United States
Environmental Protection
Agency
Research and Development
Office of Energy, Minerals, and
Industry
Washington DC 20460
EPA 600 7-79-085
March 1979
Wet/Dry
Cooling and
Cooling Tower
Blowdown
Disposal in
Synthetic Fuel and
Steam-Electric
Power Plants
Interagency
Energy/Environment
R&D Program
Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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January 1979
WET/DRY COOLING AND COOLING TOWER
BLOWDOWN DISPOSAL IN SYNTHETIC FUEL
AND STEAM-ELECTRIC POWER PLANTS
A Subcontract Report to the University of Oklahoma
Science and Public Policy Program for:
Technology Assessment of Western Energy Resource Developmeni
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
-------
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.
-------
FOREWAKD
The production of electricity and fossil fuels inevitably impacts
Man and his environment. The nature of these impacts must be thoroughly
understood if balanced judgements concerning future energy development
in the United States are to be made. The Office of Energy, Minerals and
Industry (OEMI) , in its role as coordinator of the Federal Energy/Environ-
ment Research and Development Program, is responsible for producing
the information on health and ecological effects - and methods for miti-
gating the adverse effects - that is critical to developing the Nation's
environmental and energy policy. OEMI's Integrated Assessment Program
combines the results of research projects within the Energy/Environment
Program with research on the socioeconomic and political/institutional
aspects of energy development, and conducts policy-oriented studies to
identify the tradeoffs among alternative energy technologies, develop-
ment patterns, and impact mitigation measures.
The Integrated Assessment Program has supported several "technology
assessments" in fulfilling its mission. Assessments have been supported
which explore the impact of future energy development on both a nation-
wide and a regional scale. Current assessments include national assess-
ments of .future development of the electric utility industry and of
advanced coal technologies (such as fluidized bed combustion) . Also,
the Program is conducting assessments concerned with multiple-resource
development in two "energy resource areas" :
o Western coal states
o Lower Ohio River Basin
This report, which describes wet/dry cooling and cooling tower
blowdown disposal in synthetic fuel and steam-electric power plants is
the second of two major reports prepared by Water Purification Associates
under Subcontract to the Science and Public Policy Program of the University
of Oklahoma as a part of its "Technology Assessment of Western Energy
Resource Development" study. The first report made a detailed determina-
tion of consumptive water use and wet-solids residuals for coal and oil
shale concession plants and coal-fired steam-electric power plants.
This report focuses on the problem of making a choice of cooling options
on the basis of the true cost of water.
We would like to receive your comments concerning this report.
Such comments will help us to improve the usefulness of the products
produced by our Integrated Assessment program.
Steven R. Reznel)
Acting Deputy Assistant Administrator
for Energy, Minerals and Industry
iii
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ABSTRACT
This report extends the results of a previous study dealing with the
detailed determination of consumptive water use and wet-solids residuals for
coal and oil shale conversion plants and coal-fired steam-electric power
generation plants located in the Western United States. The present report
addresses the problem of determining the degree to which wet cooling, dry cooling,
or wet/dry cooling should be used as a function of the true cost of water. The
economics of cooling gas compressor interstage coolers for coal conversion and
cooling steam turbine condensers for coal conversion and steam-electric power
generation have been examined. The results show that for coal conversion plants
located in the Western coal and oil shale bearing regions, it is economical to
use a large degree of dry cooling for the steam turbine condensers and either wet
or wet/dry cooling for the gas interstage coolers. For wet/dry cooling, the total
water consumption in a coal conversion plant is 15 to 40 percent less than with a
high degree of wet cooling. Because of the capital intensive nature of dry cooling,
the penalty in going to a wet/dry cooling system is about 0.5 - l.OC/10 Btu of
product output, if the cost of water is negligible.
The total water consumed by a steam-electric power plant using a wet/dry
cooling system can be reduced by about 70 to 80 percent below that for all wet
cooling of the steam turbine condensers. However, this is only .economical if the
cost of water exceeds about $3.50/1000 gals, which is not likely to be the case.
If the cost of water is negligible, then the maximum cost penalty is about
1-2 mils/kw-hr. The use of wet/dry cooling in power plants will most likely be
dictated by the local availability of water.
Two other subject-areas are also covered in this report. First, results of
a separate EPA/DOE study of 42 coal/oil shale conversion plant-site combinations
are included to provide an enlarged data base for more meaningful regional water
assessments. Sece-nd, the costs of wastewater treatment and blowdown treatment
and disposal are calculated for coal conversion and steam-electric power plants.
IV
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TABLE OF CONTENTS
FOREWARD iii
ABSTRACT iv
FIGURES vi
TABLES ix
CONVERSION FACTORS xii
1. SUMMARY 1
1.1 Introduction 1
1.2 Wet/Dry Cooling 2
1.3 Regional Water Requirements and Residuals Disposal .... 11
1.4 Economics of Water Treatment and Cooling Tower Slowdown
Treatment and Disposal 12
References 14
2. SELECTED ASPECTS OF WET/DRY COOLING 15
2.1 Introduction 15
2.2 Turbine Condensers in Coal Conversion Plants 52
2.3 Air Compressors in Coal Conversion Plants 87
2.4 Hydrogen Compressors in Coal Conversion Plants 109
2.5 Turbine Condensers in Steam-Electric Power Plants ..... 124
References 139
3. REGIONAL WATER REQUIREMENTS AND RESIDUALS DISPOSAL 140
3.1 Introduction 140
3.2 Process and Site Selection 140
3.3 Water Supply and Demand 145
3.4 Total Water Consumed and Residuals Generated 151
References 160
4. ECONOMICS OF WATER TREATMENT AND COOLING TOWER SLOWDOWN TREATMENT
AND DISPOSAL '. 165
4.1 Introduction 165
4.2 Process and Cooling Water Treatment 166
4.3 Slowdown Treatment and Disposal 183
References 207
v
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FIGURES
Number Page
2-1 Cost of steam turbine condenser cooling in Farmington, N.M. ... 23
2-2 Cost of steam turbine condenser cooling in Casper, Wyo 24
2-3 Cost of steam turbine condenser cooling in Beulah, N.D 25
2-4 The effect of water cost on water consumed for cooling turbine
condensers
26
2-5 Cost of interstage cooling for compressing 1,000 Ib air at
Farmington, N.M. (Set 1) 31
2-6 Cost of interstage cooling for compressing 1,000 Ib air at
Casper, Wyo. (Set 1) 32
2-7 Cost of interstage cooling for compressing 1,000 Ib air at
Beulah, N.D. (Set 1) 33
2-8 The effect of water cost on water consumed for interstage cooling
when compressing 1,000 Ib air (Set 1) 34
2-9 Cost of interstage cooling for compressing 1,000 Ib air at
Farmington, N.M. (Set 2) 35
2-10 Cost of interstage cooling for compressing 1,000 Ib air at
Casper, Wyo. (Set 2) 36
2-11 Cost of interstage cooling for compressing 1,000 Ib air at
Beulah, N.D. (Set 2) 37
2-12 The effect of water cost on water consumed for interstage cooling
when compressing 1,000 Ib air (Set 2) 38
2-13 Cost of interstage cooling for compressing 1,000 Ib air at
Farmington, N.M. (Set 3) 39
2-14 Cost of interstage cooling for compressing 1,000 Ib air at
Casper, Wyo. (Set 3) 40
2-15 Cost of interstage cooling for compressing 1,000 Ib air at
Beulah, N.D. (Set 3) 41
2-16 The effect of water cost on water consumed for interstage cooling
when compressing 1,000 Ib air (Set 3) 42
2-17 Cost of interstage cooling for compressing 1,000 Ib hydrogen at
Farmington, N.M 47
2-18 Operating costs and water consumption of wet/dry cooling system . 51
2-19 Turbine condenser cooling systems 53
2-20 Turbine heat rates at fuel load 55
2-21 Turbine condenser cooling requirements at full load 56
2-22 Fan power reduction factor for air coolers 65
2-23 Air compressor design conditions 88
2-24 Hydrogen compressor design conditions 110
2-25 Wet/dry cooling system 129
vi
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FIGURES (Continued)
Number Page
2-26 Total annual evaluated cost of wet/dry cooling system located
at Navajo/Farmington, N.M 130
2-27 Total annual evaluated cost of wet/dry cooling system located
at Beulah, N.D 131
2-28 Changeover costs for Beulah, N.D. and Navajo/Farmington, N.M. . . 134
2-29 Ratio of changeover water cost at New Mexico to North Dakota . . 135
2-30 Ratio of changeover water costs as a function of fixed charge
rate ratio 136
2-31 Ratio of changeover water costs as a function of fuel cost ratio 137
3-1 Coal and oil shale conversion site locations in Western States . 142
3-2 Costs of transporting water to specific site locations in the
Western States 149
3-3 Costs of transporting water to coal regions in the Western States 150
3-4 Summary of average net water consumed for coal conversion plants
located in the Western States 158
3-5 Summary of net water consumed for oil shale conversion plants
located in the Western States 159
3-6 Summary of average wet-solid residuals generated from standard
size coal conversion plants located in the Western States .... 161
3-7 Summary of average wet-solid residuals generated from standard
size oil shale plants located in the Western States 162
4-1 Water treatment block diagrams 168
4-2 Cost of water treatment in C/10 Btu of product 179
4-3 Energy consumed for water treatment in % of the heating value of
product fuel 180
4-4 Quantity of dirty process condensate generated in a 250 x 10
scf/day Lurgi plant as a function of moisture content of coal . . 181
4-5 Flow diagram for blowdown treatment and disposal 185
4-6 Incorporation of blowdown treatment into sidestream treatment . . 187
4-7 Case I. Effluent discharge to river at low cycles of
concentration 189
4-8 Case II. Effluent discharge to river at high cycles of
concentration. TDS reduction not required 190
vii
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FIGURES (Concluded)
Number
4-9 case II. Effluent discharge to river. TDS reduction via single
stage electrodialysis membrane system .............. •"• •
4-10 Cases III & IV. Zero discharge. Slowdown used for in-plant uses
or disposed of in a solar evaporation pond ........ • • •
4-11 Case V. Zero discharge incorporating 3 stage electrodialysis
with wastewater recycle ............. • .......
4-12 Case VI. Zero discharge incorporating vapor compression brine
concentration with wastewater recycle ..............
Vlll
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TABLES
Number Page
1-1 Net water consumed at each site for coal conversion 5
1-2 Net water consumed and wet-solid residuals generated for oil
shale conversion 9
1-3 Net water consumed at each site for steam-electric power
generation 10
2-1 Summary of the choice of wet or dry cooling and approximate amount
of evaporated water for an SNG plant producing 250 x 10 scf/day
in New Mexico and Wyoming 17
2-2 Unit costs 19
2-3 Annual average costs for wet/dry condenser cooling 20
2-4 Annual average costs for wet/dry compressor interstage cooling
for air compressors 28
2-5 Annual average cost for wet/dry compressor interstage cooling
for hydrogen compressors 44
2-6 Summary of wet/dry cooling system cost and water requirements at
Navajo/Farmington, New Mexico 49
2-7 Summary of wet/dry cooling system cost and water requirements at
Beulah, North Dakota 50
2-8 Nomenclature 67
2-9 Average ambient conditions 69
2-9a Heat transfer coefficients, fan and pump energies 70
2-10 Calculations on steam turbine condensers at Farmington, N.M. . . 71
2-11 Calculations on steam turbine condensers at Casper, Wyo 76
2-12 Calculations on steam turbine condensers at Beulah, N.D 81
2-13 Summary of wet/dry condenser cooling calculations 86
2-14 Summary of wet/dry compressor interstage cooling for air
compressors at Farmington, N.M. with water cooler off for
months 1, 2, 3, 11 and 12 93
2-15 Annual average cost for wet/dry compressor interstage cooling
for air compressors at Farmington, N.M. with water cooler off
for months 1, 2, 3, 11 and 12 93
2-16 Calculations of interstage cooling of an air compressor handling
100 Ib air/hr at Farmington, N.M. 95
2-17 Calculations of interstage cooling of an air compressor handling
100 Ib air/hr at Casper, Wyo IQQ
2-18 Calculations of interstage cooling of an air compressor handling
100 Ib air/hr at Beulah, N.D
IX
-------
TABLES (Continued)
Number Page
2-19 Summary of wet/dry compressor interstage cooling for air
compressors 108
2-20 Calculations on interstage cooling of a hydrogen compressor
handling 1,000 Ibs H /hr at Farmington, N.M 112
2-21 Calculations on interstage cooling of a hydrogen compressor
handling 1,000 Ibs H /hr at Casper, Wyo 117
2-22 Calculations on interstage cooling of a hydrogen compressor
handling 1,000 Ibs H /hr at Beulah, N.D 12°
2-23 Summary of wet/dry compressor interstage cooling for hydrogen
compressors 123
2-24 Summary of unit price data 127
2-25 Changeover water costs for New Mexico and North Dakota 133
2-26 Evaporation rate for optimized wet/dry and all wet cooling
systems 138
3-1 Coal and oil shale conversion plant-site combinations for Western
States . 141
3-2 Product fuel output of standard size synthetic fuel plants . . . 144
3-3 Study sites comprising coal and oil shale building regions . . . 152
3-4 Summary of coal and oil shale mining rates in 1,000 tons per
calendar day for standard size synthetic fuel plants operating
at 90% capacity 153
3-5 Summary of coal and oil shale mining rates normalized with
respect to the heating value of the product fuel in 100 lb/10
Btu 154
3-6 Summary of net water consumed in 10 gpd for standard size
synthetic fuel plants operating at 90% capacity 155
3-7 Summary of net water consumed normalized with respect to the
heating value in the product fuel in gallon/10^ Btu 156
-3_Q 3
Summary of total wet residuals generated in 10 tons/day for
standard size synthetic fuel plants operating at 90% capacity . . 163
3-9 Summary of total wet residuals generated normalized with respect
to the heating value in the product fuel in lbs/106/Btu 164
4-1 Water flow quantities in 10 Ib/hr 170
4-2 Quality of process condensate from synthetic and Lurgi processes
using subbituminous and lignite coals 173
-------
TABLES (Concluded)
Number Page
4-3 Costs of water treatment in £/hr • • 177
4-4 Energy requirements for water treatment in 10 Btu/hr 178
4-5 Summary of cases studied 188
4-6 Flow rates in gallons per stream minute . . 196
4-7 Flow rates, concentrations and salt loading of waste streams . . 197
4-8 Capital cost of major equipment components in thousands of $ . . 199
4-9 Capital cost of treatment and disposal systems in thousands of $ 201
4-10 Operating cost of treatment and disposal systems in thousands of
$ per year 203
4-11 Amortization and operating costs of treatment and disposal
systems in thousands of $ per year 205
4-12 Amortization and operating costs of treatment and disposal
systems normalized with respect to the product energy used . . . 208
4-13 Amortization and operating costs of treatment and disposal
systems in $ per thousand gallons of blowdown 210
XI
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Conversion Factors
Conversion of American to International System (SI) Units
ACCEPTATION
foot/second
free fall, standard
3.048
9.807
SY.
x 10
-1
To Obtain
neter/Becond2
meter/second
feet
4.047 x 10
9.290 x 10
-2
Btu (mean)
calorie (mean)
kilowatt-hours
1.056 x 10
4.190 ,
3.60 x 10
joule
joule
joule
ENERGY/AREA-TIME
Btu/foot_ hour
Btu/foot minute
Btu/foot second
calorie/cm minute
3.152 x 10
1.891 X 10'
1.135 x 10*
6.973 x 10
-1
watt/meter.
watt/meter2
watt/meter.
watt/meter
FORCE
dyne
kilogram force (Kgf)
pound force (Ib ,avoirdupois)
1.00 x 10
9.B07
4.44B
newton
newton
newton
LENGTH
foot
mile
3.048 x 10
1.609 x 10
meter
meter
pound (avoirdupois)
ton (metric)
ton (short, 2000 Ib)
4.536 x 10
1.00 x 10
9.072 x 10
kilogram
kilogram
kilogram
MASS/TIME
pound/hour
pound/minute
ton (short)/hour
ton (short)/day
1.260
7.560
2.520
x 10
x 10
1.050 x 10
kilogram/second
kilogram/second
kilogram/second
kilogram/second
MASS/VOLUME
MISCELLANEOUS
PRESSURE
gram/centimeter
pound/foot
pound/gallon (U.S. liquid)
Btu/hr-ft -°F
Btu/kw-hr
Btu/lb
Btu/lbm-«F
B
gal/10 Btu
kilocalorie/kilogram
Btu/hour
Btu/minute
Btu/second
calorie/hour
calorie/minute
calorie/second
horsepower
atmosphere
foot of water (39.2T)
psi (lbf/in )
1.
1.
1.
5.
2.
2.
4.
3.
4.
2.
1.
1.
00 X 10
602
198
674
929
324
1B4
585
184
929
757
054
1.162
6.
4.
7.
1.
2.
6.
973
184
457
013
989
895
x
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
10
1
-1
3
-
12
1
3
-?
2
5
3
3
ki lograa/ineter
kilogran/meter.
kilograjn/neter
joules/sec-m -BC
joules/kw-sec
joule/kg
jouleAg-*C
meter /joule
joule/k9
watt
watt
watt
watt
watt
watt
watt
4.788 x 10
pascal (-
pascal
pascal
pascal
newton/m )
foot/minute
foot/second
mile/hour
5.08 x 10
3.048 x 10
4.470 x 10
meter/second
meter/second
meter/second
TEMPERATURE
O.556 (°F + 459.7)
(continued)
Xll
-------
Conversion Factors (Continued)
Multiply
To Obtain
VOLUME
VOLUME/TIME
Other Conversion
acre foot
barrel (oil. 42 gal)
foot
gallon (U.S. liquid)
ft^/min
ftVsec
gal (U.S. liquid}/day
gal (U.S. liquid) /min
Factors
The following table is based on a density of water
of water at 6B°F
(20°C) and corresponds to 6.33 pounds
acres
acres
acre-feet
acre-feet
acre- fee t/y ear
acre-feet/year
acre-feet/year
barrels, oil
Btu
cubic feet
cubic feet
cubic feet of water
cubic feet/second
gallons
gallons
gallons
gallons/minute
gallons/minute
gallons/minute
gallons of water/minute
horsepower
ki lowatt-hours
milligrams/liter
million gallons/day
million gallons/day
million gallons of water/day
pounds of water
pounds of water
pound moles of gas
square feet
temperature, "C
temperature , °F- 32
thousand pounds/hour
thousand pounds/hour
thousand pounds of water/hour
thousand pounds of water/hour
tons (short)
tons (short)
tons/year
watt:;
-1
1.590 x 10
1.233 x 10
2.832 x 10"
3.785 x 10
4.719 x 10~*
2.832 x 10*
4.381 x 10"
6.309 x 10~
of 62.3 pounds per cubic
of water per gallon.
4.36 x 104
1.56 x 10~
4.36 x 10*
3.26 x 10_
3.91 x 10 ~*
6.20 x 10~
8.93 x 10"
4.2 x 10
2.52 x 10
3.93 x 10~
2.30 x 10"
7.48
6.23 x 10"!
4.49 X 10
6.46 x 10 ~^
3.O7 x 10
2.38 x 10"
1.34 x 10
8.33
1.61
2.23 x 10 '
1.44 x 10 j
5.00 x 10
4
6.11 x 10
2.55 x 10^
3.41 x 10
*• 3
1.12 x 10
,1.55 . .
6.94 x 10j
3.47 x 10
1.20 x ID'*
1ff\ „ -t ft"
. oU X J-U.
