
_
-
-
-
-
-
-
LUR<
ACRE-
rr/YR*
18,472
13,854
13,854
46,180
3,307
3,307
3,307
3,307
3,307
6,614
6,614
3,307
6,614
3,307
42,991
12,618
4,206
4,206
21,030
I GAS
WET SOLIDST
106 TON/YR
5.08
3.81
3.81
12.70 .
1.20
1.20
1.20
1.20
1.20
2.40
2.40
1.20
2.40
1.20
15.60
2.16
0.72
0.72
3.60
SYNTBANii GAS
ACRE-
FT/YR*
15,616
7,808
7,808
31,232
7,671
7,671
7,671
15,342
7,671
46,026
7,776
7,776
15,552
WET SOLIDSt
106 TONAR
2.24
1.12
1.12
4.48
1.08
1.08
1.08
2.16
1.08
6.48
0.71
0.71
1.42
SYN
ACRE-
FTAR*
10,296
10,296
THOIL
WET SOLIDS1
106 TON/XR
2.07
2.07
Pj^a^j
ACRE-
FT/YR*
79,977
79,977
106,636
266,590
23,884
23,884
47,768
23.884
23,884
47,768
47,768
23,884
23,8,84
23,884
23,884
334,376
72,526
51,684
25,842
155,052
GPNPRArt0M
ffiT SOLIDS7
10s" TON/YR
9.03
9.03
12.04
30.10
2.65
2.65
5.30
2.65
2.65
5.30
5.30
2.65
2.65
2.65
2.65
37.10
3.96
2.64
1.32
7.92
TOf fHMJS
ACRE-
FT/YR*
-------
APPENDIX E. STATE TOTALS OF WATER CONSUMED AND RESIDUALS
GENERATED FOR THREE ENERGY SCENARIOS
The results presented in Appendix D are presented in a differ-
ent form in this appendix. For each region and facility, state
totals for water consumed and residuals generated are presented by
year and for the three energy scenarios. Table E-l shows the page
numbers on which the results for specific scenarios are presented
in this appendix.
245
-------
Table E-l. Location of results for specific
scenario by region and facility.
Facility
Slurry Pipeline*
Lurgi
Synthane
Gas Production
(Lurgi and Synthane)
Synthoil
Electrical Generation
Oil Shale
Page Number
Rocky Mountain
Region
247
248
249
250
251
252
253
Powder River
Region
254
255
256
257
258
259
—
For each facility, totals for consumed water and residuals
generated are presented by state for each energy scenario
and for each year.
246
-------
STATE TOTALS
FACILITIES SITED AFTER 1975 IN ROCKY MOUNTAINS REGION
FACILITY SLURRY PIPELINE (25 x 1Q6 tons/yr @ 100% load factor)
NOMINAL
DEMAND CASK
COLORADO
NEW J'JEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEW MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 10 TONS
PER YEAR* PER YEARt
1985
ACRE-PT 106 TOMS
PER YEAR* PER YBART
19,171
19,171
>
19,171
1990
ACRE-FT 106 TONS
PER YEAR* PER YEARt
19,171
19,171
19,171
2000
ACRE-FT J.O TONS
PER YEAR* PER YEARt
19,171
19,171
38,342
* Water Consumed
t Residuals (Wet Solids)
247
-------
;TATE TOTALS
FACILITIES SITED AFTER 1975 IN ROCKY MOUNTAINS REGION
FACILITY LURGI (25Q_x 1Q6 scf/stream day @ 90% load factor)
NOMINAL
DEMAND CASE
COLORADO
NEW MEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEW MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 10 TONS
PER YEAR* PER YEARt
1985
ACRE-FT 106 TONS
PER YEAR* PER YEARt
1990
6
ACRE-FT 10 TONS
PER YEAR* PER 'YEARt
2000
ACRE-FT -106 TONS
PER YEAR* PER YEARt
5,639 3.00
5,639 3.00
5,639 3.00
Water Consumed
Residuals (Wot Solids)
248
-------
STATE TOTALS
FACILITIES SITED AFTER 1975 IN ROCKY MOUNTAINS REGION
FACILITY _SYNTHANE (250 K 1Q6 scf/stream day @ 90% load factor)
NOMINAL
DEMAND CASE
COLORADO
NEW MEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEVJ MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 10 iuNS
PER YEAR* PER YEARt
1985
ACRE-FT 106 TONS
PER YEAR* PER YEARt
1990
ACRE-FT 10 TONS
PER YEAR* PER YEARt
2000
ACRE-FT 10 TONS
PER YEAR* PER YEARt
8,670 2.84
8,670 2.84