3.80 x 10
2.30 x 10
1'8
5.56 x 10~
1.2 x 10
4.38 x 10
2.00
2.88 X 10
2 X 10
9.07 x 10 ~^
8.33 x 10"^
2.28 x 10
3.41
3
meter^
meter
meter
meter
meter /second
meter /second
meter /second
meter /second
foot. This is the density
square feet
square miles
cubic feet
gallons
cubic meters /second
gallons/minute
million gallons/day
gallons
ho r s epowe r -hou r s
acre-feet
gallons
pounds of water
million gallons/day
acre-feet
barrels , oil
cubic feet
acre-feet/year
cubic feet/second
million gallons/day
thousand pounds of water/hr
Btu/hour
Btu
parts/million
acre-feet/year
gallons/minute
thousand pounds of water/hr
gallons of water
......standard cubic feet of gas
acres
32 - °F
°C
tons /day
tons/year
gallons of water/minute
millions gals of water/day
pounds
metric tons
thousand pounds/hour
Btu/hour
Kill
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1. SUMMARY
1.1 INTRODUCTION
In a previous report the water requirements of several fossil fuel
energy conversion technologies were determined at six sites in the Western
United States. The results of the study showed that the largest quantity of
water consumed in all facilities, except oil shale, is the water evaporated
for cooling. Calculations for steam electric power generation were based
on all wet cooling of turbine condensers. However, a partial evaluation was
made of wet/dry cooling which showed that a reduction of over 75 percent in water
consumption could be achieved but with the economics depending on the cost of
water. Calculations for the synthetic fuel plants were based on all wet cooling
of turbine condensers and interstage coolers. Combination wet/dry cooling was
not examined for the synthetic fuel plants, but could also reduce the cooling
water requirements substantially. The cost of water when wet/dry cooling
becomes economically viable was estimated but not quantified. The present report
addresses the problem of determining the degree to which wet cooling, dry cooling
or wet/dry cooling should be used as a function of the true cost of water.
The results presented in Reference 1 were also limited in two other respects.
First, a total of only fourteen (14) coal and oil shale conversion plant-site
combinations were studied with the total number of sites limited to six. The
regional water impact assessments presented in Reference 2 were based on this
limited data base. Results of a study of 42 plant-site combinations are included
in this report to provide an enlarged data base for more meaningful regional
water assessments.
Second, the costs of wastewater treatment in coal gasification plants were
not calculated in Reference 1. In this report these costs are calculated
together with the costs of blowdown treatment and disposal to determine if they
are excessive with respect to the cost of the product fuel or the cost of
electricity.
-------
1.2 WET/DRY COOLING
The water consumed in cooling is a large percentage of the total water
consumed in a plant converting coal to synthetic fuel. This is true even
when all effluent water streams are recycled or reused within the mine or the
plant after any necessary treatment. For example, for the four Synthane
plants studied under the first phase of the program , the cooling water
consumption ranged from 65 to 70 percent of the total water consumption,
while for the four Synthoil plants the range was 71 to 86 percent. Coal-
fired, steam-electric power plants even use a higher percentage of cooling
water, ranging from 80 to 90 percent of the total water consumed for the six
sites.
In coal conversion plants the heating value in the raw material not
recovered in the synthetic fuel or the by - products must be transferred to
the environment. Some of this unrecovered heat is lost directly to the
atmosphere, leaving the plant in hot gases up a flue, in water vapor from
coal drying and in other direct ways. However, the largest fraction of the
unrecovered heat is indirectly transferred to the atmosphere, through either
air (dry) cooling or wet cooling or a combination of the two. A high degree
of wet cooling was assumed in calculating the water requirements for the
Synthane and Synthoil processes studied in Reference 1. High wet cooling
does not mean that all of the unrecovered heat is dissipated by wet cooling.
In the Synthane process, it was calculated that the amount of unrecovered
heat dissipated by wet cooling was 42 percent, while for the Synthoil process
wet cooling ranged from 48 to 55 percent. Thus, even for a high degree of
wet cooling, more than 50 percent of the unrecovered heat is economically
dissipated to the atmosphere.
The degree to which wet cooling or dry cooling is used is an economic
one depending on the cost of water. The economics must be calculated for
each type of cooling load in the plant. We assumed in the calculations
presented in Reference 1 that intermediate and product gas and liquid process
streams are dry cooled to 140°F and wet cooled below this temperature, that
the gas purification regenerator condenser is dry or wet/dry cooled dependent
-------
on the choice of purification system, that off-gas scrubbing.and quenching is
dry cooled, and that both the condensers for steam turbines and the gas
compressor interstage coolers are wet cooled. In this report, the economics
of the last two cooling loads are examined for coal conversion plants.
For steam turbine condensers in a coal conversion plant, when water
costs more than about 25C/1000 gals, combined wet/dry cooling should be used
and the water consumption will be less than 10 percent of the consumption
with all wet cooling. This summary is based on calculations performed for
Farmington, New Mexico, Casper, Wyoming and Beulah, North Dakota for a range
of amortization and maintenance charges and electrical energy and steam
costs.
Results on interstage cooling of an air compressor in a coal conversion
plant show that if the cost of water exceeds about $1.50 per 1000 gals,
series wet/dry interstage coolers should be used with water consumption 50 to
60 percent of the consumption for all wet coolers. Dry cooling is preferred
for all unit cost sets studied at all sites for interstage cooling of a
hydrogen compressor.
Three cooling options have been considered, each option denoted by the
different degrees of wet cooling used for turbine condensers and interstage
coolers on gas compressors in coal conversion plants. At a site where water
is plentiful and inexpensive to transport, high wet cooling would be used.
The cooling loads on both the turbine condensers and interstage coolers are
taken to be all wet cooled. For the Lurgi process, a detailed thermal balance
is not available and wet cooling is assumed to be used to dispose of 42
percent of the total unrecovered heat. This value is the same one estimated
for the Synthane process. In regions where water is marginally available or
moderately expensive to transport, intermediate wet cooling would be used.
This assumes that wet cooling handles 10 percent of the cooling load on the
turbine condensers and all of the load of the interstage coolers. For the
Lurgi process it is assumed that 28 percent of the unrecovered heat is dissipated
by wet cooling, which is in the range of values found in the proposed El Paso
and Wesco Lurgi designs and the same one estimated for the Synthane process.
The oil shale processes are taken to correspond to intermediate cooling.
Twenty-eight percent of the unrecovered heat is dissipated by wet cooling for
-------
the Paraho Direct process, while 18-19 percent is dissipated for both the
Paraho Indirect and TOSCO II processes. In regions where water is expensive
to transport or scarce, minimum practical wet cooling is assumed with wet
cooling handling 10 percent of the cooling load on the turbine condensers and
50 percent of the load on the interstage coolers. For this case we have
assumed the Lurgi process dissipates about 24 percent of the unrecovered heat
by wet cooling.
If water costs more than about $1.50/1000 gals, minimum practical cooling
would be used. Intermediate cooling would be used if water costs between
$0.25 to $1.50/1000 gals, while high wet cooling would be used if water costs
less than $0.25/1000 gals.
Table 1-1 shows the total net water consumed for all three cooling
options in coal conversion plants located at the study sites. The results
presented in Phase I of the program are indicated by an asterisk. It should
be noted that the resu-lts for Lurgi presented in Reference 1 correspond to
the case of intermediate wet cooling, as we have defined it above. For the
Lurgi process the total water consumed in the case of intermediate wet cooling
is 21 to 32 percent less than the case of high wet cooling. The water consumption
with minimum practical wet cooling is 27 to 42 percent less than with high wet
cooling. For Synthane the reductions are 23-24 percent and 27-29 percent, while for
Synthoil the reductions are 16-19 percent and 21-25 percent, respectively.
The largest reduction is between high wet cooling and intermediate wet cooling,
while there is only an additional reduction of about 2 to 5 percent between
intermediate wet cooling and minimum practical cooling.
Table 1-1 shows that the reduction in the net water consumed between
high wet cooling and minimum practical wet cooling is about 9 gal/10 Btu
for the Lurgi and Synthane processes and 4 gal/10 Btu for the Synthoil
process. However, a penalty must be paid in going to a wet/dry cooling
system because of the capital intensive nature of dry cooling. The penalty
is about 1C/10 Btu for the Lurgi and Synthane processes and about 0.5C/10
Btu for the Synthoil process. This penalty is the maximum penalty and assumes
that the cost of water is negligible. The price of pipeline gas is estimated
to be about $3.00-$4.00/ 10 Btu.
The results presented in Reference 1 for oil shale have been extended
from the TOSCO II indirect retorting process to include the Paraho Direct and
Indirect processes. Underground mining and surface retorting are assumed for
-------
TABLE 1-1 NET WATER CONSUMED AT EACH SITE FOR COAL CONVERSION
LURGI (250 x 10 scf/stream day)
acre-ft/yr
gal/cal min
gal/106 Btu
SYNTHANE (250 x 10 scf/stream day)
acre-ft/yr
gal/cal min
gal/106 Btu
SYNTHOIL (100,000 bbI/stream day)
acre-ft/yr
gal/cal min
gal/106 Btu
Beulah
North Dakota
4,891
3,032
20.2
7,671*
4,756*
31.7
10,085*
6,253*
16.1
Colstrip
Montana
6,283
3,895
26.0
7,808*
4,841*
32.3
10,296*
6,383*
16.5
Gillette
Wyoming
5,823
3,661
24.4
7,776*
4,821*
32.1
9,227*
5,721*
14.8
Farming ton
New Mexico
7,128
4,419
29.4
8,670*
5,375*
35.8
11,753*
7,130*
18.4
+gallons per calendar minute, 90% load factor
*Phase I results reported in Ref. 1
-------
TABLE 1-1(continued)
LURGI (250 x 10 scf/stream day)
acre-ft/yr
gal/cal min
gal/10 Btu
% of high wet cooling
SYNTHANE (250 x 1Q6 scf/stream day)
acre-ft/yr
gal/cal min
gal/10 Btu
% of high wet cooling
SYNTHOIL (100,000 bbl/stream day)
acre-ft/yr
gal/cal min
c
gal/10 Btu
% of high wet cooling
Beulah
North Dakota
3,307*
2,050*
13.7
68
5,878
3,644
24.3
77
8,170
5,065
13.1
81
Colstrip
Montana
4,618*
2,863*
19.1
74
5,923
3,672
24.5
76
8,481
5,258
13.6
82
Gillette
Wyoming
4,206*
2,608*
17.4
71
5,875
3,642
24.3
76
7,539
4,674
12.1
82
na.va.ju/
Farmington
New Mexico
5,639*
3,496*
23.3
79
6,694
4,155
27.7
77
9,655
5,986
15.4
84
+gallons per calendar minute, 90% load factor
*Phase I results reported in Ref. 1
-------
TABLE 1-1 (concluded)
LURGI (250 x 105 -scf/stream day)
acre-ft/yr
gal/ cal min
gal/10 Btu
% of high wet cooling
SYNTHANE (250 x 10 scf/stream day)
acre-ft/yr
gal/ cal min
gal/106 Btu
% of high wet cooling
SYNTHOIL (100,000 bbl/stream day)
acre-ft/yr
gal/ cal min
gal/106 Btu
% of high wet cooling
Beulah
North Dakota
2,853
1,769
11.8
58
5,520
3,422
22.8
72
7,552
4,682
12.1
75
Colstrip
Montana
4,142
2,568
17.1
66
5,536
3,432
22.9
71
7,904
4,900
12.6
77
Gillette
Wyoming
3,721
2,307
15.1
63
5,484
3,400
22.7
71
7,026
4,356
11.2
76
mexvetju/
Farmington
New Mexico
5,213
3,232
21.5
73
6,289
3,899
26.0
73
9,112
5,649
14.6
79
+gallons per calendar minute, 90% load factor
-------
all oil shale processes. These results are shown in Table 1-2 for both the
net water consumed and solid residuals generated. The calculations for the
TOSCO II process have been refined and are also shown on Table 1-2.
In general the net water requirements normalized with respect to the
product output are largest for coal gasification followed in turn by coal
liquefaction. For intermediate wet cooling the water requirements for the
Paraho Direct process are comparable with the Synthoil process, which roughly
produces the same product. However, the Paraho Indirect and TOSCO II processes
have the largest net water requirements due mainly to the larger requirements
for spent shale disposal and revegetation.
For steam-electric power generation, wet/dry cooling was examined for
Navajo/Farmington, New Mexico and Beulah, North Dakota. The optimum costs
for New Mexico were slightly higher than those at North Dakota, generally not
exceeding 10 percent. The point at which the cost of the wet/dry cooling
system is optimum occurs when the evaporation rate is approximately 15 percent
of the evaporation rate for all wet cooling. This optimum point is the same
at both sites and the result was extended to include all six study sites.
Table 1-3 shows the total water consumed for all wet cooling and the
optimum wet/dry cooling system for steam electric power generation. The
estimates for all wet cooling represent consumptive water use for well managed
power plants in the Western and Southwestern regions of the country- A
reduction of 85% in the cooling water requirements reduces the total water
consumed by a plant by 68-75 percent. However, the changeover water costs,
i.e. the cost of water above which wet/dry cooling would be used, range from
$3.65 to $5.87 per 1000 gals evaporated for power generation plants, much
higher values than those for coal conversion plants producing synthetic
fuels. The busbar energy cost penalty in using wet/dry cooling instead of all
wet cooling ranges from 1.4 mils/kw-hr to 1.97 mils/kw-hr for Navajo,,New
Mexico and 1.2 mils/kw-hr to 1.9 mils/kw-hr for Beulah, North Dakota, compared
to the cost of electricity of 20 to 30 mils/kw-hr.
In the site studies discussed in Section 1.3, on a purely economic
basis either intermediate cooling or minimum practical cooling is
desirable for most of the Western sites for coal or oil shale conversion.
For steam-electric power plants, if only the costs of water are considered,
then all wet cooling would be desired, since wet/dry cooling is so capital
-------
TABLE 1-2 NET WATER CONSUMED AND WET-SOLID RESIDUALS
GENERATED FOR OIL SHALE CONVERSION
PARAHO DIRECT (100,000 bbl/stream day)
Net water consumed
acre ft/yr
gal/stream min
gal/106 Btu
Wet-solid residuals
tons/day
lb/106 Btu
PARAHO INDIRECT (100,000 bbl/stream day)
Net water consumed
acre ft/yr
gal/stream min
gal/10 Btu
Wet-solid residuals
tons/day
lb/106 Btu
TOSCO II (100,000 bbl/stream day)
Net water consumed
acre ft/yr +
gal/stream min
gal/10 Btu
Wet-solid residuals
tons/day
lb/106 Btu
Intermediate Cooling
Rifle, Colorado
5,771
3,578
18
75,000
520
9,233
5,724
28
90,000
620
9,307*
5,770*
29*
60,000
470
+gallons per calendar minute, 90% load factor
*Modified from Phase I calculations (see Ref. 1)
-------
TABLE 1-3 NET WATER CONSUMED AT EACH SITE FOR STEAM-ELECTRIC POWER GENERATION
+"1"
All Wet Cooling Wet/Dry Cooling %
acre-ft/yr gal/stream min acre-ft/yr gal/stream min all wet
Beulah, North Dakota* 23,884
Colstrip, Montana* 26,659
Gillette, Wyoming* 25,842
Kaiparowitz/Escalante,
Utah* 29,816
Navajo/Framington,
New Mexico* 29,206
Rifle, Colorado 9,494
14,807
16,527
16,021
18,483
18,106
5,885
5,494
7,336
6,465
9,481
9,089
2,786
3,406
4,548
4,008
5,878
5,635
1,727
23
28
25
33
31
29
*3,000 MWe @ 35% eff. and 70% load factor
+1,000 MWe @ 35% eff. and 70% load factor
•H-Phase I results reported in Ref. 1.
10
-------
intensive. and the fuel penalty is so high. However, if water is in short
supply, or if there are other pressures for conserving water, then it is
obvious that wet/dry cooling is feasible.
1.3 REGIONAL WATER REQUIREMENTS AND RESIDUALS DISPOSAL
A study was recently completed by Water Purification Associates under
the sponsorship of the U.S. Environmental Protection Agency and the Department
of Energy, in which 42 coal and oil shale conversion plant-site combinations
were studied in the Western states. In order to extend the data base of the
present study, these results are included to provide more meaningful regional
water impact assessments.
Estimates were made of the cost of transporting water to all of the
plant-sites for two limiting cases: low water demand and high water demand.
Low water demand corresponds to a synthetic fuel production rate of approximately
1.0 x 10 barrels/day of synthetic crude, or its equivalent in other fuels of
5.8 x 10 Btu/day, while high water demand corresponds to a synthetic fuel
production rate of approximately 4.0 x 10 barrels/day of synthetic crude, or
12
its equivalent in other fuels of 23.2 x 10 Btu/day. For low water demand
two standard size coal or oil shale conversion plants were assumed to be
located in each of eleven hydrologic regions in the Western states for a
total of 22 plants producing approximately 1.0 x 10 barrels/day of synthetic
crude. For high water demand 1 x 10 barrels/day of synthetic crude, or its
equivalent in other fuels of 5.8 x 10 Btu/day, were produced in each of
three principal coal bearing regions and one oil shale region. Except for
plants located near the mainstem of major rivers or near large reservoirs,
the water transport cost estimates show that intermediate or minimum practical
wet cooling would be desirable for most of the sites for low water demand.
For high water demand, it is more economical to build a large pipeline to
supply water to a large number of plants than to have a large number of
individual pipelines supplying individual plants. The estimates show that
except for large scale development near the mainstem of major rivers, intermediate
cooling would be preferred for most of the sites.
Except for the Synthane process, the results of the limited six site-
specific studies with respect to water consumption are in general agreement
with the results of the more expanded site studies. For Synthane, the major
11
-------
difference is in the degree to which wet cooling was used to dissipate the
unrecovered heat. In Reference 3 a more detailed thermal balance was made
resulting in a reduction in the net water consumed of about 7 gals/10 Btu
below those of Reference 1. The calculations of the total wet solid residuals
reported in Reference 3 are about twice those reported in Reference 1, due
primarily to the much larger quantities of flue gas desulfurization sludge
and water treatment sludge.
Within a given coal region and for a given process, rank of coal and wet
cooling option, differences in the net water consumed from site to site are
not significant. However, within a given region there might be large variations
in water availability and water costs and different cooling options at different
sites will produce large differences in the cooling water consumed and the
plant water requirements. Thus, for a particular process and coal rank, the
cost of water and the particular cooling technology selected for a given
plant are the main factors which determine the water use. Intermediate and
minimum practical wet cooling should be used at most of the sites.
1.4 ECONOMICS OF WATER TREATMENT AND COOLING TOWER SLOWDOWN TREATMENT AND DISPOSAL
Estimates were made of the costs of treating water in a coal gasification
plant for the purpose of recycling and reusing the water for in-plant uses to
minimize the problem of disposal of contaminated waste streams. The main
components of any water treatment plant include: boiler feed water treatment.,
process water or condensate cleanup, and cooling water treatment. Boiler
feed water treatment includes primarily ion exchange. The foul condensate
wastewater is assumed to be treated and blended with water from the river or
used by itself as makeup to the cooling tower. The foul condensate treatment
includes phenol extraction, ammonia separation and biological treatment.
Cooling water treatment includes chemical addition and filtration.
The water treatment costs range from about 8C/10 Btu product energy
output to 12C/10 Btu, while the energy requirements for water treatment
range from about 4 to 6. 5 percent of the product output. The cost of the
product fuel will probably be in the range of $3-4/10 Btu, so that the water
treatment costs, after taking credit for the sale of by-product ammonia, will
not exceed 5 percent of the sale of the product fuel.
12
-------
The total costs and energy requirements for water treatment are primarily
dependent on the costs and energy requirement for process condensate treatment.
The costs of cooling water treatment comprise the lowest costs while boiler
feed water treatment costs are intermediate between the two. The total costs
and energy requirements for water treatment are not very sensitive to the
choice of the cooling option with the costs not varying by more than 10
percent between a high degree of net cooling and minimum practical cooling.
The costs of the treatment and disposal of cooling tower blowdown were
estimates for the case of zero discharge and the case of effluent discharge
to the receiving water, for coal gasification and electric power generation.
For each case the cooling tower was operated at either very few cycles of
concentration (N = 2.5 cycles of concentration) or at very high cycles of
concentration (N = 10). At low cycles of concentration, only chemical treatment
of the circulating cooling water was assumed necessary. At high cycles of
concentration, sidestream softening in a reactor-clarifier was assumed.
Blowdown treatment included treatment by either electrodialysis or vapor
compression, followed by disposal of the brine to the receiving water or to
lined evaporation ponds. In some cases the product water from the electrodialysis
or vapor compression unit was recycled back to the plant with credit taken
for the product water.
For all cases the annual operating and amortization costs decreases as
the cycles of concentration in the cooling tower increases. The costs are
lower for Lurgi than for Synthane for all cases. The lowest costs are for
those cases where there is no limitation on the method of disposing of the
blowdown. This occurs when the blowdown is discharged directly to the receiving
water or where the blowdown is disposed of with coal ash. The cost of
blowdown treatment and disposal are in the range of approximately 0.40C/10
Btu to 0.80C/106 Btu for N = 2.5, and 0.20C/106Btu to 0.35C/106 Btu for N = 10
for coal gasification; and about 0.40 mils/kw-hr for N = 2.5 and 0.15 mils/kw-hr
for N = 10 for steam-electric generation. As a basis for comparison, pipeline
gas is expected to cost about $3-4/10 Btu and electricity costs about 20 to
30 mils/kw-hr.
The cost of treatment and disposal of the blowdown increases if TDS
(total dissolved solids) reduction is required for discharge to the receiving
water. If a single stage electrodialysis system is used to reduce the TDS by
13
-------
50 percent, then the costs increase to 1.25-2.75C/10 Btu for N = 2.5 and
0.35-0.70^/10 Btu for N = 10 for coal gasification; and to 1.35-1.60
hr for N = 2.5 and 0.30-0.40 mils/kw-hr for power generation.
The costs increase further for zero discharge. Three cases were considered
with final disposal of the concentrated brine taking place in lined evaporation
ponds. Of the three cases the least expensive was for blowdown treatment by
3-stage electrodialysis and recycle of the product water back to the plant
for in-plant uses. The costs for this case range from 1.40-2.70C/10 Btu
for N = 2.5 and 0.40-0.70C/10 Btu for N = 10 for coal gasification; and
1.50-1.70 mils/kw-hr for N = 2.5 and 0.40 milsAw-hr for N = 10 for power
generation. If credit is taken for the recycled water, then the costs are
0.65-1.05C/10 Btu (N = 2.5) and 0.30 - 0.35C/1Q6 Btu (N = 10) for coal
gasification; and 0.70-1.05 mils/kw-hr (N = 2.5) and 0.20-0.30 mils/kw-hr (N
= 10) for power generation.
The costs for a vapor compression brine concentrator were the next
expensive, ranging from 6.50-12.30C/10 Btu (N = 2.5) and 1.20-2.30C/10 Btu
(N = 10) for coal gasification; and 6.90-7.30 milsA^-hr (N = 2.5) and 1.20-
1.40 mils/kw-hr (N = 10) for power generation. If credit is taken for recycle,
then these costs would be reduced by approximately 0.80-1.50C/10 Btu (N = 2.5)
and 0.15-0.30C/10 Btu (N = 10) for coal gasification; and by 0.70-0.80 milsAw-hr
(N = 2.5) and 10 mils/kw-hr (N = 10) for power generation.
The most expensive case was for complete blowdown disposal into lined
evaporation ponds without blowdown treatment. The costs are 4.80-14.0<:/10
Btu (N = 2.5) and 0.90-2.50C/10 Btu (N = 10) for coal gasification; and
6.00-9.50 milsAw-hr (N = 2.5) and 1.10-1.60 mils/kw-hr (N = 10) for power
generation.
REFERENCES (Section 1)
1. Gold, H., et al, "Water Requirements for Steam-Electric Power Generation
and Synthetic Fuel Plants in the Western United States," EPA Report No.
600/7-77-037, Environmental Protection Agency, Washington, D. C., April 1977.
2. Science and Public Policy Program, University of Oklahoma, "Energy from
the West: A Progress Report of a Technology Assessment of Western Energy
Resource Development," EPA Report No. 600/7-77-072, Environmental Protection
Agency, Washington, D. C., July 1977.
/
3. Gold, H. and Goldstein, D.J., "Water Related Environmental Effects in Fuel
Conversion: Summary Volume and Appendix Volume," Environmental Protection
Agency, Research Triangle Park, N.C., EPA Report No. 600/7-78-197a,b,
October 1978.
14
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2. SELECTED ASPECTS OF WET/DRY COOLING
2.1 INTRODUCTION AND CONCLUSIONS
2.1.1 Introduction
Evaporation for cooling can be a major consumptive use of water in coal
conversion and generating plants . In coal conversion plants, the heating
value in the raw material not recovered in the synthetic fuel or the byproducts
must be transferred to the environment. Some of this unrecovered heat is lost
directly to the atmosphere, leaving the plant in hot gases up a flue, in water
vapor from coal drying, in convective and radiant losses from machinery and
container surfaces, and in other direct ways. However, the largest fraction
of the unrecovered heat is indirectly transferred to the atmosphere. The heat
to be dissipated may be transferred through a heat transfer surface that is
cooled by air. This is called dry cooling, or air cooling, and negligible
water consumption is incurred in this method. Alternatively, the heat transfer
surface may be cooled by circulating water, which is itself cooled in a cooling
tower with evaporation to the atmosphere of a fraction of the water. This is
called wet cooling, or evaporative cooling. We are concerned in this section
with these two methods of cooling or their use in combination, termed wet/dry
cooling.
Under the same conditions an air cooled heat exchanger transfers less
heat per unit area than a water cooled exchanger. Therefore, to transfer a
given amount of heat, air cooling requires a larger surface area. Air coolers
thus have a higher capital cost. Moreover, an air cooled system cannot usually
reach temperatures as low as those in a water cooled system and, hence, the
efficiency of conversion will be lower if air cooling is used to any great
extent.
15
-------
Wet cooling is less capital intensive and, in general, is less expensive
to operate than dry cooling. Wet cooling, however, does require water, and
water is not free. To move one thousand gallons of water one mile through a
horizontal pipeline costs one to two cents. To treat water in a circulating
cooling system and to dispose of the residues can cost $0.50 to $1.00 per
thousand gallons of water evaporated . The economic decision of whether to
use wet or dry cooling, or a combination, at any given point of cooling in the
plant depends on the true cost of water. This must include any costs to buy
water rights and to transport the water to the plants, as well as the cost to
treat the circulating cooling water and to dispose of the cooling tower residues.
The economics must be calculated for each type of cooling load in the
plant. Major cooling loads have been classified , and Table 2-1 (taken from
Reference 3) shows the classification for a typical substitute natural gas
plant. More generally, types of cooling loads can be classified with the
choice of wet or dry cooling as:
»<•
Cooling of intermediate and Dry cooling to 140°F and
product gas .and liquid wet cooling below this
process streams. temperature.
Gas purification regenerator Dry or wet/dry, dependent
condenser. on choice of purification
system.
Off-gas scrubbing and quenching. .Dry.
Condensers for steam turbines. Evaluated here.
Gas compressor interstage coolers. Evaluated here.
In the above list the cooling method has been assigned to the first three
•classifications for reasons given in detail in References 2 and 3. In steam
generating plants the principal cooling load is for steam turbine condensers.
In a previous study , steam turbine condensers and gas compressor interstage
coolers for coal conversion plants were assumed to be all wet cooled, while a
partial evaluation was made of the wet/dry cooling of steam turbine condensers
for power generating plants. Condensers for steam turbines in coal conversion
and in generating plants are one of the subjects of this study. Gas compressor
interstage coolers in coal conversion plants is the other subject. In a study
4
just completed , detailed calculational procedures were presented for the cooling
of steam turbine condensers and air compressor interstage coolers and calculations
16
-------
TABLE 2-1. SUMMARY OF THE CHOICE OF WET OR DRY COOLING AND APPROXIMATE AMOUNT OF EVAPORATED
WATER FOR AN SNG PLANT PRODUCING 250 X 10 SCF/DAY IN NEW MEXICO AND WYOMING
Point
Gas purification (hot potassium
carbonate) Regenerator condenser
Pump drive
i*
Off-gas scrubbing & quenching
Boiler steam generation
Oxygen production
Air compressor intercoolers
Oxygen compressor intercoolers
Turbine condensers
Electric power generation
Turbine condensers
Electricity
Coal drying (lignite)
Product cooling & drying
TOTALS
Load
(109 Btu/hr)
1.3
0.15
1.1
0.4
0.2
0.1
-0.6
0.12
0.02
0.5
0.14
Breakeven
Evaporated
Water Cost
($/103 gal)
0.46
zero
no cooling
9.4
3.3
2.6
no cooling
no cooling
zero 85%
14%
Wet
or
Dry
Dry
Wet
Dry
Wet
Wet
Wet
Wet
Dry
Wet
Evaporated Water
N.M. W.Y.O.
(106 gal/day) (1Q6 qal/day)
0.39 0.33
0.53 0.45
0.26 0.22
1.57 1.33
0.31 0.27
0.05 0.04
4.67
3.11
2.64
From Reference 3
-------
carried out for Farmington, New Mexico, Casper, Wyoming and some eastern sites
and for a given set of unit costs. The procedures are also discussed in this
report and the calculations extended to include Beulah, North Dakota and other
sets of unit costs. Calculations are also presented for hydrogen compressor
interstage coolers at the three western sites. The technical discussion and
the results of the calculations will be found in the four following subsec-
tions. Economic calculations and our conclusions are given next.
2.1.2 Economics of Cooling Turbine Condensers in Coal Conversion Plants
Unit costs are shown on Table 2-2. Set number 1 is the base set; the
other two sets show variations. There are three types of unit costs. The
capital costs are for a 1980 start, which means that they are 1977 equipment
costs with erection spread over the next two years. The capital costs will
increase with time. More importantly, the capital costs do not change uniformly^
so the relationship between capital costs of dry coolers and capital costs of
cooling towers and wet coolers changes. We are not able to predict these
changes, and no variations in capital costs have been considered.
The amortization and maintenance rates shown for set number 1 are reason-
able for commercial enterprises today. Lower values are used in set number 3
to illustrate the effect of possible lower interest rates for utilities.
The energy costs shown for set number 1 are reasonable for today, and
quite low. Energy costs, double those used in set number 1, are used in set
number 2.
Using the unit costs and the summary of calculated results for wet/dry
condenser cooling from Section 2.2, annual average costs, tabulated on Table
2-3, were calculated according to the following examples:
2 2
Dry condenser cost K/kw-hr) = (area, ft /kw) (cost,
-------
Condensers and
heat exchanger:
Dry cooling
Wet cooling
TABLE 2-2. UNIT COSTS
SET NUMBER 1
Cost
2*
Other:
Cooling tower
Electrical energy
Steam
$22/ft
$11.0/ft
$12.I/ft"
$13.2/ft'
$19.2/ft"
$20/gpm circulated
2C/kw-hr
Pressure
(p,psig)
Annual Charges
for Amortization
Plus Maintenance
p < 300
300 < p < 450
450 < p < 600
p _> 600
17%/yr
20%/yr
15%/yr
$1.80/10 Btu
SET NUMBER 2
As Set Number 1, but
Electrical energy
Steam
4C/kw-hr
$3.60/10 Btu
SET NUMBER 3
As Set Number 1, but
Dry cooled heat exchangers
Wet cooled heat exchangers
Cooling towers
13%/yr
16%/yr
11%/yr
*Based on bare tube area of finned tubes.
19
-------
TABLE 2-3. ANNUAL AVERAGE COSTS FOR WET/DRY CONDENSER COOLING
UNIT COSTS - SET NO. 1
Farmington, New Mexico
Fraction designed dry 0.95
Dry condenser cost C/kw-hr 0.156
Wet condenser cost C/kw-hr 0.0031
Electric energy C/kw-hr 0.024
Fuel penalty C/kw-hr 0
Cooling tower C/kw-hr 0.0015
Total C/kw-hr 0.185
Avg water consumption gal/kw-hr 0
0.75 0.50
0.123 0.082
0.016 0.031
0.032 0.046
0 0.0008
0.0075 0.015
0.179 0.175
0.014 0.101
0.25 0
0.041 0
0.047 0.063
0.054 0.046
0.0075 0.0285
0.022 0.030
0.172 0.167
0.374 0.707
Casper, Wyoming
Fraction designed dry
Dry condenser cost C/kw-hr
Wet condenser cost C/kw-hr
Electric energy C/kw-hr
Fuel penalty £/kw-hr
Cooling tower <=/kw-hr
Total C/kw-hr
Avg water consumption gal/kw-hr
0.95
0.148
0.0031
0.020
0
0.0015
0.173
0
0.75 0.50
0.117 0.078
0.016 0.031
0.028 0.042
0 0
0.0075 0.015
0.168 0.166
0.008 0.088
0.25 0
0.039 0
0.047 0.063
0.054 0.046
0.0064 0.035
0.022 0.030
0.169 0.174
0.362 0.701
Beulah, North Dakota
Fraction designed dry
Dry condenser cost C/kw-hr
Wet condenser cost C/kw-hr
Electric energy C/kw-hr
Fuel penalty C/kw-hr
Cooling tower C/kw-hr
Total C/kw-hr
Avg water consumption gal/kw-hr
0.?5 0.50 0.25 0
0.139 0.092 0.046 0
0.016 0.031 0.047 0.063
0.024 0.036 0.056 0.044
0 0 0.002 0.025
0.007 0.015 0.022 0.030
0.185 0.175 0.174 0.162
0 0.058 0.265 0.671
20
-------
TABLE 2-3. (continued)
UNIT COSTS - SET NO. 2
Farmington, New Mexico
Fraction designed dry 0.95 0.75 0.50 0.25 0
Dry condenser cost C/kw~hr 0.156 0.123 0.082 0.040 0
Wet condenser cost C/kw-hr 0.0031 0.016 0.031 0.047 0.063
Electric energy C/kw-hr 0.048 0.064 0.092 0.108 0.092
Fuel penalty C/kw-hr 0 0 0.0016 0.0015 0.057
Cooling tower C/kw-hr 0.0015 0.0075 0.015 0.022 0.030
Total C/kw-hr 0.209 0.211 0.222 0.232 0.247
Avg water consumption gal/kw-hr 0 0.014 0.101 0.374 0.707
Casper, Wyoming
Fraction designed dry 0.95 0.75 0.50 0.25 0
Dry condenser cost C/kw-hr 0.148 0.117 0.078 0.039 0
Wet condenser cost C/kw-hr 0.0031 0.016 0.031 0.047 0.063
Electric energy C/kw-hr 0.040 0.056 0.084 0.108 0.092
Fuel penalty C/kw-hr 000 0.013 0.070
Cooling tower C/kw-hr 0.0015 0.0075 0.015 0.027 0.030
Total C/kw-hr 0.193 0.197 0.208 0.229 0.255
Avg water consumption gal/kw-hr 0 0.008 0.088 0.362 0.701
Beulah, North Dakota
Fraction designed dry 0.75 0.50 0.25 0
Dry condenser cost C/kw-hr 0.139 0.092 0.046 0
Wet condenser cost C/kw-hr 0.016 0.031 0.047 0.063
Electric energy C/kw-hr 0.048 0.072 0.112 0.088
Fuel penalty C/kw-hr 0 0 0.004 0.050
Cooling tower C/kw-hr 0.007 0.015 0.022 0.030
Total C/kw-hr 0.21 0.215 0.231 0.231
Avg water consumption gal/kw-hr 0 0.058 0.265 0.671
21
-------
TABLE
2-3. (concluded)
UNIT COSTS - SET NO. 3
Farmington, New Mexico
Fraction designed dry 0.95 0.75 0.50 0.25 0
Dry condenser cost C/kw-hr 0.119 0.094 0.063 0.029 0
Wet condenser cost C/kw-hr 0.0023 0.012 0.023 0.035 0.047
Electric energy C/kw-hr 0.024 0.032 0.046 0.057 0.046
Fuel penalty C/kw-hr 0 0 0.0008 0.0075 0.0285
Cooling tower C/kw-hr 0.0011 0.0055 0.011 0.016 0.022
Total C/kw-hr 0.146 0.144 0.144 0.144 0.144
Avg water consumption gal/kw-hr 0 0.014 0.101 0.374 0.707
Casper, Wyoming
Fraction designed dry 0.95 0.75 0.50 0.25 0
Dry condenser cost C/kw-hr 0.113 0.089 0.060 0.030 0
Wet condenser cost C/kw-hr 0.0023 0.012 0.023 0.035 0.047
Electric energy C/kw-hr 0.020 0.028 0.042 0.054 0.046
Fuel penalty C/kw-hr 000 0.0064 0.035
Cooling tower C/kw-hr 0.0011 0.0055 0.011 0.016 0.022
Total C/kw-hr 0.136 0.135 0.136 0.141 0.150
Avg water consumption gal/kw-hr 0 0.008 0.088 0.362 0.701
Beulah, North Dakota
Fraction designed dry 0.75 0.50 0.25 0
Dry condenser cost C/kw-hr 0.100 0.070 0.035 0
Wet condenser cost C/kw-hr 0.012 0.023 0.035 0.047
Electric energy C/kw-hr 0.024 0.036 0.056 0.044
Fuel penalty C/kw-hr 0 0 0.002 0.025
Cooling tower C/kw-hr 0.0055 0.011 0.016 0.022
Total C/kw-hr 0.142 0.140 0.144 0.138
Avg water consumption gal/kw-hr 0 0.058 0.265 0.671
22
-------
0.3
0.25
5= 0.2
S3
0.15
0.1
UNIT COSTS - SET NO. 1
\
\
o
a
0.5 »
CO
UJ
a
o
S
0
0.2 0.4 0.6
WATER CONSUMPTION, GAL/KW-HR
0.8
Figure 2-1. Cost of steam turbine condenser cooling in Farmington,
New Mexico.
23
-------
0.30
0.25
Of
:r
i
oo
o
CJ
0.20
0.15
0.10
\r
UNIT COSTS - SET NO. 1
I
0.5
ce
Q
LL)
O
0
0
0.2 0.4 0.6
WATER CONSUMPTION, GAL/KW-HR
0.8
Figure 2-2. Cost of steam turbine condenser cooling in Casper, Wyoming.
24
-------
0.35
0.30
0.25
0.20
0.15
0.1
UNIT COSTS - SET NO. 1
WATER COST, $/1000 GAL
l.i
t
1.0
ex:
o
Q
0.5
•a:
ex:
0.2 0.4 0.6 0.8
WATER CONSUMPTION, GAL/KW-HR
Figure 2-3. Cost of steam turbine condenser cooling in
Beulah, North Dakota.