* Water Consumed
t Residuals (Wet Solids)
249
-------
STATE TOTALS
FACILITIES SITED AFTER 1975 IN ROCKY MOUNTAINS REGION
FACILITY GAS PRODUCTION (LURGI and SYNTHANE)
NOMINAL
DEMAND CASE
COLORADO
NEW MEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEW MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 10 TONS
PER YEAR* PER YEARt
1985
ACRE-FT 10 TONS
PER YEAR* PER YEARt
1990
ACRE-FT 10 TONS
PER YEAR* PER YEARt
2000
6
ACRE-FT 10 TONS
PER YEAR* PER YEARt
14,309 5.84
5,639 3.00
14,309 5.84
* Water Consumed
t Residuals (Wet Solids)
250
-------
STATE TOTALS
FACILITIES SITED AFTER 1975 IN ROCKY MOUNTAINS REGION
FACILITY SYNTHOIL (100.000 bbl/stroam day @ 90% load factor)
NOMINAL
DEMAND CASE
COLORADO
NEW MEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEW MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 10 TONS
PER YEAR* PER YEARt
1985
ACRE-FT 106 TONS
PER YEAR* PER YEARt
1990
ACRE-FT 106 TONS
PER YEAR* PER YEARt
2000
ACRE-FT ' 106 TONS
PER YEAR* , PER YEARt
* Water Consumed
t Residuals (Het Solids)
251
-------
STATE TOTALS
FACILITIES SITED AFTER 1975 IN ROCKY MOUNTAINS REGION
FACILITY ELECTRICAL GENERATION (3,uOO MWe @ 35% eff. and 70% load factor)
NOMINAL
DEMAND CASE
COLORADO
NEW MEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEW MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
i
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 106 TONS
PER YEAR* PEE YEARt
29,206 5.00
29,816 5.30
29,816 5.30
29,206 5.00
29,816 5.30
1985
ACRE-PT 106 TONS
PER YEAR* PER YEARt
28,482 1.14
29,206 5.00
29,816 5.30
29,206 5.00
29,816 5.30
28,482 1.14
58,412 10.00
59,632 10.60
1990
ACRE-FT 10 TONS
PER YEAR* PER YEARt
28,482 1.14
29,206 5.00
59,632 10.60
29,206 5.00
29,816 5.30
28,482 1.14
58,412 10.00
89,448 15.90
2000
ACRE-FT 106 TONS
PER YEAR* PER YEARt
28,482 1.14
29,206 5.00
59,632 10.60
29,206 5.00
29,816 5.30
56,964 2.28
87,618 15.00
119,264 21.20
* Hater Consumed
f Residuals (Wet Solids)
252
-------
STATE TOTALS
FACILITIES SITED AFTER 1975 IN ROCKY MOUNTAINS REGION
FACILITY OIL SHALE (100.000 bbl/scream day @ 90% load factor)
NOMINAL
DEMAND CASE
COLORADO
NEW MEXICO
UTAH
LOW DEMAND
CASE
COLORADO
NEW MEXICO
UTAH
LOW NUCLEAR
AVAILABILITY
CASE
COLORADO
NEW MEXICO
UTAH
1980
ACRE-FT 10 TONS
PER YEAR* PER YEARt
1985
ACRE-FT 106 TONS
PER YEAR* PER YEARt
25,848 81.62
25,848 81.62
25,848 81.62
1990
ACRE-FT 10 TONS
PER YEAR* PER YEARt
64,620 204.05
64,620 204.05
. 51,696 163.24
2000
ACRE-FT 106 TONS
PER YEAR* PER YEARt
91,112 1,550.78
51,696 163.24
413,568 1,305.92
38,'772 122.43
478,188 1,509.97
51,696 163.24
* Water Consumed
t Residuals (Wet Solids)
253
-------
STATE TOTALS
FACILITIES SITED AFTER 1975 IN POWDER RIVER REGION
FACILITY SLURRY PIPELINE (25 x 10 tons/yr & 100% load factor)
NOMINAL
DEMAND CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW DEMAND
CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW NUCLEAR
AVAILABILITY
CASE
MONTANA
NORTH DAKOTA
WYOMING
1980
• 6
ACRE-FT 10 TONS
PER YEAR* PER YEARt
19,171
19,171
19,171
1985
ACRE-FT 10 TONS
PER YEAR* PER YEARt
57,513
19,171
38,342
19,171
76,684
38,342
1990
ACRE-FT 10 TONS
PER YEAR* PER YEARt
76,684
38,342
57,513
38,342
115,026
76,684
2000
ACRE-FT - 10 TONS
PER YEAR* PER YEARt
210,881
115,026
172,539
76,684
345,078
172,539
* Water Consumed
t Residuals (Wet Solids)
254
-------
STATE TOTALS