25
-------
100
o
o
o
o
0
o:
UJ
80
40
20
UNIT COSTS - SET NO. 1
CASPER
Beulah
I ^
V
10
20
30
40
WATER COST, CENTS/100 GAL
Figure 2-4. The effect of water cost on water consumed
for cooling turbine condensers.
26
-------
shows that when water costs more than about 2CK/10 gal/ combined wet/dry
cooling should be used and the water consumption will be less than 10 percent
of the consumption with all wet cooling.
For sets numbers 2 and 3, graphs are not necessary. At most sites the
total cost increases as the fraction of wet cooling increases, even when water
is free. In no case will wet cooling be used if water costs more than IOC/10
gal—and water always costs more than IOC/10 gal. Of course, small wet
coolers must be provided for use during the daylight hours of the hottest
summer days, but the annual water consumption for cooling will be close to
zero.
The following conclusions apply for the cooling of condensers for steam
turbines in coal conversion plants:
1) There is an excellent chance of saving money and water by using
combined wet/dry condensers on condensing steam turbine drives; calculations
should be made for all designs.
2) For most western sites, when water is not very abundant and not very
cheap the water consumption estimates should be made on the assumption that
parallel wet/dry condensers will be used on turbine drives and that the average
water consumption will be less than 10 percent of the consumption for all-wet
cooled condensers.
2.1.3 Economics of Cooling Air Compressors in Coal Conversion Plants
The three sets of unit costs on Table 2-2 were used with the summary of
calculated results on wet/dry interstage cooling of an air compressor (from
Section 2.3) to calculate the annual average costs tabulated on Table 2-4.
The cost of compression energy in C/kw-hr is found by multiplying the steam
cost in C/Btu by 11,700 Btu/kw-hr. As with turbine condensers, note that the
"total costs" (C/1000 lb) refer only to those costs dependent on the choice of
the cooling system. Other cost components such as the purchase of the compressors
are omitted.
The results are presented graphically on Figures 2-5 to 2-8 for unit cost
set number 1, on Figures 2-9 to 2-12 for unit cost set number 2, and on
Figures 2-13 to 2-16 for unit cost set number 3. Figures 2-8, 2-12 and 2-16
summarize the results for each of the three unit cost sets. From these figures
27
-------
TABLE 2-4. ANNUAL AVERAGE COST FOR WET/DRY COMPRESSOR INTERSTAGE
COOLING FOR AIR COMPRESSORS
UNIT COSTS - SET NO. 1
Farmington, New Mexico
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, °F 140 160 180 all wet
Dry cooler cost, C/1000 Ib 3.123 2.139 1.432 0
Wet cooler cost, C/1000 Ib 2.367 2.633 2.861 3.346
Tower cost, C/IOOO Ib 0.081 0.131 0.180 0.319
Fan and pump energy, C/1000 Ib 1.408 1.102 0.88 0.498
Compression energy cost, C/1000 Ib 58.164 58.538 58.734 59.246
Total, C/1000 Ib compressed 65.142 64.543 64.088 63.409
Water consumed, gal/1000 Ib 0.851 1.929 3.097 7.215
Casper, Wyoming
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, °F 140 160 180 all wet
Dry cooler cost, C/1000 Ib 2.886 2.100 1.259 0
Wet cooler cost, C/1000 Ib 2.367 2.633 2.861 3.332
Tower cost, C/1000 Ib 0.081 0.131 0.180 0.314
Fan and pump energy, C/1000 Ib 1.316 1.084 0.808 0.490
Compression energy cost, C/1000 Ib 57.921 58.210 58.629 58.949
Total, C/1000 Ib compressed 64.571 64.157 63.738 63.085
Water consumed, gal/1000 Ib 0.868 1.779 3.275 6.965
Beulah, North Dakota
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, °F 140 160 180 all wet
Dry cooler cost,'C/1000 Ib 3.484 2.354 1.561 0
Wet cooler cost, C/1000 Ib 2.365 2.645 2.886 3.454
Tower cost, C/1000 Ib 0.081 0.131 0.180 0.347
Fan and pump energy, C/1000 Ib 1.528 1.152 0.910 0.590
Compression energy cost, C/1000 Ib 57.035 57.643 57.755 58.235
Total, C/1000 Ib compressed 64.493 63.926 63.292 62.626
Water consumed, gal/1000 Ib 0.584 1.447 2.221 6 686
28
-------
TABLE 2-4. (continued)
UNIT COSTS - SET NO. 2
Farmington, New Mexico
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, °F 140 160 180 all wet
Dry cooler cost, C/1000 Ib 3.122 2.138 1.432 0
Wet cooler cost, C/1000 Ib 2.367 2.633 2.861 3.346
Tower cost, C/1000 Ib 0.081 0.131 0.180 0.319
Fan and pump energy, C/1000 Ib 2.816 2.204 1.760 0.996
Compression energy cost, C/1000 Ib 116.327 117.077 117.468 118.492
Total, C/1000 Ib compressed 124.721 124.183 123.701 123.153
Water consumed, gal/1000 Ib 0.851 1.929 3.097 7.215
Casper, Wyoming
Basis: 1000 Ib air compressed/hr :
Design intermediate temperature, °F 140 160 180 all wet
Dry cooler cost, <=/1000 Ib 2.885 2.100 1.259 0
Wet cooler cost, C/IOOO Ib 2.367 2.633 2.861 3.332
Tower cost, C/1000 Ib 0.081 0.131 0.180 0.314
Fan and pump energy, C/1000 lt> 2.632 2.168 1.616 0.980
Compression energy cost, C/1000 Ib 115.843 116.420 117.278 117.898
Total, C/1000 Ib compressed 123.808 123.452 123.194 122.524
Water consumed, gal/1000 Ib 0.868 1.779 3.275 6.965
Beulah, North Dakota
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, °F 140 160 180 all wet
Dry cooler cost, C/IOOO Ib 3.484 2.354 1.561 0
Wet cooler cost, C/1000 Ib 2.365 2.645 2.886 3.454
Tower cost, C/1000 Ib 0.081 0.131 0.180 0.347
Fan and pump energy, C/1000 Ib 3.056 2.304 1.820 1.180
Compression energy cost, C/1000 Ib 114.069 115.287 115.510 116.470
Total, C/1000 Ib compressed 123.056 122.721 121.957 121.451
Water consumed, gal/1000 Ib 0.584 1.447 2.221 6.686
29
-------
TABLE 2-4. (concluded)
UNIT COSTS - SET NO. 3
Farmington, New Mexico
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, °F 140 160 180 all wet
Dry cooler cost, C/1000 Ib 2.387 1.635 1.095 0
Wet cooler cost, C/1000 Ib 1.893 2.106 2.289 2.677
Tower cost, C/1000 Ib 0.059 0.096 0.132 0.234
Fan and pump energy, C/1000 Ib 1.408 1.102 0.880 0.498
Compression energy cost, C/1000 Ib 58.164 58.538 58.734 59.249
Total, C/1000 Ib compressed 63.911 63.478 63.130 62.655
Water consumed, gal/1000 Ib 0.851 1.929 3.097 7.215
Casper, Wyoming
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, °F 140 160 180 all wet
Dry cooler cost, C/1000 Ib 2.206 1.605 0.962 0
Wet cooler cost, C/1000 Ib 1.893 2.106 2.289 2.665
Tower cost, C/IOOO Ib 0.059 0.096 0.132 0.230
Fan and pump energy, C/1000 Ib 1.316 1.084 0.808 0.490
Compression energy cost, C/1000 Ib 57.921 58.210 58.629 58.949
Total, C/1000 Ib compressed 63.396 63.101 62.821 62.334
Water consumed, gal/1000 Ib 0.868 1.779 3.275 6.965
Beulah, North Dakota
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, °F 140 160 180 all wet
Dry cooler cost, C/1000 Ib 2.664 1.800 1.194 0
Wet cooler cost, C/1000 Ib 1.892 2.116 2.309 2.763
Tower cost, C/1000 Ib 0.59 0.096 0.132 0.254
Fan and pump energy, C/1000 Ib 1.528 1.152 0.910 0.590
Compression energy cost, C/1000 Ib 57.035 57.643 57.755 58.235
Total, C/1000 Ib compressed 63.179 62.808 62.300 61.843
Water consumed, gal/1000 Ib 0.584 1.447 2.221 6.686
30
-------
66
65
ca
o
o
o
(S)
o
o
64
UNIT COST - SET NO. 1
246
WATER CONSUMPTION, GAL/1,000 LB
Figure 2-5. Cost of interstage cooling-for compressing 1,000 Ib
air at Farmington, New Mexico. (Unit cost - Set No. 1)
31
U.S EPA Headquarters Library
Mail code 3404T
1200 Pennsylvania Avenue NW
Washington, DC 20460
202-566-0556
-------
o
o
o
GO
o
66
65
64
f
0
UNIT COSTS - SET NO. 1
I
246
WATER CONSUMPTION, GAL/1,000 LB
8
Figure 2-6. Cost of interstage cooling for compressing 1,000 Ib air
at Casper, Wyoming. (Unit cost - set No. 1)
32
-------
66
o
o
o
OO
o
o
65
64
UNIT COSTS - SET NO. 1
WATER COST $/1000 GALS
8
WATER CONSUMPTION, GAL/1000 LB
Figure 2-7. Cost of interstage cooling for compressing 1,000 Ib
air at Beulah, North Dakota.(Unit cost - Set No.l)
33
-------
CJ3
O
O
o
O
O
a:
t—
«c
o
c_>
a:
LU
•a:
100
80
60
40
20
UNIT COSTS - SET NO.l
CASPER
100
150
200
250
WATER COST, CENTS/10"3 GAL
Figure 2-8. The effect of water cost on water consumed for
interstage cooling when compressing 1,000 Ib air. (Unit cost - Set No.l)
34
-------
126
125
CO
o
o
o
oo
o
o
124
1
UNIT COSTS - SET NO. 2
WATER COST $/1000 GALS
8
WATER CONSUMPTION, GAL/1000 LB
Figure 2-9. Cost of interstage cooling for compressing 1000 Ib air
at Farmington, New Mexico. (Unit cost - Set No. 2)
35
-------
126
o
o
o
I/O
o
125
UNIT COSTS - SET NO. 2
WATER COST $/1000 GALS
2.50.
WATER CONSUMPTION, GAL/1000 LB
Figure 2-10. Cost of interstage cooling for compressing 1000 Ib air
at Casper, Wyoming. (Unit cost - Set No. 2)
36
-------
125
124
CD
CD
CD
-fc>-
GO
O
CJ
•a:
CD
0
UNIT COSTS - SET NO. 2
WATER COST, $/1000 GALS
WATER CONSUMPTION, GAL/1000 LB
8
Figure 2-11. Cost of interstage cooling for compressing 1000 Ib air
at Beulah, North Dakota. (Unit cost - Set No. 2)
37
-------
100
CJ
o
o
o
80
o
LU
oo
o
o
CC
60
3 40
i/>
z:
o
01
LU
20
UNIT COSTS - SET NO. 2
FARMINGTON
BEULAH
100
150
200
250
WATER COST, CENTS/100 GAL
Figure 2-12. The effect of water cost on water consumed for
interstage cooling when compressing 1000 Ib air. (Unit cost - Set No. 2)
38
-------
65
64
o
o
o
LO
CD
63
UNIT COSTS - SET NO. 3
WATER COST S/1000 GALS
WATER CONSUMPTION, GAL/1000 LB
Figure 2-13. Cost of interstage cooling for compressing 1000 Ib air
at Fannington, New Mexico. (Unit cost - Set No. 3)
39
-------
65
CO
o
o
o
CO
o
o
«=c
o
64
63
UNIT COSTS - SET NO. 3
WATER COST $/1000 GALS
2.50
WATER CONSUMPTION, GAL/1000 LB
Figure 2-14. Cost of interstage cooling for compressing 1000 Ib air
at Casper, Wyoming. (Unit cost - Set No. 3)
40
-------
65
64
o
o
o
-fc>-
to
o
63
UNIT COSTS - SET NO. 3
WATER COST $/1000 GALS
WATER CONSUMPTION, GAL/1000 LB
Figure 2-15. Cost of interstage cooling for compressing 1000 Ib air
at Beulah, North Dakota (Unit cost - Set No. 3)
41
-------
100
s-s
o
o
80
60
O
O
CCL
UJ
g
Q
40
o
CtL
LU
< 20
FARMINGTON
BEULAH
UNIT COSTS - SET NO. 3
100
150
200
250
WATER COST/CENTS/100 GAL
Figure 2-16. The effect of water cost on water consumed for interstage cooling
when compressing 1000 Ib air. (Unit cost - Set No. 3)
42
-------
we can draw the following conclusions which, it must be remembered, apply to a
compressor compressing air from atmospheric pressure to 90 psia:
I) There is cost of water above which it pays to use dry followed by wet
interstage cooler. This cost of water is high, but not ridicuously high; for
our unit costs the change occurs when water costs between $1.00 and $1.50 per
10 gallons.
2) Should energy costs increase more than the capital costs, partial dry
cooling will be introduced at lower costs of water.
3) For some western sites, where water is moderately expensive and
moderately scarce, water consumption estimates should be made on the assump-
tion that series dry/wet interstage coolers are used. The water consumption
will be 50 to 60 percent of the consumption for all wet coolers.
2.1.4 Economics of Cooling Hydrogen Compressors in Coal Conversion Plants
The three sets of unit costs on Table 2-2 were used with the summary of
calculated results on wet/dry interstage cooling of a hydrogen compressor,
from Section 2.4, to calculate the annual average costs tabulated on Table 2-
5.
A single cost graph has been prepared for Farmington, New Mexico using
unit costs set number 1. Figure 2-17 shows not only the total cost but also
the capital cost (dry area plus wet area plus cooling tower), the auxiliary
fan and pump energy cost, and the compression energy cost. Although the cost
scales are different for different curves, the difference is only in a dis-
placement of zero; the scale intervals are the same for all the curves. This
makes it simple to see that changes in the cost of compression energy dominate
the other changes in cost. The molecular weight of hydrogen is very low and
compression energy is very high. When dry interstage coolers are compared to
wet coolers, it is found that dry cooling gives a lot lower temperature in
winter than does wet cooling, but that wet cooling is not so much more effective
than dry cooling in the summer.
For all unit cost sets studied, at all sites, dry cooling is preferred.
Small wet coolers will be installed for use on the hottest days of the year,
but for estimating purposes, interstage coolers on the hydrogen compressor
studied can be assumed to consume no water.
43
-------
TABLE 2-5. ANNUAL AVERAGE COST FOR WET/DRY COMPRESSOR INTERSTAGE
COOLING FOR HYDROGEN COMPRESSORS
UNIT COSTS - SET NO. 1
Farmington, New Mexico
Basis: 1000 Ib hydrogen compressed/hr
Design intermediate temperature, °F all dry 140 160 180 all wet
Dry cooler cost, C/1000 lb 11.623 7.261 5.472 4.162 0
Wet cooler cost,
-------
TABLE 2-5. (continued)
UNIT COSTS - SET NO. 2
Farmington, New Mexico
Basis: 1000 Ib hydrogen compressed/hr
Design intermediate temperature, °F all
Dry cooler cost, C/1000 Ib 11.
Wet cooler cost, C/1000 Ib 0
Tower cost, C/1000 Ib 0
Fan and pump energy, C/1000 Ib 11.
Compression energy cost, C/1000 Ib 2239.
Total, */1000 Ib compressed 2262.
Water consumed, gal/1000 Ib 0
Casper,
Basis: 1000 Ib hydrogen compressed/hr
Design intermediate temperature, °F
Dry cooler cost, C/1000 Ib
Wet cooler cost, C/1000 Ib
Tower cost, C/1000 Ib
Fan and pump energy, C/1000 Ib
Compression energy cost, C/1000 Ib
Total, C/1000 Ib compressed
Water consumed, gal/1000 Ib
dry 140
623 7.261
4.395
0.736
324 9.372
68 2267.0
6 2288.8
10.253
Wyoming
all dry
11.145
0
0
10.850
2272.2
2294.2
0
160
5.472
4.986
1.211
9.116
2332.4
2353.1
20.937
160
5.373
4.986
1.211
9.020
2279.3
2300.0
19.816
180 all
4.162 0
5.474 7.
1.47] 4.
9.660 13.
2334.5 2355.
2355.3 2380.
27.684 107.
all wet
0
7.142
4.311
13.464
2362.3
2387.2
106.801
wet
142
311
404
2
1
93S
Beulah, North Dakota
Basis: 1000 Ib. hydrogen compressed/hr
Design intermediate temperature, °F
Dry cooler cost, C/1000 Ib
Wet cooler cost, C/1000 Ib
Tower cost, C/1000 Ib
Fan and pump energy, C/1000 Ib
Compression energy cost, C/1000 Ib
Total, C/1000 Ib compressed
Water consumed, gal/1000 Ib
all dry
12.785
0
0
12.452
2251.0
2276.3
0
160
5.669
4.986
1.211
9.308
2319.1
2340.3
16.6
all wet
0
7.142
4.311
13.464
2351.4
2376.3
107
o
45
-------
TABLE 2-5. (concluded)
UNIT COSTS - SET NO. 3
Farmington ,
Basis: 1000 Ib hydrogen compressed/hr
New Mexico
Design intermediate temperature, °F all dry 140
Dry cooler cost, C/1000 Ib 8
Wet cooler cost, C/1000 Ib 0
Tower" cost, C/1000 Ib 0
Fan and pump energy, C/1000 Ib 5
Compression energy cost, C/1000 Ib 1119
Total, C/1000 Ib compressed 1128
Water consumed, gal/1000 Ib 0
Casper,
Basis: 1000 Ib hydrogen compressed/hr
Design intermediate temperature, °F
Dry cooler cost, */1000 Ib
Wet cooler cost, C/1000 Ib
Tower cost, C/1000 Ib
Fan and pump energy, C/1000 Ib
Compression energy cost, C/1000 Ib
Total, <=/1000 Ib compressed
Water consumed, gal/1000 Ib
.888 5.553
3.516
0.540
.662 4.686
.8 1133.5
.7 1147.8
10.3
Wyoming
all dry
8.523
0
0
5.428
1136.1
1150.1
0
160
4.184
3.989
0.888
4.558
1166.1
1179.7
20.9
160
4.109
3.989
0.888
4.510
1139.7
1153.2
19.8
180 all
3.183 0
4.379 5.
1.079 3.
4.830 6.
1167.3 1177.
1180.8 1193.
27.7 107.
all wet
0
5.714
3.161
6.732
1181.1
1196.7
106.8
wet
714
161
732
6
2
9
Beulah, North Dakota
Basis: 1000 Ib. hydrogen compressed/hr
Design intermediate temperature, °F
Dry cooler cost, C/1000 Ib
Wet cooler cost, C/1000 Ib
Towejr cost, C/1000 Ib
Fan and pump energy, C/1000 Ib
Compression energy cost, C/1000 Ib
Total, C/1000 ifc compressed
Water consumed, gal/1000 Ib
all dry
9.777
0
0
6.226
1125.5
1141.5
0
160
4.335
3.989
0.888
4.654
1159.5
1173.4
16.6
all wet
0
5.714
3.161
6.732
1175.7
1191.3
107
46
-------
co
o
o
o
1/1
I—
o
_l
—«
1/1
LU
o;
Q.
1200
1180
1160
1140
1120
1100
UNIT COSTS - SET NO. 1
TOTAL COST (WATER FREE)
COMPRESSION ENERGY
CAPITAL
AUXILIARY ENERGY
20
40
60
80
100
WATER CONSUMPTION, GAL/1000 LB
100
80
60
40
20
120
.CO
o
o
o
1/1
h-
1/1
o
o
en
a:
Q.
-------
2.1.5 Economics of Cooling Turbine Condensers in Steam Generating Plant
Tables 2-6 and 2-7 summarize the costs and evaporation rates of economically
optimum systems for the wet/dry cooling of turbine condensers in steam generating
plants for a range of fixed charge rates and fuel costs. Figure 2-18 shows
schematically the operating costs of cooling steam turbine condensers as a
function of water consumed for different costs of water. If water is free or
its cost is negligible, then an all wet cooling system is the lowest cost cooling
system. As the cost of water increases, the cost of wet/dry cooling systems
becomes comparable with the all wet system, but with a much lower water consump-
tion. When the cost of water is equal to the changeover water cost, then the
annual cost of operating a wet/dry system is equal to the cost of an all wet
system. When the cost of water exceeds the changeover water cost, wet/dry cooling
is more desirable, while all wet cooling is more desirable when the cost of
water is lower than the changeover water cost. (See Figure 2-18).
The changeover water costs range from $3.65 to $5.47 per 1000 gals water
evaporated in North Dakota and $3.83 to $5.87 per 1000 gals water evaporated in
New Mexico for the fixed charge rates and fuel costs considered. These costs
are much higher than the changeover water costs previously found for cooling
turbine condensers and gas comparessors in plants producing synthetic fuel
from coal. The variation in changeover water cost is primarily dependent on the
variation in the fixed charge rate and is relatively independent of the fuel cost.
We have also shown the busbar energy cost penalty of using a wet/dry cooling
tower in preference to an all wet cooling tower. The cost penalty is the
difference in the optimum operating cost of a wet/dry tower at the changeover
water cost to the optimum cost of an all wet tower when the water is free divided
by the output of the power plant in kw-hrs. The penalty cost ranges from
1.2 to 2.0 mils/kw-hr (0.12 -0.2 £/kw-hr) as compared to a delivered cost of
electricity of 2C/kw-hr, commonly used today. This would represent the maximum
penalty since water is not free and would rarely exceed the changeover water cost.
The cost of wet/dry towers is relatively insensitive to the water costs near
the design optimum.
The primary advantage of the wet/dry system is that the consumptive use of
water can be drastically reduced from that of an all wet tower. Tables 2-6 and
2-7 show that at the design optimum the evaporative water consumption is reduced
48
-------
TABLE 2-6. SUMMARY OF WET/DRY COOLING SYSTEM COSTS AND WATER REQUIREMENTS
AT NAVAJO/FARMINGTON, NEW MEXICO
Fixed Charge Fuel Cost
Rate
(Percent) (S/10 Btu)
15 0.50
1.00
1.50
18 0.50
1.00
1.50
21 0.50
1.00
1.50
Changeover
Water Cost
($/1000 gals
Evaporated)
3.83
4.16
4.34
4.43
4.80
5.18
5.03
5.44
5.87
Busbar
Energy Cost
Penalty
(Mils/kwhr)
1.40
1.53
1.65
1.56
1.76
1.82
1.77
1.84
1.97
Evaporation
Rate*
(gals/cal min)
693
686
534
847
686
856
847
1012
1028
Evaporation
Rate
as Percent of
All Wet Cooling
14.6
14.4
11.2
17.8
14.6
18.0
17.8
21.3
21.6
*For 1000 MWe steam-electric power plant.
-------
TABLE 2-7. SUMMARY OF WET/DRY COOLING SYSTEM COSTS AND WATER REQUIREMENTS
AT BEULAH, NORTH DAKOTA
ui
o
Fixed Charge
Rate
(Percent)
15
18
21
Fuel Cost
($/106 Btu)
0.50
1.00
1.50
0.50
1.00
1.50
0.50
1.00
1.50
Changeover
Water Cost
($/1000 gals
Evaporated)
3.65
4.16
4.34
4.43
4.80
5.18
5.03
5.44
5.87
Busbar
Energy Cost
Penalty
(Mils/kwhr)
1.21
1.31
1.44
1.43
1.52
1.67
1.63
1.75
1.89
Evaporation
Rate*
(gals/cal min)
661
650
513
661
650
513
661
651
513
Evaporation
Rate
as Percent of
All Wet Cooling
15.2
15.0
11.8
14.9
15.0
11.8
14.9
15.0
11.8
*For 1000 MWe steam-electric power plant.
-------
CO
o
LU
d.
O
ALL DRY
WATER CONSUMPTION
ALL WET
o
i—i
Q.
SI
ra
CO
z
o
t_>
or
ALL WET
CHANGEOVER
WATER COST
AT OPTIMUM DESIGN
WATER COST
Figure 2-18. Operating costs and water consumption of wet/dry cooling system.
51
-------
by 78 to 88 percent. However, some care should be exercised in interpreting
this result since this reduction is based on a yearly average and the wet/dry
system consumes water during periods of peaking in the summer months. In
Reference 5, United Engineers and Constructors, Inc. correctly point out that
although the annual makeup is small, the maximum flow rate over the peaking
periods can be large. For example, for Farmington, New Mexico, a wet/dry
tower consuming 10 percent of the annual water consumed for an all wet tower,
will have a maximum flow rate of almost 60 percent of that required by an all
wet system, resulting possibly in the building of impoundments since the stream
flows may not be high enough in the summer to match the makeup requirements.
2.2 TURBINE CONDENSERS IN COAL CONVERSION PLANTS
On Figure 2-19 is shown a parallel dry/wet cooling system for a turbine
condenser. The following calculations are intended to determine what fraction
of the cooling load should be designed wet and what fraction should be designed
dry; also, the water consumption is to be determined. Dry cooling has the
advantage over wet cooling in that water is not used. It has the disadvantage
of a higher capital investment and a higher condenser temperature. The higher
condenser temperature means a lower efficiency for the turbine; that is, more
energy as steam is consumed by the turbine for each kw-hr of shaft work performed.
Before an economic analysis can be made, a physical analysis is necessary.
To obtain the desired information the cooling system is first designed and
then its operation is analyzed, month by month, for a year. Finally, the
economic analysis is made, and this depends on the cost of water.
2.2.1 Turbine Characteristics
In a steam turbine drive system the steam rate required by the turbine to
produce a certain shaft power output depends on the inlet steam condition, the
condenser pressure and the turbine efficiency. Usually the higher the inlet
steam pressure and temperature, the higher will be the thermal efficiency of
the system. In the present application where the steam is partially produced
by waste heat recovery, the usual steam pressure is in the range of 715 to 915
psia, and the superheated temperature in the range of 600°F to 900°F. Also,
in the present application where the steam turbine drive is used mainly for
52
-------
U)
i
STEAM
FROM
TURBINE
CONDE
k
OO CO CO OO
i
Tc
NSATE
!
DRY
WET
Tc
^
\
<
EVAPORATION
1 I
tu R|
n ^ L
*~ I .
rl- -,
BYPASS V\" " "7
yRl \\ (
t ^ A A . tM X
^^^ AIR RA
Figure 2-19. Turbine condenser cooling systems.
-------
gas compression purposes, the type of turbine drive used usually has a maximum
efficiency of about 80 percent when the condenser pressure is in the range of
3 to 5 in. Hg absolute. The corresponding steam saturation temperatures for
the two condenser pressures are 115°F and 134°F respectively. Above 134°F,
efficiency falls. We have assumed that below 115°F, the efficiency also
falls. This is a function of the exhaust losses and may not be true for all
turbines. However, usually there is no positive advantage in cooling below
115°F, so the procedure adopted in this study, which is never to cool below
115°F, is reasonably generally applicable when cooling water is scarce.
The heat rates required when the condenser temperature is in the range of
115°F to 134°F have been calculated for the various inlet steam conditions
mentioned and are plotted in Figure 2-20. The calculations were made using an
overall turbine efficiency of 80 percent including the bearing efficiency.
The results in Figure 2-20 show that the steam rates for the four inlet steam
conditions are quite close and that they can be represented by a single
straight line going from a steam rate value of 11,700 Btu/kw-hr at the condenser
temperature of 115°F to a value of 12,200 Btu/kw-hr at the condenser temperature
of 134°F.
The increase in steam rate with condenser temperature indicates that
there is a certain fuel penalty to be considered in evaluating the cost of
various cooling systems.
The condenser cooling loads when the condenser temperature is in the
range of 115°F to 134°F have also been calculated for the four inlet steam
conditions mentioned and are plotted in Figure 2-21. The results indicate
that the condenser loads for the four inlet steam conditions are also quite
close and that they can be represented by a single straight line, going from
a value of 8,200 Btu/kw-hr at the condenser temperature of 115°F to a value of
8,700 Btu/kw-hr at the condenser temperature of 134°F. This typical line will
be used for condenser load calculations when the economics of condenser
cooling systems are evaluated.
In analytical form the turbine heat rate is
54
-------
15
10
ro
O
QJ
H
<
or
STEAM
TEMP
(I) 600
(2) 700
(3) 900
(4) 900
STEAM
PRESSURE
(PSIA)
715
915
715
915
LU
H
CO
en
ro
o*
in
110
115 120 130 134
CONDENSER TEMPERATURE (°F)
140
Figure 2-20. Turbine heat rates at full load.
55
-------
15
2 '0
CD
K)
O
O
<
O
cr
LJ
LJ
O
z
O
O
T
STEAM
TEMP
(I) 600
(2) 700
(3) 900
(4) 900
STEAM
PRESSURE
(PSIA)
715
915
715
915
o>
X
to
CT>
X
10
1
1
MO
115 120 130 134
CONDENSER TEMPERATURE (°F)
140
Figure 2-21. Turbine condenser cooling requirements at full load.
56
-------
T - 115
Qu (Btu/kw-hr) = 11,700 + 500
tTT * fc-W/ JXW 1.XJL. / J*J./iW « W W TOX
= 8,674 + 26.32 T , for 115 <_ T < 134 (1)
C "~~ *-*
and the condenser cooling load is
Q (Btu/kw-hr) = 5,174 + 26.32 T , for 115 < T_ <134 (2)
C V-
The nomenclature is shown on Table 2-8 shown with other tables collected at
the end of this section.
2.2.2 Design Conditions
Design ambient conditions are given on Table 2-9 with complete monthly
average ambient conditions. The condenser design condition is a condensing
temperature of 134°F. This is a high design temperature chosen because the
design ambient conditions are, on the average, not exceeded more than ten
hours in a year. The design conditions for circulating cooling water are a
hot water temperature, t, , of 119°F which is a reasonable and usual 15°F below
h
the design condensing temperature, and cold water temperature, t , of 94°F.
The cold water temperature means that the circulating pumps must be sized for
a 25°F rise which is usually found to be economical.
If x is the fraction of condenser load which is dry at design condition,
QD,d " 8'7°°X
The dry condenser area, A is given by
QD,d = UDAD (LMTD)D
where
(T - T ) - (T - T )
. C D c» C D.h>
C D,h ;
57
-------
The temperature of the heated air leaving the dry condenser is found from the
empirical equation
T^ v, ~ Tr^ = 0.005 U CT - T ) (6)
D,h D,c D C D,c
from which
(TC - TD,c> - (TC - TD,h) - °-0°5 VTC - TD,c>
= (TC-TD,C)(I- °-005 V
so,
,
D f T - T
C D,c I
M-ST^
= 0.005 U_(T_ - TL )/l-ln(l - 0.005 U_ \ (9)
D (^ D f C \ iJ*
Values of U are given on Table 2-.9a. Since the design condenser tempera-
ture is
T_ . = 134 (10)
i-,a
the design log mean temperature difference, LMTD , can be found from
D f Q
Equation (9) and the area from Equations (3) and (4).
58
-------
2.2.3 Design of Wet Condenser and Cooling Tower
To design the cooling tower, information on the efficiency of the packing
is needed. It must be remembered that our objective in designing a tower is
not to build a tower but to determine its operation at off-design conditions.
The choice of tower type and fill pattern is therefore not very important.
For this study we have used the comprehensive graphical data given in Kelley's
Handbook based on 18 ft of air travel and 30 ft height of fill type H. The
tower design parameter, which is given the symbol K Y/L and is called "character-
3.
istic," is taken from Reference 6 for the condition
"Wet Bulb" = T „
W,d
"Range" = t, - t = 25°F (11)
he
"Approach" = t - T = 94 - T (12)
T is the design air wet bulb temperature.
w, d
The equations which give the wet condenser area are
QW,d - 87°°(1 - X) - UWftW(IMrD)W,d
(T - t ) - (T - t )
(LMTD)W,d = r°T _ t ^
-------
The equations which give the rate of circulation of cooling water are
RL(lb/kw-hr) = Qw/d/25
R (gal/min)/kw) = R /(8.33)(60) = 0.002 R (16)
G
2.2.4 Off-Design Conditions, General
Calculations were made using monthly average ambient conditions for each
month of a year beginning with the hottest and ending with the coldest. This
is more convenient than considering the months in chronological order. The
condenser temperature is first determined. If this is apparently below
115°F, then it is controlled at 115°F using the following control philosophy.
First, the heat rejection load of the cooling tower is reduced by altering the
pitch of the fans or by turning the fans off. When the ambient air temperature
is sufficiently low, the evaporative tower is shut down and the heat load is
carried by the dry cooler which controls the turbine back pressure by altering
the fan blade pitch. When the cooling tower is shut down, the circulation of
water is stopped. Water circulation is either full on or off. Throttling the
circulation pumps leads to stagnation, fouling and scaling and is not practiced.
2.2.5 Determination of Condenser Temperature
Determination of the condenser temperature is a trial-and-error calcu-
lation made as follows.
1) A condenser temperature, T , is assumed.
2) The total cooling load, Q, is calculated from Equation (2).
3) The dry log mean temperature difference is calculated from Equation
(5).
4) The dry cooling load is calculated from the equation
QD = UDAD(LMTD)D (17)
5) The wet cooling load is calculated from the equation
Qw = Q - QD (18)
6) The cooling water temperatures are calculated from the wet cooling
load. The "range" is given by the equation
60
-------
(19)
so,
(20)
The rate of heat transfer in the wet condenser is given by
2W = Vw(LMTD)w
where
(MTD>W= (th - V/iln
-------
8) The fan and pump energy needs are calculated from the equations
Dry condenser fan energy E = 0.0149 AD (26)
Cooling tower fan energy EW = 0.0089 RG (27)
Cooling water circulation pump energy E = 0.0246 R (28)
These equations are used only when the condenser temperature is above 115 °F.
When the condenser temperature is controlled at 115°F, the equation given in
later steps should be used.
9) To calculate the water consumption, the rate of air flow through the
tower must be known. The ratio of water flow to air flow, R /R , is part of
the design of the tower (see Reference 6) and is known. Since the water
flow, R , is known, the air flow, R , is also known. Knowing the dry bulb
and wet bulb temperatures the absolute humidity of the entering air, H. Ib
water/lb dry air, can be read from a standard psychometric chart. When the
dry and wet bulb temperatures are below 30°F, the absolute humidity of the
entering air is taken to be zero. It is also possible to calculate the
enthalpy of the entering air, i.. Enthalpies of humid air are normally
measured above 0°F for dry air and liquid water at 32 °F
i± = 0.24 TD + ^[1075 + 0.45(TD - 32)] (29)
In Equation (29), 0.24 is the specific heat of dry air, 0.45 is the specific
heat of water vapor and 1075 is the latent heat of vaporization of water at
32°F.
Next, the condition of the air exiting the tower can be found. The
enthalpy of the exit air is
(30)
because the circulating water transfers the wet cooling load to the air.
Experience shows that the leaving air is within a few percentage points of
62
-------
saturation and it is sufficiently accurate to assume it to be saturated. In
Reference 6 is given a table of saturated air enthalpies against temperature
from which the temperature of the air leaving the tower can be read. The
psychometric chart gives the humidity of the leaving air, H . The rate of
water evaporation is
R (H - H.) Ib/kw-hr (31)
A e i
Equation (31) applies when the tower is not bypassed. When the tower is
bypassed the modification given in Step 18 is used.
2.2.6 Operation with 115°F Condenser Temperature
When the condenser temperature is known, the calculation is as follows.
10) The total cooling load is 8,200 Btu/kw-hr.
11) The dry log mean temperature difference is given by the equation
f }
LMTD = 0.005 U (115 - T )/ (32)
JJ LJ J_) / C [ J-/ J
12) The dry cooling load is given by Equation (17).
13) The wet cooling load is given by the equation
Qw = 8,200 - QD (33)
14) The hot temperature of the circulating cooling water, t , is given
by Equation (25) and the cold temperature, t , by Equation (20). The cold
C
temperature is the temperature of blended water entering the condenser, not
the temperature at the bottom of the cooling tower. The tower is bypassed.
15) The temperature at the bottom of the cooling tower, t , is found
from Reference 6. It is that temperature which makes both the range, t - t ,
and approach, t - T , correct at the same time. When the wet bulb temperature
is very low such that it is no longer on the graphs, an arbitrary 37°F approach
is chosen. This makes the tower bottom temperature 37° higher than the wet
bulb temperature.
63
-------
16) The fraction of the flow which bypasses the tower, y, is given b,y
b = R t (34)
t - t
y = — (35)
t, - t
h r
If y >_ 1, we skip to Step 19.
17) The dry condenser fan energy is given by Equation (26). The cooling
water circulation pump energy is given by Equation (28). The cooling tower
fan energy is
Er, = 0.0089(1 - y)R^ (36)
W G
18) The water evaporation is calculated as in Step 9, except that the
air rate is now (1 - y)Rfl' where R is the design air rate.
19) If the ambient conditions are so cold that the cooling tower is
completely bypassed, the rate of water evaporated is zero, the cooling tower
fan energy is zero and the cooling water circulation pump energy is zero.
The only quantity to be calculated is the dry condenser fan energy. To do
this we first need to know the air temperature, T', at which the dry condenser
will carry the whole load. This is given by
/'
8200 = U A x 0.005 U (115 - T')/ <|-ln(l - 0.005 U )} (37)
^ )
-8200 ln(l - 0.005 U )
115 - T' = — (38)
0.005 U A_
The fan factor, F, is read from the vertical scale of Figure 2-22when the
horizontal scale point is (T' - T ). The dry condenser fan energy is
E = 0.0149 FA (39)
64
-------
1.0
0 20 40 60 80
AMBIENT TEMPERATURE DROP(°F)
Figure 2-22. Fan power reduction factor for air coolers.
65
-------
2.2.7 Results
The results of the month-by-month calculations are given for 0, 25, 50,
75 and 95 percent dry cooling at Farmington, New Mexico, at Casper, Wyoming
and at Beulah, North Dakota on Tables 2-10, 2-11 and 2-12. Summaries are
given on Table 2-12. To make the summaries, equal weight was given to each
month: for example, the fan and pump energies from Tables 2-10 to 2-12
were totaled and divided by 12 to obtain the value entered on Table 2-13.
The fuel penalty is that part of the turbine heat rate in excess of the
minimum value, 11,700 Btu/kw-hr.
Because of the way the calculations were made, the hot and cold circu-
lating water temperatures are both changed to control the system. Now, the
cooling system may have other connections such as to process coolers, and the
hot water returning to the tower may have a temperature derived from mixing
all the returning streams. However, there is no other way of making calcula-
tions. If the cooling tower is not reserved exclusively for turbine condensers,
then the calculations made are indicative but not a precise representation of
reality. Fortunately the chosen configuration, when not all wet, is more than
90 percent dry and less than 10 percent wet. The wet condensers will only be
turned on for a few months of the year, and even then they will carry such a
small fraction of the load that control may not be required.