FACILITIES SITED AFTER 1975 IN POWDER RIVER REGION
FACILITYLURGI (250 x 1Q6 scf/stream day @ 90% load factor)
NOMINAL
DEMAND CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW DEMAND
CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW NUCLEAR
AVAILABILITY
CASE
MONTANA
NORTH DAKOTA
WYOMING
1980
6
AC RE -FT 10 TONS
PER YEAR* PER YEARt
1985
ACRE -FT 10 TONS
PER YEAR* PER YEARt
1990
ACRE -FT 10 TONS
PER YEAR* PER YEART
4,618 1.27
6,614 2.40
6,614 2.40
4,618 1.27
3,307 1.20
2000
ACRE-FT 106 TONS
PER YEAR* PER YEARt
46,180 12.70
46,298 16.80
25,236 4.32
27,708 7.62
26,456 9.60
12,618 2.16
46,180 12.70
42,991 15.60
21,030 3.60
* Water Consumed
t Residuals (Wet Solids)
255
-------
STATE TOTALS
FACILITIES SITED AFTER 1975 IN POWDER RIVER REGION
FACILITY SYSTHAHE (250 x 10 scf/stream day @ 90% load factor)
NOMINAL
DEMAND CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW DEMAND
CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW NUCLEAR
AVAILABILITY
CASE
MONTANA
NORTH DAKOTA
WYOMING
1980
ACRE-FT 10 TONS
PER YEAR* PER YEARt
1985
ACRE -FT 106 TONS
PER YEAR* PER YEARt
1990
6
ACRE-FT 10 TONS
PER YEAR* PER YEARt
2000
ACRE-FT 106 TONS
PER'.YEAR* PER YEAR*
39,'040 5.60
53,697 7.56
23,328 2.13
23,424 3.36
38,355 5.40
15,552 1.42
31,232 4.48
46,026 6.48
15,552 1.42'
* Water Consumed
t Residuals (Wet Solids)
256
-------
STATE TOTALS
FACILITIES SITED AFTER 1975 IN POWDER RIVER REGION
FACILITY GAS PRODUCTION (LURGI AND SYNTHANE)
NOMINAL
DEMAND CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW DEMAND
CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW NUCLEAR
AVAILABILITY
CASE
MONTANA
NORTH DAKOTA
WYOMING
1980
ACRE -FT 10 TONS
PER YEAR* PER YEARt
1985
6
ACRE -FT 10 TONS
PER YEAR* PER YEARt
1990
ACRE -FT 10 6 TONS
PER YEAR* PER YEARt
4,618 1.27
6,614 2.40
6,614 2.40
4,618 1.27
3,307 1.20
2000
ACRE-FT "106 TONS
PER YEAR* PER YEARt
85,220 18.30
99,995 24.36
48,564 6.45
51,132 10.98
64,811 15.00
28,170 3.58
77,412 17.18
89,017 22.08
36,582 5.02
* Water Consumed
t Residuals (Wet Solids)
257
-------
STATE TOTALS
FACILITIES SITED AFTER 1975 IN POWDER RIVER REGIChN
FACILITY SYNTHOIL (100.000 bbl/stream day @ 90% load factor)
NOJ-SINAL
DEMAND CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW DEMAND
CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW NUCLEAR
AVAILABILITY
CASE
MONTANA
NORTH DAKOTA
WYOMING
1980
ACRE -FT 106 TONS
PER YEAR* PER YEARt
1985
ACRE -FT 106 TONS
PER YEAR* PER YEARt
1990
ACRE-FT 106 TOMS
PER YEAR* PER YEARt
2000 -
ACRE-FT ' 106 TONS
PER YEAR* PER YEARt
5,1*8 I-04
10,085 2.00
10,296 2.07
9,227 1.23
10,296 2.07
* V!ater Consumed
t Residuals (Wet Solids)
258
-------
STATE TOTALS
FACILITIES SITED AFTER 1975 IN POWDER RIVER REGION
FACILITY ELECTRICAL GENERATION (3,000 MWe @ 35% eff. and 70% load facto*'
NOMINAL
DEMAND CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW DEMAND
CASE
MONTANA
NORTH DAKOTA
WYOMING
LOW NUCLEAR
AVAILABILITY
CASE
MONTANA
NORTH DAKOTA
WYOMING
1980
ACRE -FT 10 TONS
PER YEAR* PER YEARt
53,318 6.02
47,768 5.30
25,842 1.32
26,659 3.01
47,768 5.30
25,842 1.32
53,318 6.02
47,768 5.30
51,684 2.64
1985
ACRE -FT 10 TONS
PER YEAR* PER YEARt
106,636 12.04
119,420 13.25
51,684 2.64
79,977 9.03
95,536 10.60
51,684 2.64
133,295 15.05
167,188 18.55
51,684 2.64
1990
ACRE -FT 10 TONS
PER YEAR* PER YEARt