66
-------
TABLE 2-8. NOMENCLATURE
2
A condenser area, ft
E cooling tower circulation pump energy, kw
E dry condenser fan energy, kw
E cooling tower fan energy, kw
w
F dry condenser fan factor
H absolute humidity of air, Ib water/lb dry air
i enthalpy of air, Btu/lb dry air
LMTD log mean temperature difference, °F
P compression power, kw
Q condenser cooling load, Btu/kw-hr
Q condenser dry cooling load, Btu/kw-hr
Q turbine heat rate, Btu/kw-hr
H
Q condenser wet cooling load, Btu/kw-hr
r compression ratio
R air rate through the tower, Ib/hr
R cooling water circulation rate, gpm/kw
G
R cooling water circulation rate, Ib/kw-hr
T steam condensing temperature, °F
\^
t cold circulating water temperature, °F
c
T air dry bulb temperature, °F
T' air temperature at which dry condenser will carry whole load, °F
t. hot circulating water temperature, °F
t temperature at bottom of cooling tower, °F
T air wet bulb temperature, °F
W
(continued)
67
-------
TABLE 2-s (continued)
2
U heat transfer coefficient, Btu/(hr)(ft )(°F)
x fraction of cooling load carried dry
y fraction of circulating water that bypasses the cooling tower
Suffixes
c cold or entry temperature
C condensing temperature
D dry
d design condition
e exiting, or out
h hot, or exit temperature
i entering, or in
o out, or discharge
W wet
X temperature between dry and wet series coolers between compression
stages
1,2,3 compressor stages
68
-------
TAB!.: - 2-9. AVERAGE AMBIENT CONDITIONS
Month
1, January
2, February
3, March
4, April
5, May
6, June
7, July
8, August
9, September
10, October
11, November
12, December
Farmington, N. M.
DBT*
26
33
42
49
60
70
76
73
64
51
39
27
WBT**
23
28
33
37
45
51
58
57
49
41
32
24
Casper, Wyo.
DBT
24
26
32
41
54
65
71
70
59
47
32
30
WBT
20
22
27
34
44
51
55
53
46
38
47
25
Beulah- N n
DBT
8
15
24
43
56
65
72
70
58
46
28
18
.. , *. . t* •
WBT
7
13
21
37
47
57
62
60
50
39
25
17
Design
98
65
96
60
102
71
'*DBT = dry bulb"' - -;-erature (OF).
**WBT = wet bulb t'.-J'erature (°F) .
69
-------
TABLE 2-9a. HEAT TRANSFER COEFFICIENTS FAN AND PUMP ENERGIES
Cooling a compressed gas:
10 psig
50 psig
100 psig
300 psig
>_ 500 psig
U[Btu/(hr) (ft ) (°F)]
Dry,
.ne drives: 120
Dry
Air Hydrogen Air
10 30 12
20 45 20
30 65 40
40 85 60
50 95 70
Wet
170
Wet
Hydrogen
35
75
100
135
150
Dry cooler fans: kw = 0.0112 x area (U <_ 50)
= 0.0130 x area (100 > U > 50)
= 0.0149 x area (U > 100)
Cooling tower fans: kw = 0.0089 x gpm circulated
Circulating water pumps: kw = 0.0246 x gpm circulated
70
-------
TABLE 2-10. CALCULATIONS ON STEAM TURBINE CONDENSERS AT FARMINGTON, NEW MEXICO
Design Conditions; Fraction designed dry 0.
Dry condenser area 0 ft AW, wet condenser area 2.0069 ft AW.
Cooling tower information: characteristic, KaY/L •= 1.24, water/gas rates 2.12,
circulation rate 348 Ib/kw-hr, 0.696 gpmAw.
Month 123456789 10 11 12
Condenser temperature (°F) 115 115 117 119 124 126 131 129 125 120 116 115
Turbine heat rate (BtuAw-hr) 11,700 11,700 11,753 11,806 11,938 11,990 12,122 12,069 11,964 11,832 11,727 11,700"
Total condenser load (BtuAw-hr) 8,200 8,200 8,253 8,306 8,437 8,490 8,622 8,569 8,464 8,332 8,227 8,200
Dry condenser load (Btu/kw-hr)
Wet condenser load (BtuAw-hr)
Hot water temperature (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
Fraction circulating water
that bypasses tower
-3 kw-hr
Dry fan power (10 kw_hr>
- 3 kw-hr
-3 kw-hr
Circulating pump pwr (10 kw_. ')
Water evaporated (IbAw-hr)
0
8,200
101
77
60
0.41
0
3.65
17.1
5.52
0
8,200
101
77
65
0.33
0
5.39
17.1
5.57
0
8,253
103
79
79
0
0
6.19
17-1
5.41
0
8,306
105
81
81
0
0
6.19
17.1
5.67
0
8,437
109
85
85
0
0
6.19
17.1
6.06
0
8,490
111
87
87
0
0
6.19
17.1
6.45
0
8,622
116
91
91
0
0
6.19
17.1
6.69
0
8,569
114
90
90
0
0
6.19
17.1
6.601
0
8,464
110
86
86
0
0
6.19
17.1
6.23
0
8,332
106
82
82
0
0
6.19
17.1
5.78
0
8,227
102
78
78
0
0
6.19
17.1
5.36
0
8,200
101
77
61
0.40
0
3.72
17.1
5.36
(continued)
-------
TABLE 2-10. (continued)
Design Conditions; Fraction designed dry 0.25.
2 2
Dry condenser area 0.7689 ft /kw, wet condenser area 1.5051 ft AW.
Cooling tower information: characteristic, KaY/L = 1.24, water/gas rates 2.12,
circulation rate 261 IbAw-hr, 0.522 gpmAw.
Month
8
10
11
12
Condenser temperature (°F) 115 115 115 115 115 119 123 122 115 115 115
Turbine heat rate (BtuAw-hr) 11,700 11,700 11,700 11,700 11,700 11,806 11,911 11,885 11,700 11,700 11,700
Total condenser load (BtuAw-hr) 8,200 8,200 8,200 8,200 8,200 8,306 8,411 8,385 8,200 8,200 8,200
Dry condenser load (BtuAw-hr)
Wet condenser load (BtuAw-hr)
Hot water temperature (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
Fraction circulating water
that bypasses tower
,, -3 kw-hr.
Dry fan power (10 kw_hr)
Coolg tower fan pwr (10
5,377 4,954 4,410 3,987 3,322 2,960 2,839 2,960 3,081 3,867 4,592
2,823 3,246 3,790 4,213 4,877 5,346" 5,572 5,425 5,119 4,334 3,609
109
98
60
0.78
11.5
1.02
108
95
65
0.70
11.5
1.39
Circulating pump pwr (10 kw_hr.) 12.8 12.8
Water evaporated (IbAw-hr)
1.96
2.23
106
92
70
0.33
11.5
3.11
12.8
2.45
105
89
84
0.24
11.5
3.53
12.8
2.84
104
85
83
0.10
11.5
4.18
12.8
3.46
107
86
86
0
11.5
4.64
12.8
4.36
110
89
89
0
11.5
4.64
12.8
4.70
109
89
89
0
11.5
4.64
12.8
4.16
103
84
83
0.05
11.5
4.41
12.8
3.70
105
88
82
0.26
11.5
3.44
12.8
2.94
107
93
69
0.75
11.5
1.16
12.8
2.61
115
11,700
8,200
5,316
2,884
108
97
61
0.77
11.5
I'.OS
12.8
2.01
(continued)
-------
OJ
TABLE 2-10. (continued)
Design Conditions; Fraction designed dry 0.50.
2 2
Dry condenser area 1.5378 ft /kw, wet condenser area 1.0035 ft /kw.
Cooling tower information: characteristic, KaY/L • 1.24, water/gas rates 2.12,
circulation rate 174 Ib/kw-hr, 0.348 gpm/kw.
Month 123456789 10 11 12
Condenser temperature (°F) 115 115 115 115 115 115 117 115 115 115 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,700 11,700 11,753 11,700 11,700 11,700 11,700 11,700
Total condenser load (BtuAw-hr) 8,200 8,200 8,200 8,200 8,200 8,200 8,253 8,200 8,200 8,200 8,200 8,200
Dry condenser load (Btu/kw-hr) 8,200 8,200 8,200 7,975 6,646 5,43Q 4,954 5,075 6,163 7,734 8,200 8,200
Wet condenser load (Btu/kw-hr)
Hot water temperature (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
Fraction circulating water
that bypasses tower
-3 kw-hr
Dry fan power (10 kw_hr>
-3 kw-hr
Coolg tower fan pwr (10 . )
-3 kw-hr
Circulating pump pwr (10 kwlh"r">
Water evaporated (Ib/kw-hr)
0
—
—
—
1.0
5.25
0
0
0
0
—
—
—
1.0
7.79
0
0
0
0
—
—
—
^1.0
14.77
0
0
0
224
114
113
92
0.95
22.9
0.15
8.56
0.16
1,554
110
101
88
0.59
22.9
1.27
8.56
1.06
2,762
105
90
85
0.75
22.9
0.77
8.56
2.18
3,299
106
87
87
0
22.9
3.10
8.56
2.56
3,125
104
86
85
0.05
22.9
2.94
8.56
2.45
2,037
108
96
86
0.45
22.9
1.70
8.56
1.49
466
113
111
88
0.92
22.9
0.25
8.56
0.24
0
—
—
—
1.0
11.57
0
0
0
0
—
—
—
1.0
4.81
0
0
0
(continued)
-------
TABLE 2-10. (continued)
Design Conditionst Fraction designed dry 0.75.
Dry condenser area 2.3069 ft /kw, wet condenser area 0.5017 ft2/kw.
Cooling tower information: characteristic, KaY/L = 1.24, water/gas rates 2.12,
circulation rate 87 IbAw-hr, 0.174 gpm/kw.
Month 12 3456789 10 11 12
•*
Condenser temperature (°F) 115 115 115 115 115 115 115 115 115 115 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700
Total condenser load {Btu/kw-hr) 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200
Dry condenser load (Btu/kw-hr)
Wet condenser load (BtuAw-hr)
Hot water temperature (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
Fraction circulating water
that bypasses tower
-3 kw-hr
Dry fan power (10 )
1 e kw-hr
-3 kw-hr
Coolg tower fan pwr (10 . . )
Circulating pump pwr (10 — — r— )
Water evaporated (Ib/kw-hr)
8,200 8,200 8,200
000
__
—
—
1.0 1.0 1.0
4.50 4.98 6.19
000
10 0 0
000
8,200 8,200 8,157
0 0 43
115
114
88
1.0 1.0 0.96
7.97 15.5 34.4
0 0 0.06
0 0 4.28
0 0 0.035
7,069
1,131
107
94
92
0.13
34.4
1.35
4.28
0.93
7,613 8,200
587 0
111
104
89
0.68 1.0
34.4 21.21
0.49 0
4.28 0
0.453 0
8,200 8,200 8,200
000
—
—
—
1.0 1.0 1.0
8.83 4.85 4.54
000
000
000
(continued)
-------
TABLE 2-10. (continued)
Design Conditions; Fraction designed dry 0.95.
2 2
Dry condenser area 2.922 ft Awf wet condenser area 0.1003 ft AW.
Cooling tower information: characteristic, KaY/L = 1.24, water/gas rates 2.12,
circulation rate 17.4 IbAw-hr, 0.0348 gpm/kw.
Month 123456789 10 11 12
Condenser temperature (8F) 115 115 115 115 115 115 115 115 115 115 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700
Total condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200
Dry condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,200 ^ 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200
-j
01 Wet condenser load (Btu/kw-hr) 000000000000
Hot water temperature ("F)
Cold water temperature (*F)
Tower bottom temperature (°F)
Fraction circulating water
that bypasses tower
-3 kw-hr
Dry fan power (10 * " •)
•* kw-hr
*• 3 lew—hi?
Coolg tower fan pwr (10 |^_hr)
— 3
Circulating pump pwr (10 J
Water evaporated (Ib/kw-hr)
1.0
5.22
0
0
0
1.0
5.70
0
0
0
1.0
6.26
0
0
0
1.0
7.27
0
0
0
1.0
10.8
0
0
0
1.0
20.2
0
0
0
1.0
33.18
0
0
0
1.0
25.69
0
0
0
1.0
13.63
0
0
0
1.0
7.71
0
0
0
1.0
6.05
0
0
0
1.0
5.27
0
0
0
-------
TABLE 2-3 1 CALCULATIONS ON STEAM TURBINE CONDENSERS AT CASPER, WYOMING
Design Conditions; Fraction designed dry 0.
2 2
Dry condenser area 0 ft AW, wet condenser area 2.0069 ft AW.
Cooling tower information: characteristic, KaY/L = 1.17, water/gas rates 2.24,
circulation rate 348 Ib/kw-hr, 0.696 gpmAw.
Month 12 3456789 10 11 12
Condenser temperature (°F) 115 115 116 122 127 130 131 130 129 122 116 115
Turbine heat rate (BtuAw-hr) 11,700 11,700 11,727 11,885 12,016 12,096 12,122 12,096 12,069 11,885 11,727 11,700
Total condenser load (BtuAw-hr) 8,200 8,200 8,227 8,385 8,516 8,596 8,622 8,596 8,569 8,385 8,227 8,200
Dry condenser load (BtuAw-hr) 000000000000
Wet condenser load (Btu/kw-hr) 8,200 8,200 8,227 8,385 8,516 8,596 8,622 8,596 8,569 8,385 8,227 8,200
Hot water temperature (°F) 101 101 102 108 112 115 116 115 114 108 102 101
Cold water temperature (°F) 77 77 78 83 88 90 91 90 90 83 78 77
Tower bottom temperature (°F) 57 59 78 83 88 90 91 90 90 83 78 62
Fraction circulating water
that bypasses tower 0.45 0.43 000000000 0.38
Dry fan power (10~3 ^W"^0 000000000000
Coolg tower fan pwr (10~3 !;W"^r) 3.40 3.53 6.19 6.19 6.19 6.19 6.19 6.19 6.19 6.19 6.19 3.84
jcw~nr
Circulating pump pwr (10~3 ^^) 17.12 17.12 17.12 17.12 17.12 17.12 17.12 17.12 17.12 17.12 17.12 17.12
Water evaporated (Ib/kw-hr) 5.54 5.57 5.28 5.47 6.00 6.39 6.56 6.52 6.22 5.78 5.28 5.49
(continued)
-------
TABLE 2-11(continued)
Design Conditions; Fraction designed dry 0.25.
Dry condenser area 0.728 ft /kw, wet condenser area 1.5051 ft AW.
Cooling tower information: characteristic, KaY/L = 1.17, water/gas rates 2.24,
circulation rate 261 Ib/kw-hr, 0.522 gpmAw.
Month 123456789 10 11 12
Condenser temperature (»F) 115 115 115 115 115 118 122 121 115 115 115 115
Turbine heat rate (BtuAw-hr) 11,700 11,700 11,700 11,700 11,700 11,780 11/885 11,859 11,700 11,700 11,700 11,700
Total condenser load (BtuAw-hr) 8,200 8,200 8,200 8,200 8,200 8,279 B.,^85 8,358 8,200 8,200 8,200 8,200
Dry condenser load (Btu/kw-hr) 5,206 5,091 4,747 4,233 3,203 3,032' 2,917 2,917 3,203 3,890 4,748 4,862
Wet condenser load (BtuAw-hr) 2,995 3,109 3,452 3,967 4,997 5,248 5,468 5,441 4,997 4,311 3,452 3,338
Hot water temperature (°F) 108 108 107 106 104 106 109 108 104 105 107 107
Cold water temperature (°F) 97 96 94 91 84 86 88 88 84 89 94 S5
Tower bottom temperature (°F) 57 59 64 71 84 86 88 88 84 84 64 62
Fraction circulating water
that bypasses tower 0.78 0.75 0.70 0.57 00000 0.24 0.70 0.73
Dry fan power (10~3 ^z^) 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8
Coolg tower fan pwr (10~3 j^f) 1-02 1.16 1.39 2.00 4.65 4.65 4.65 4.65 4.65 3.53 1.39 1.25
-1 Vu—Vir-
Circulating pump pwr (10 J ^_^) 12.8 12.8 12.8 12.B 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8
Water evaporated (Ib/kw-hr) 2.07 2.14 2.40 2.71 3.52 3.91 4.20 4.06 3.56 2.91 2.40 2.33
(continued)
-------
oo
TABLE 2-11 (continued)
Design Conditions; Fraction designed dry 0.75.
2 2
Dry condenser area 2.185 ft /kw, wet condenser area 0.5017 ft Aw.
Cooling tower information: characteristic, KaY/L = 1.17, water/gas rates 2.24,
circulation rate 87 IbAw-hr, 0.174 gpm/kw.
Month 12 3456789 10 11 12
Condenser temperature (°F) 115 115 115 115 115 115 115 115 115 115 115 115
Turbine heat rate (BtuAw-hr) 11,700 11,700 11,700 11,700 11,700 11,700 11;700 11,700 11,700 11,700 11,700 11,700
Total condenser load (BtuAw-hr) 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200
Dry condenser load (BtuAw-hr) 8,200
Wet condenser load (BtuAw-hr) 0
Hot water temperature (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
Fraction circulating water
that bypasses tower 1.0
— T VT*J— ViT"
_ ,- i 1 n •* **" 11JL \ A 1f\
Dry ran power ill) , , i i.ju
-3 kw-hr
Coolg tower fan pwr (10 vw-hr' ^
••3 kw~hr
Circulating pump pwr (10 - • ) 0
Water evaporated (lb/kw-hr) 0
8,200 8,200 8,200 8,200
0000
—
__
—
1.0 1.0 1.0 1.0
4.43 4.85 6.32 11.69
0000
0 00 0
0000
8,200
0
--
—
—
1.0
27.05
0
0
0
7,554
646
111
103
89
0.64
32.5
0.56
4.28
0.48
7,726 8,200 8,200
474 0 0
112
106
89
0.74 1.0 1.0
32.5 1.6.38 7.72
0.40 0 0
4.28 0 0
0.36 0 0
8,200 8,200
0 0
—
—
—
1.0 1.0
4.85 4.66
0 0
0 0
0 0
(continued)
-------
TABLE 2-11 (continued)
Design Conditions: Fraction designed dry 0.50.
Dry condenser area 1.4568 ft AW, wet condenser area 1.0035 ft AW.
Cooling tower information: characteristic, KaY/L = 1.17, water/gas rates 2.24,
circulation rate 174 IbAw-hr, 0.348 gpmAw.
Month 123456789 10 11 12
Condenser temperature (°F) 115 115 115 115 115 115 115 115 115 115 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700
Total condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200
Dry condenser load (BtuAw-hr) 8,200 8,200 8,200 8,200 6,982 5,723 5,036 5,151 6,410 7,784 8,200 8,200
Wet condenser load (Btu/kw-hr) 0 0 0 0 1,218 2,477 3,164 3,049 1,790 416 0 0
Hot water temperature (°F) — — — — 111 106 104 104 109 114
Cold water temperature (°F) ~ — — — 104 92 86 87 99 111
Tower bottom temperature (°F) — — — — 87 86 86 86 87 90
Fraction circulating water
that bypasses tower 1.0 1.0 1.0 1.0 0.71 0.30 0 0.06 0.55 0.91 • 1.0 1.0
_T Vw-hr
Dry fan power (10 £--•" ) 5.42 6.07 8.79 17.97 21.7 21.7 21.7 21.7 21.7 21.7 8.79 7.73
/tw*rnr
— 1 kw—hr
Coolg tower fan pwr (10 * " ) 0000 0.90 2.17 3.10 2.91 1.39 0.29 0 0
Circulating pump pwr (10~3 ^j^) 0000 8.56 8.56 8.56 8.56 8.56 8.56 0 0
Water evaporated (IbAw-hr) 0000 0.87 1.86 2.40 2.36 1.29 0.009 0 0
(continued)
-------
00
o
TABLE 2-11(continued)
Design Conditions i Fraction designed dry 0.95.
2 2
Dry condenser area 2.7680 ft /kw, wet condenser area 0.1003 ft AW.
Cooling tower information: characteristic, KaY/L = 1.17, water/gas rates 2.24,
circulation rate 17.4 IbAw-hr, 0.0348
Month 123456789 10 11 12
Condenser temperature (°F)
Turbine heat rate (Btu/kw-hr)
Total condenser load (Btu/kw-hr)
Dry condenser load (Btu/kw-hr)
Wet condenser load (Btu/kw-hr)
Hot water temperature (°F)
Cold water temperature (°F)
Tower bottom temperature (*F)
Fraction circulating water
that bypasses tower
,,«-3 kw-hr.
Dry fan power (10 kw_hr>
,,_-3 kw-hr v
Coolg tower fan pwr (10 Vu-hr
Circulating pump pwr (10 . :.• 1
Water evaporated (Ib/kw-hr)
115
11,700
8,200
8,200
0
—
—
—
1.0
4.95
0
! 0
0
115
11,700
8,200
8,200
0
—
—
—
1.0
4.99
0
0
0
115
11,700
8,200
8,200
0
—
—
—
1.0
5.32
0
0
0
115
11,700
8,200
8,200
0
—
—
—
1.0
6.06
0
0
0
115
11,700
8,200
8,200
0
—
—
—
1.0
8.66
0
0
0
115
11,700
8,200
8,200
0
—
—
—
1.0
15.71
0
0
0
115
11,700
8,200
8,200
0
—
—
~
1.0
24.29
0
0
0
115
11,700
8,200
8,200
0
~
~
~
1.0
22.11
0
0
0
115 115
11,700 11,700
8,200 8,200
8,200 8,200
0 0
__
—
—
1.0 1.0
10.81 6.89
0 0
0 0
0 0
115
11,700
8,200
8,200
0
—
—
—
1.0
5.32
0
0
0
115
11,700
8,200
8,200
0
—
—
—
1.0
4.65
0
0
0
-------
TABLE 2-12 CALCULATIONS ON STEAM TURBINE CONDENSERS AT BEULAH, NORTH DAKOTA
Design Conditions; Fraction designed dry 0.
2 2
Dry condenser area 0 ft /kw, wet condenser area 2.007 ft /kw.
Cooling tower information: characteristic, KaY/L =• 1.30, water/gas rates 1.85,
circulation rate 348 Ib/kw-hr, 0.696 gpm/kw.
\
j
Month 123456789 10 11 12
Condenser temperature (°F) 115 115 115 119 124 126 129 127 124 119 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,806 11,938 11,990 12,069 12,017 11,938 11,806 11,700 11,700
Total condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,306 8,430 8,490 8,569 8,517 8,438 8,306 8,200 8,200
Dry condenser load (Btu/kw-hr) 000000000000
Wet condenser load (Btu/kw-hr) 8,200 8,200 8,200 8,306 8,438 8,490 8,569 8,517 8,438 8,306 8,200 8,200
Hot water temperature (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
Fraction circulating water
that bypasses tower
— "? lew—V) Y"
Dry fan power (10 * " )
— "1
Coolg tower fan pwr (10 J
-3
Circulating pump pwr (10
Water evaporated (Ib/kw-hr) 4.42 4.70 4.89 5.64 6.26 6.40 6.64 6.58 6.11 5.64 5.08 4.70
(continued)
101
) 77
°F) 45
0.57
0
KW nr. „ -
i kw-hr. - _ , _
101
77
52
0.51
0
3.03
n IT
101
77
61
0.40
0
3.72
T7 1 •>
105
81
81
0
0
6.19
it IT
109
84
85
0
0
6.19
IT IT
111
87
87
0
0
6.19
IT IT
114
90
90
0
0
6.19
IT IT
112
88
88
0
0
6.19
IT IT
109
85
85
0
0
6.19
IT 10
105
81
81
0
0
6.19
IT 1 -*
101
77
65
0.33
0
4.15
IT 1^
101
77
55
0.48
0
3.22
^ T •» *\
-------
TABLE 2-12 (Continued)
Design Conditions; Fraction designed dry 0.25.
Dry condenser area 0.865 ft /kw, wet condenser area 1.505 ft /kw.
Cooling tower information: characteristic, KaY/L = 1.30, water/gas rates 1.85,
circulation rate 261 Ib/kw-hr, 0.522 gpm/kw.
Month 123456789 10 11 12
Condenser temperature (°F) 115 115 115 115 115 115 115 115 115 115 115 115
Turbine heat rate (Btu/kw-hr) 11,700 11,700 11,700 11,700 11,700 11,700 11,806 11,753 11,700 11,700 11,700 11,700
CO Total oondonnor load (ntu/kw-hr) 8,200 8,200 8,200 0,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200
to
Dry condenser load (Btu/kw-hr) 7,273 6,797 6,185 4,894 4,010 3,398 3,195 3,194 3,874 4,690 5,914 6,593
Wet condenser load (Btu/kw-hr) 927 1,403 2,015 3,306 4,190 4,801 5,111 5,059 4,326 3,510 2,286 1,607
Hot water temperature (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
Fraction circulating water
that bypasses tower
- 3 kw-hr
Dry fan power (10 !cw_nr'
-3 kw-hr
Coolg tower fan pwr (10 . • . )
-3 kw-hr
Circulating pump pwr (10 kw-hr'
Water evaporated (Ib/kw-hr)
113
109
45
0.94
12.9
0.28
12.8
0.28
112
106
52
0.90
12.9
0.46
12.8
0.56
110
103
61
0.86
12.9
0.65
12.8
1.13
107
95
81
0.54
12.9
2.14
12.8
2.20
105
89
83
0.27
12.9
3.39
12.8
3.00
104
86
86
0
12.9
4.65
12.8
3.67
107
87
87
0
12.9
4.65
12.8
4.02
105
86
86
0
12.9
4.65
12.8
4.00
105
88
83
0.23
12.9
3.58
12.8
3.13
107
93
81
0.46
12.9
2.51
12.8
2.40
110
101
65
0.80
12.9
0.93
12.8
1.27
111
105
55
0.89
12.9
0.51
12.8
0.78
(continued)
-------
00
TABLE 2-12 (Continued)
Design Conditions t Fraction designed dry 0.50.
2 2
Dry condenser area 1.730 ft AW, wet condenser area 1.003 ft AW.
Cooling tower information: characteristic, KaY/L •= 1.30, water/gas rates 1.85,
circulation rate 174 Ib/kw-hr, 0.348
Month 123456789101112
Condenser temperature (°F)
Turbine heat rate (Btu/kw-hr)
Total condenser load (Btu/kw-hr)
Dry condenser load (Btu/kw-hr)
Wet condenser load (Btu/kw-hr)
Hot water temperature (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
Fraction circulating water
that bypasses tower
. -3 kw-hr.
, -3 kw-hr,
Coolg tower ran pwr (iu (,,.,_ v, '
-3 kw-hr
Circulating pump pwr (10 . . )
Water evaporated (Ib/kw-hr)
115
11,700
8,200
8,200
0
-
-
-
1.0
3.1
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
4.6
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
4.9
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
10.3
0
0
0
115
11,700
8,200
8,020
180
114
113
86
0.96
25.8
0.12
8.56
0.40
115
11,700
8,200
6,797
1,403
110
102
86
0.67
25.8
1.02
8.56
1.22
115
11,700
8,200
5,845
2,355
107
93
88
0.26
25.8
2.29
8.56
1.91
115
11,700
8,200
6,117
2,083
108
96
85
0.48
25.8
1.61
8.56
1.74
115
11,700
8,200
7,749
451
113
111
86
0.93
25.8
0.22
8.56
0.56
115
11,700
8,200
8,200
0
-
-
-
1.0
10.3
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
5.1
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
4.7
0
0
0
(continued)
-------
00
TABLE 2-12 (Continued)
Design Conditions; Fraction designed dry 0.75.
2 2
Dry condenser area 2.595 ft /kw, wet condenser area 0.502 ft fkv.
Cooling tower information: characteristic, KaY/L = 1.30, water/gas rates 1.85,
circulation rate 87 Ib/kw-hr, 0.174 gpm/kw.
Month 12 3456789 10 11 12
Condenser temperature (°F)
Turbine heat rate (Btu/kw-hr)
Total condenser load (Btu/kw-hr)
Dry condenser load (Btu/kw-hr)
Wet condenser 'load (Btu/kw-hr)
Hot water temperature (°F)
Cold water temperature (°F)
Tower bottom temperature (°F)
Fraction circulating water
that bypasses tower
., -3 kw-hr
Dry fan power (10 kw_hr'
—3 kw— hr
Coolg tower fan pwr (10 . )
,,,,-3 kw-hr.
Circulating pump pwr (10 tij-hr
Water evaporated (Ib/kw-hr)
115
11,700
8,200
8,200
0
-
-
-
1.0
4.64
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
5.02
0
0
0
115
11,700
8,200
.8,200
0
-
-
-
1.0
5.60
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
6.94
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
10.0
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
15.4
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
38.7
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
31
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
7.0
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
6.95
0
0
0
115
11,700
8,200
8,200
0
-
-
-
1.0
5.80
0
0
0
115
11,700
8,200
8,200
0
-
-
. -
1.0
4.64
0
0
0
(continued)
-------
TABLE 2-12 (Concluded)
Design Conditions: Fraction designed dry 0.95.
2 2
Dry condenser area 3.287 ft Aw, wet condenser area 0.100 ft AW.
Cooling tower informations characteristic, KaY/L = 1.30, water/gas rates 1.85,
circulation rate 17.4 IbAw-hr, 0.0348
Month 123456789 10 11 12
Condenser temperature (°F) 115 115 115 115 115 115 115 115 115 115 115 115
Turbine heat rate (BtuAw-hr) 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700 11,700
00
en Total condenser load (BtuAw-hr) 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200 8,200
Dry condenser load (BtuAw-hr) --------------------- NOT REQUIRED AS
Wet condenser load (Btu/kw-hr) WATER CONSUMPTION
Hot water temperature (°F)
_ . , . ^ .._. ALREADY NEGLIGIBLE
Cold water temperature ( F)
Tower bottom temperature (°F) FOR 75* DESGINED DRY.
Fraction circulating water
that bypasses tower
, nr.~ ->
Dry fan power (10 kw_hr>
. ,,_-3 kw-hr,
Coolg tower fan pwr (10 -
-3 kw-hr
Circulating pump pwr (10 kw_hr)
Water evaporated (lb/kw-hr)
-------
TABLE 2-13 SUMMARY OF WET/DRY CONDENSER COOLING CALCULATIONS
Farming-ton, New Mexico
Fraction designed dry
Dry
Wet
2
condenser area ft /kw
2
condenser area ft AW
Circulation rate gpm/kw
Avg
Avg
Avg
fuel penalty Btu/kw-hr
fan & pump energy kw-hr/kw-hr
water consumption gal/kw-hr
0.95
2.92
0.100
0.0348
0
0.012
0*
0.
2.
0.
0.
0
0.
0.
75
31
50
174
016
014
0
1
1
0
4
0
0
.50
.54
.00
.348
.417
.023
.101
0.
0.
1.
0.
41.
0.
0.
25
77
51
52
833
027
374
0
0
2.
0.
158.
0.
0.
01
696
42
023
707
Casper , Wyoming
Fraction designed dry
Dry
Wet
condenser area ft /kw
condenser area ft /kw
Circulation rate gpm/kw
Avg
Avg
Avg
fuel penalty Btu/kw-hr
fan & pump energy kw-hr/kw-hr
water consumption gal/kw-hr
Beulah
0.95
2.77
0.100
0.0348
0
0.010
0*
, North
Fraction designed dry
Dry
Wet
2
condenser area ft /kw
2
condenser area ft /kw
Circulation rate gpm/kw
0.
2.
0.
0.
0
75
19
50
174
0.014
0.
008
0
1
1
0
0
0
0
.50
.46
.00
.348
.021
.088
0.
0.
1.
0.
35.
0.
0.
25
728
51
522
33
027
362
0
0
2.
0.
193.
0.
0.
01
696
58
023
701
Dakota
0.
2.
0.
0.
75
595
502
174
0
1
1
0
.50
.730
.003
.348
0.
0.
1.
0.
25
865
505
522
0
0
2.
0.
007
696
Avg fuel penalty' Btu/kw-hr 0 0 13.25 138.7
Avg fan S pump energy kw-hr/kw-hr 0.012 0.018 0.028 0.022
Avg water consumption gal/kw-hr 0 0.058 0.265 0.071
*Less than 0.001.
86
-------
2.3 AIR COMPRESSORS IN COAL' CONVERSION PLANTS
To study the effect of series dry-wet coolers on interstage cooling in
gas compressors two compressors have been studied, an air compressor and a
hydrogen compressor. The study on the hydrogen compressor is given in the
following section. The study on the air compressor follows.
2.3.1 Design Conditions
Air is compressed from ambient temperature and 15 psia to 90 psia and
104°F (or cooler) , in which condition air enters the separation plant to be
separated into nitrogen and oxygen. Air compressors are used in all plants,
and they are the biggest compressors in the gas plants. The compressor is
shown on Figure 2-23. It is a three-stage compressor with a compression ratio
of 1.817 per stage. The temperatures T and T. = 109°F are design conditions.
X 1
The stage outlet temperatures are calculated from the equation
T = T. r- (40)
o i
where
T , T. are outlet and inlet temperatures, °R, (°R = 460 + °F)
o i
r is the compression ratio
(n-l)/n = 0.371 for air
The only number which must be chosen is T , the temperature between the
air cooler and the wet cooler. The following calculations are intended to
determine what T should be.
X
To begin, it is necessary to know the power consumed by a gas compressor.
The general equations for the horsepower needed to drive a gas compressor
7
are :
HP = WH/33,OOOe (41)
Z '\/, c '> [
d 1,545 ir
(n-D/n
87
-------
00
CO
ttl'lUltlX 1
15 psia
>
f
\
Tn „ T T« . = 109°F Z'° T T -inq°F 3,0s T T
1,0 y _, ?.i ?Rn°F y ' T i luy r ocrioc '« '
y — I **** c^ c:>v ^ , — , * r*S -3'1 ^bu r w jL-^ ^^ air
IX
27.26 psia
X
1
'
\
2
/
r u-j ^;
P><
49.52 psia
f
\
£>0 = 104oF
90 psia
X
3 1
Figure 2-23. Air compressor design conditions.
-------
(n-l)/n = (k-l)/ke (43)
HP is horsepower
W is gas flow in Ib/min
H is polytrophic head (ft-lb)/lb
e is polytrophic efficiency
Zsf Zd are coim?ressikility factors for suction and discharge
M is molecular weight
w
TS is suction temperature, °R(°R = 460 + °F)
r is the compression ratio
k is ratio of specific heats
For air, the appropriate values of the parameters are:
W
e
Z
s
Zd -
k
M
w
•D/n -
16.67
0.77
1.0
1.0
1.40
29
0.371
The choice of W means that all calculations are based on 1,000 Ib/hr of
gas. Note that 1,000 Ib/hr of air is equivalent to 233 Ib/hr of oxygen.
The short equation, where P is the power in kw (= 1.341 HP), is:
P = 0.0702 T.(r°'371 - 1) (44)
Monthly average and design ambient conditions are as previously given for
turbine condenser calculations. Hot and cold water design temperatures are
119°F and 94°F as above, and the tower characteristics are as previously
found. For interstage cooling the tower is assumed independent of the tower
for the turbine condensers. This means a segregated cooling loop which is
U S EPA Headquarters Library
89 Mai! cede 3404T
1200 Pennsylvania Avenue NW
Washindtori, DC 20460
202-566-0556
-------
acceptable practice but not always done. The two cooling loops are assumed
segregated in this study to limit the calculation and to aid in understanding
the theory.
T is chosen and the areas of the various wet and dry coolers determined.
A
The heat transfer coefficient varies with the gas pressure as shown on Table 2-10.
The load on the cooler, Btu/hr, is
(gas rate, Ib/hr) (T - TQui_)c (45)
The gas rate is 1,000 Ib/hr. The specific heat is sufficiently independent of
temperature and pressure to be taken as constant. We have used
c (air) = 0.241 (46)
P
so, the load
Q = 241(T. - T ) (47)
in out
The wet and dry cooler areas following each stage are calculated and
tabulated. The calculation proceeds as follows.
1) For the design ambient temperature, calculate the first stage outflow
temperature T from Equation (40) which, for this compressor, is
1,0
T ,_ = 1-248 T. ,,_.
out in (48)
2) Calculate the area of the air cooler from the equations
(49)
o
where GTD is the greater of the temperature differences
90
-------
and
and LTD is the lesser temperature differences. The nomenclature is given on
Figure 2-23 and Table 2-8.
The hot temperature on the ambient side of the cooler is given by
Vh - TD,d - °-°°5 UD ~- ~ TD,d ]
All four temperatures are known and A can be found for each stage.
3) Calculate the area of the wet cooler from the equation
Qw = UwAw(LMTD)w = 241 (TX ~ Ti) (52)
where LMTD is given by an equation similar to Equation (50) in which the
Vr
temperature differences are
and (T. - t(j)
The design conditions are: T as chosen, t = 119°F, T. = 109CF, t = 94°F.
X rl 1 C
The wet area is calculated for all stages.
4) The water circulation rates for each wet cooler are calculated from
Equations (15) and (16) . The total flow is the sum of the individual flows.
2.3.2 Off -De sign Conditions
When turbine condensers were studied, there was actually a penalty for
cooling too low. In this case there is a benefit for cooling to a lower, and
still lower temperature — namely, the compression energy is decreased. At
first sight the optimum strategy is not apparent: whether to control the
inlet temperature to each stage or let it go as cold as possible. However,
calculations show that maximum cooling is always preferable. An example can
be given to show this. With the temperature between dry and wet cooling equal
to 160 °F in Farmington, New Mexico, the maximum cooling calculations using
91
-------
Set No. 1 and presented in Section 2.1 show a cost of 65.54 C/1000 Ib and a
water evaporation rate of 1.929 gal/1000 Ib. If water is turned off for
months 1, 2, 3, 11 and 12, the cost goes up by 0.65 C/1000 Ib and the water
consumption goes down by 0.562 gal/1000 Ib (Tables 2-13 and 2-14). This cost
of water is $11.57/thousand gallons, which is too high.
2.3.3 Operation with Maximum Cooling
5) The calculation must begin at the entry to the first stage and
proceed through each piece of equipment in series. First the exit temperature
from Stage 1 is calculated.
6) Next, T is calculated by simultaneous solution of Equations (49) ,
X, 1
(50) and (51). A trial-and-error solution is used. A value is assumed for
T , T is calculated from Equation (51) and IMTV^ is calculated from Equa-
tion (50). The assumed value for T is correct if Equation (49) is true. If
A
U A (LMTD) < 241 (T - T )
D D D O X
then T has been chosen too low and a larger value must be tried.
A
7) Next, T . is calculated (also be trial and error). A value for T
2,1 ^,1
is assumed and Q calculated from Equation (52) . The hot and cold water
temperatures are then calculated from the equations
'TX - fch - Ti + tc
vvv =
that is,
- V*L <54)
and
„ _ .. „ K - *i -IVR!