133,295 15.05
143,304 15.90
51.684 2.64
79,977 9.03
95,536 10.60
77,526 3.96
159,954 18.06
191,072 21.20
77,526 3.96
2000
ACRE-FT 106 TONS'
PER YEAR* PER YEARt
159,954 18.06
214,956 23.85
77,526 3.96
133,295 15.05
143,304 15.90
77,526 3.96
266,590 30.10
334,376 37.10
155,052 7.92
* Water Consumed
t Residuals (Wet Solids)
259
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-77-037
3. RECIPIENT'S ACCESSION NO.
.. TITLE AND SUBTITLE
Water Requirements for Steam-Electric Power Generation
and Synthetic Fuel Plants in the Western United States
5. REPORT DATE
February, 1977
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
H. Gold, D.J. Goldstein, R.F. Probstein, J.S. Shen &
D. Yung
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Water Purification Associates
Cambridge, Massachusetts 02142
10. PROGRAM ELEMENT NO.
EHE 624C
11. CONTRACT/GRANT NO.
68-01-1916
12. SPONSORING AGENCY NAME AND ADDRESS
Office of Energy, Minerals and Industry
Office of Research and Development
U.S. Environmental Protection Agency
Washington, D.C. 20460
13. TYPE OF REPORT AND PERIOD COVERED
Final, 5/76-8/76
14. SPONSORING AGENCY CODE
EPA/600/17
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The study describes the procedures for the detailed determination of the water
consumed for mining and processing coal and oil shale, and for determining the
residuals generated. The processes considered are Lurgi, Synthane, and Synthoil
for coal conversion, TOSCO II for shale conversion, coal-fired steam electric power
generation and slurry pipeline. In addition, determiniations are also made of the
water consumed for process cooling, flue gas desulfurization, revegetation of mined
land, solids disposal and by evaporation and other uses within the mine-plant
complex. In these determinations it is assumed that there is no discharge to
receiving waters and that there is a reasonably high level of recycle and reuse
of process effluent waters. Wasteful evaporation of wastewater is not permitted.
Economic studies of water treatment are not included in this assessment except for
some of the process cooling studies.
The consumptive water use and solids residuals are determined for a total of
21 plant-site combinations. The sites are: Beulah, North Dakota; Colstrip, Montana;
Gillette, Wyoming; Kaiparowits/Escalante, Utah; Navajo/Farmington, New Mexico; and
Rifle, Colorado. A detailed breakdown by consumptive water use category is presented
in tabular form for each plant-site combination. Approximately twenty water use
categories are considered.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Water Supply
Energy Conversion
b.IDENTIFIERS/OPEN ENDED TERMS
Coal Conversion
Oil Shale Conversion
Water Consumption
c. COSATI Reid/Group
13B
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
UNCLASSIFIED
21. NO. OF PAGES
276
20. SECURITY CLASS {Thispage)
UNCLASSIFIED
22. PRICE
EPA Form 2220-1 (9-73)
aU.S. GOVERNMENT PRINTING OFFICE: 1977 7^0-U7/1982 1-3
-------
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Technical Information Staff
Cincinnati, Ohio 45268
POSTAGE AND FEES PAID
U S ENVIRONMENTAL PROTECTION AGENCY
EPA-335
OFFICIAL BUSINESS
b
PENALTY FOR PRIVATE USE. S3OO
AN EQUAL OPPORTUNITY EMPLOYER
Special Fourth-Class Rate
Book
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