(55)
, X
11
T -
*h
92
-------
TABLE 2-14. SUMMARY OF WET/DRY COMPRESSOR INTERSTAGE COOLING FOR AIR COMPRESSORS
AT FARMINGTON, N.M. WITH WET COOLER OFF FOR MONTHS 1, 2, 3, 11 and 12
Basis; 1000 Ib air compressed/hr.
Design intermediate temperature, °F 160
Dry cooler area, ft /1000 Ib/hr 40.059
2
Wet cooler area, ft /1000 Ib/hr 83.853
Circulation rate, gpm/1000 Ib/hr 3.046
Average fan & pump energy, kw-hr/1000 Ib 0.509
Compression energy, kw-hr/1000 Ib 28.140
Water consumed, gal/1000 Ib 1.367
TABLE 2-15. ANNUAL AVERAGE COST FOR WET/DRY COMPRESSOR INTERSTAGE COOLING FOR
AIR COMPRESSORS AT FARMINGTON, N.M. WITH WET COOLER OFF
FOR MONTHS 1, 2, 3, 11 AND 12
Basis: 1000 Ib air compressed/hr
Design intermediate temperature, °F 160
Dry cooler cost, C/1000 Ib 2.140
Wet cooler cost, C/1000 Ib 2.636
Tower cost, C/1000 Ib 0.131
Fan and pump energy, C/1000 Ib 1.018
Compression energy cost, C/1000 Ib 59.263
Total, C/1000 Ib compressed 65.188
Water consumed, gal/1000 Ib 1.367
93
-------
so,
th(ek-l) = ek(VQw/RL) - TX (56)
where
(57)
If the cold water temperature calculated this way is colder than the value
given by the cooling tower curves at the prevailing wet bulb temperature and
hot water temperature, then T . has been chosen too low and a higher temper-
2 , i
ature must be tried.
8) Steps 5, 6 and 7 are then repeated for Stage 2. This will result in
a hot and cold water temperature different from those calculated in Step 7.
However, the cold water to both wet coolers must have the same temperature
because it all comes from the same cooling tower basin. The hot water temper-
ature to the tower is the temperature resulting from mixing the two streams.
It is necessary, therefore, to determine those hot and cold water temperatures
which satisfy the calculations for both stages. In fact the cold water
temperatures for the two stages found by the above procedure did not differ
very much. For a second iteration an average cold water temperature was taken.
This allows calculation without further use of the cooling tower curves.
If t, is eliminated from Equations (54) and (55) one obtains
w w T - t - Q /R (58)
ln T° - t"
1 C
A convenient procedure is to assume T. , calculate Q from Equation (52) and
to use the calculated value of Q in the right hand side of Equation (58) to
redetermine Q . A few iterations give the correct value of T and 0 .
*
w
The procedure is to return to Step 7 and recalculate T . using
2,1
Equation (58) . T is calculated using Equation (48) T is calculated
^ / *-* X / 2,
94
-------
as described in Step 6. T is calculated using Equation (58) again, and
calculation proceeds to the exit of the system. The hot circulating water
temperature is given by
t (average) = V* + Q",2 + Qw,3 + \ (\,l + \,2 + \,
^r -i "*" ^r o ~*~ ^-T o
Lt r j. JU;Z Li r 3
9) For air separation there is little benefit to having T . < 95°F so
air
the third stage water cooler is turned off when T v ,<. 95°F.
X, 3
10) The calculations of all the temperatures are made month by month
beginning with the hottest month and continuing through successively cooler
months. In the colder months little benefit is obtained from the wet cooler.
The purpose of the wet cooler is to decrease the energy consumed in compression.
When (T -T.) < 5°F, the wet cooler gives less than one percent reduction in
A J-
compression energy and we turned off the wet coolers, circulating water and
tower when T -T. < 5°F. This occurred only at Beulah, North Dakota.
X 1
11) From the above calculations the grand total wet load each month is
known, and so the water evaporated can now be calculated using the procedure
previously given.
12) The fan and pump energies are calculated as previously described.
13) The compression energy is calculated from Equation (41).
2.3.4 Best Results
The results for Farmington, New Mexico, Casper, Wyoming and Beulah, North
Dakota are shown on Tables 2- 16 to 2- 18, with summaries on Table 2- 19.
95
-------
TABLE 2-16. CALCULATIONS ON INTERSTAGE COOLING OF AN AIR COMPRESSOR HANDLING 1000 LB AIR/HR
AT FARMINGTON, N.M.
Design intermediate temperature T - 140°F
Design ft2/1000 Ib ft2/1000 Ib lb/1000 Ib gpm/1000 Ib
' AD.l ' 29.306 AWfl - 34.914 Rj.,1 - 298.84 Rg,! - 0.598 Qw,l • 7471
AD,2 " 16.147 Aw>2 - 20.948 Rj.,2 " 298.84 RQr2 " 0.598 5?w,2 * 7471
AD.3 ° 13-027 *w. 3 " 19-506 ^,3 - 347.04 Rg.3 - 0.694 Qw.3 " 8676
Total: 58.480
Month
Tl,o
Tx,l
T
2,i
T
2,o
T
X,2
T
3,i
T3,o
TX,3
Tair
te (avg)
th (avg)
QW1
QW2
°W3
Total QM
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
75.368
1
146.5
62
55
183
69
60
189
71
71
54
60
1687
2169
o
3856
0.655
0.011
0.029
26.482
0.267
2
155.3
70
62
191
77
66
196
78
78
59
68
1928
2651
0
4579
0.655
0.011
0.029
26.830
0.337
944.72
3
166.4
80
69
200
86
73
205
87
87
65
75
2651
3133
0
5784
0.655
0.011
0.029
27.231
0.449
4
175.2
87
74
206
92
77
210
94
94
68
80
3133
3615
0
6748
0.655
0.011
0.029
27.509
0.588
1.890
5
189.0
99
83
218
104
86
221
105
84
76
90
3856
4338
5061
13255
0.655
0.017
0.046
28.240
1.177
6
201.4
110
90
226
113
92
229
114
89
81
97
4820
5061
6025
15906
0.655
0.017
0.046
28.414
1.460
23,618
7
208.9
116
95
233
119
97
235
120
94
85
103
5061
5302
6266
16629
0.655
0.017
0.046
28.693
1.578
Cooling Tower Characteristic
KaY/L • 1.24
WA ^ Ai*/f?A4 PA^ A in TOW*»T*
naucc/ uoa nd to .LH A uwtsjt
RL/RA - 2.12
8
205.2
113
93
230
116
95
233
117
92
84
100
4820
5061
6025
15906
0.655
0.017
0.046
28.571
1.493
9
194.0
103
86
221
107
88
224
108
86
78
93
4097
4579
5302
13978
0.655
0.017
0.046
28.171
1.257
10
178.0
90
76
209
95
79
213
96
77
70
83
3374
3856
4338
11568
0.655
0.017
0.046
27.614
0.936
11 12
162.8 147.8
77 64
67 57
198 185
83 71
71 61
203 190
84 72
84 72
63 55
72 62
2410 1687
2892 2410
0 0
5302 4097
0.655 0.655
0.011 0.011
0.029 0.029
27.109 26.552
0.396 0.278
(continued)
-------
TABLE 2-16 (continued)
Design intermediate temperature T - 160°F; Fraction dry load - 0.638
Design ft2/1000 Ib
AD,1 " 19.688 /
AD|2 = 11.26 /
Ap , «= 9.111 ;
Total: 40.059
Month
T,
1.0
Tx,i
T2,i
T
2,o
T
X,2
T
T3,i
T
3,o
T
X,3
T ,
air
tc (avg)
th (avg)
OKI
QW2
QW3
Total Qw
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
x
ft2/1000 Ib
H»,l "
VW,2 •
VW,3 -
1
146.5
80
62
191
93
68
199
97
67
59
70
4338
6025
7230
17593
0.449
0.027
0.075
26.743
1.147
39.61
23.767
20.476
83.853
2
lb/1000 Ib gpm/1000
RL,I - 491
RL,2 - 491
RL,3 " 539
1523
3
155.3 166.4
88
68
199
101
75
208
104
73
64
75
4820
6266
7471
18557
0.449
0.027
0.075
27.091
1.302
98
75
208
110
80
214
112
78
72,
86
5543
7230
8194
.64 HB.! - 0.
.64 R
.84 R
.12
4
175.2
106
78
211
115
84
219
118
82
72
86
6748
7471
8676
20967 22895
0.449
0.027
0.075
0.449
0.027
0.075
27.457 27.701
1.613
1.880
5,2 ' 0.
G.3 " !•
3.
5
189.0
118
87
223
127
91
228
126
87
79
96
7471
8676
9399
25546
0.449
0.027
0.075
28.171
2.242
Ib
983 Qwf
983 Owf
080 Qu
046
6
201.4
129
94
231
136
96
234
137
93
84
102
8435
9640
10604
28679
0.449
0.027
0.075
28.554
2.639
1 - 12,
2 " 12,
3 " ill.
38,
7
208.
136
98
236
141
101
240
143
98
88
107
9158
9833
10848
29839
0.449
0.027
0.075
28.815
2.760
291 Cooling Tower Characteristic
291 KaY/L - 1.
Water/Gas
078 RL/RA - 2.
8 9
9 205.2 194,
132 122
96 90
234 226
139 130
99 93
238 230
140 132
96 90
86 81
105 98
8676 7712
9640 8917
10604 10122
28920 26751
0.449 0.449
0.027 0.027
0.075 0.075
28.693 28.327
2.674 2.372
24
Rate in
12
Tower
10 11
0 178.
108
82
216
118
88
224
122
85
76
90
6266
7230
8917
22413
0.449
0.027
0.075
27.875
1.837
0 162.8
95
73
205
107
78
211
109
77
68
80
5302
6989
7712
20003
0.449
0.027
0.075
27.335
1.475
12
147.8
61
63
193
95
69
200
98
68
60
70
4338
6266
7230
17834
0.449
0.027
0.075
26.795
1.207
(continued)
-------
TABLE 2-16 (continued)
03
Design intermediate temperature
Design ft2/1000 ib
AD<1 - 12.743 I
AD,2 " 7.779 '
An', - 6.297 J
'
Totalt 26.819
Month
T,
1,0
Tx,l
T2 i
T,
2,0
T
X,2
T3,i
T,
3,0
T ,
X,3
T .
air
t (avg)
c
th (avg)
QW1
QW2
QW3
Total Qw
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
ft2/100
V,l ' 4
^W,2 ' 2
V3-2
T - 180»F
X
0 Ib lb/1000 Ib gpm/1000 Ib
3.485 RL,i " 684.44 RG,I - 1.369 Qwfl - 17,11
6.091 RL 2 * 684.44 RQ 2 " 1.369 QW 2 " 17,11
1.647 RT.., - 732.64 R,/, - 1.465 Qu -, - 18,31
91.123
1
146.5
98
63
193
116
73
205
122
71
59
73
8435
10363
12291
31089
0.300
0.037
0.103
26.847
2.106
2
155.3
106
67
198
122
77
210
128
75
66
82
9399
10845
12773
33017
0.300
0.037
0.103
27.109
2.416
"
2101.52
3
166.4
116
78
211
133
84
219
137
82
72
87
9158
11809
13255
34222
0.300
0.037
0.103
27.579
2.654
4
175.2
124
82
216
139
87
223
143
84
74
91
10122
12532
14219
36873
0.300
0.037
0.103
27.823
3.070
*
4.203
5
189.0
137
90
226
149
94
231
152
91
.81
100
11327
13255
14701
39283
0.300
0.037
0.103
28.275
3.463
6
201.4
148
96
234
158
98
236
159
94
85
105
12532
14460
15665
42657
0.300
0.037
0.103
28.623
3.891
1 Cooling Towe
1 KaY/L • 1.24
— Water/Gas Ra
r Characteristic
ite in Tower
52,538 Rj/RA - 2.12
7
208.9
155
100
239
164
102
241
165
99
88
110
13255
14942
15906
44103
0.300
0.037
0.103
28.867
4.165
8
205.2
152
98
236
161
101
240
163
97
87
108
13014
14460
15906
43380
0.300
0.037
0.103
28.763
4.046
9
194.0
142
92
229
153
96
234
156
92
83
101
12050
13737
15424
41211
0.300
0.037
0.103
28.414
3.665
10
178.0
127
87
223
144
90
226
145
86
73
89
9640
13014
14219
36873
0.300
0.037
0.103
27.997
3.035
11 12
162.8 147.8
113 99
77 63
210 193
131 116
84 73
219 205
136 123
82 72
71 59
86 73
8676 8676
11327 10363
13014 12291
33017 31330
0.300 0.300
0.037 0.037
0.103 0.103
27.509 26.865
2.511 2.142
(continued)
-------
TABLE 2-16 (continued)
in intermediate temperature
jn £t2/1000 Ib
AD,1 "0 *
AD,2 = ° «
AD,3 a ° *
Total: 0
Month
T
' l.o
T
X.I
T
T2,i
T
2,0
TX 2
T3 i
T,
3,o
T ,
X,3
T .
air
tQ (avg)
th (avg)
Q
Q
Qw3
Total Qw
il air fan energy
cw-hr/1000 Ib)
>r fan energy
cw-hr/1000 Ib)
:ulation pump energy
tw-hr/1000 Ib)
sression energy
cw-hr/1000 Ib)
;r consumed
ft2/100
•W,l - 5
'W,2 " 3
^W 3 *"
T - all wet
X
0 Ib lb/1000 Ib gpm/lOOq Ib
1.365 RL,1 " 1224.28 R- j. - 2.449 Cw,]
0.820 RL 2 " 1224.28 RI 2 " 2.449 Qw ;
4.375 R,.', - 1272.48 R,,', - 2.545 ft/,
106.560
1
146.5
147
72
204
204
84
219
219
82
66
85
18075
28920
33017
80012
0
0.066
0.183
27.196
5.837
2
155.3
155
77
210
210
89
225
225
87
71
91
18798
29161
33258
81217
0
0.066
0.183
27.492
6.216
3721.04
3
166.4
166
83
218
218
95
233
233
93
77
97
20003
29643
33740
83386
0
0.066
0.183
27.857
6.616
4
175.2
175
86
221
221
98
236
236
95
79
100
21449
29643
33981
85073
0
0.066
0.183
28.084
7.101
*
7.443
5
189.0
189
93
230
230
102
241
241
99
84
106
23136
30848
34222
88206
0
0.066
0.183
28.467
7.796
6
201.4
201
97
235
235
104
244
244
101
86
109
25064
31571
34463
91098
0
0.066
0.183
28.745
8.323
L • 30,607 Cooling Tower Characteristic
; - 30,607 Kay/L " 1.24
• 11 fl 1 5
1 ' Water/Gas Rate in Tower
93,026 Rj/RA - 2.12
7
208.9
209
102
241
241
108
249
249
103
90
114
25787
32053
35186
93026
0
0.066
0.183
29.006
8.639
8
205.2
205
100
239
239
107
248
248
103
89
113
25305
31812
34945
92062 '
0
0.066
0.183
28.902
8.471
9
194.0
194
95
233
233
103
243
243
100
85
108
23859
31330
34463
89652
0
0.066
0.183
28.589
7.902
10
178.0
178
90
226
226
101
240
240
98
83
103
21208
30125
34222
85555
0
0.066
0.183
28.240
7.206
11
162.8
163
81
215
215
94
231
231
92
75
95
19762
29161
33499
82422
0
0.066
0.183
27.753
6.532
12
147.8
148
73
205
205
85
220
220
83
67
86
18075
28920
33017
80012
0
0.066
0.183
27.248
5.942
(gal/1000 Ib)
-------
o
o
TABLE 2-17. CALCULATIONS ON INTERSTAGE COOLING OF AN AIR COMPRESSOR HANDLING 1000 LBS AIR/HR
AT CASPER, WYOMING
Design intermediate temperature T - 140°P
Design ft2/1000 Ib
AD,1 ' 28.156 1
ADf2 - 14.334 I
ADi3 - 11.572 l
Total: 54.052
Month
Tl.o
Tx,l
T
T2,o
T
X.2
T
T3,i
T3,o
TX,3
Tair
tc (avg)
th (avg)
Qwl
QW2
QW3
Total Cw
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
ft*/ioo
*W,1 • 3
V2 " 2
X3 " ^
X
0 Ib lb/1000 Ib gpm/1000 Ib
4.914 RL<1 - 298.84 R x - 0.598 Qw x - 7471
:0.948 RL>2 - 298.84 R '2 - 0.598 Q^' 2 - 7471
9.506 RT , - 347.04 R^', - 0.694 ft,', . 8676
75.368
1
144.0
62
55
183
75
62
191
77
77
54
61
1687
3133
0
4820
0.605
.0.011
0.029
26.482
0.304
2
146.5
64
57
185
77
64
194
80
80
56
63
1687
3133
0
4820
0.605
0.011
0.029
26.586
0.314
944.72
3
154.0
71
64
194
84
70
201
86
86
60
68
1687
3374
0
5061
0.605
0.011
0.029
26.917
0.354
4
165.2
80
70
201
92
77
210
95
76
67
77
2410
3615
4579
10604
0.605
0.017
0.046
27.300
0.810
1.890
5
181.5
95
81
215
105
87
223
108
85
76
89
3374
4338
5543
13255
0.605
0.017
0.046
27.892
1.134
6
195.2
106
89
225
116
95
233
119
93
82
98
4097
5061
6266
15424
0.605
0.017
0.046
28.362
1.392
23,618
7
202.7
113
93
230
122
99
238
124
96
85
102
4820
5543
6748
17111
0.605
0.017
0.046
28.606
1.580
Cooling Tower Characteristic
KaY/L -1.17
Hater/Gas Rate in Tower
R /R -2.24
L A
B
201.4
112
92
229
121
98
237
123
95
84
101
4820
5543
6748
17111
0.605
0.017
0.046
28.554
1.570
9
187.7
100
83
218
110
89
225
112
87
76
92
4097
5061
6025
15183
0.605
0.017
0.046
28.049
1.327
10
172.7
87
75
208
98
82
216
101
81
70
83
2892
3856
4820
11568
0.605
0.017
0.046
27.579
0.927
11
154.0
71
64
194
84
70
201
86
86
60
68
1687
3374
0
5061
0.605
0.011
0.029
26.917
0.354
12
151.5
69
61
190
81
63
199
84
84
59
68
1928
3133
0
5061
0.605
0.011
0.029
26.795
0.349
(continued)
-------
TABLE 2-17 (continued)
Design intermediate temperature T • 160*P
Design ft2/1000 lb ft2/1000 lb
AD,1 ' 18.890 AWfj • 39.612 R
AD,2 " 11.037 AWf2 " 23.767 R
lb/1000 lb gpm/1000
L,l • 491.64 RG,I " 0.
L.2 " 491.64 R-,2 " 0.
A,,^ - 9.396 Au , • 20.476 RT..I - 539.84 R^' •> - 1.
Total: 39.323
Month
T
Tx',I
T2,i
T,
2,0
T
X,2
T
T3,i
T,
3,0
T ,
X,3
T .
air
tc (avg)
th (avg)
Qwl
Q
Q
Total Qw
Total air fan energy
(kw-hr/1000 lb)
Tower fan energy
(kw-hr/1000 lb)
Circulation pump energy
(kw-hr/1000 lb)
Compression energy
(kw-hr/1000 lb)
Hater consumed
(gal/1000 lb)
83.855
1
144.0
80
61
190
93
67
198
93
64
57
68
4579
6266
6989
17834
0.440
0.027
0.075
26.67
1.151
2
146.5
82
63
193
95
69
200
95
66
59
70
4579
6266
6989
17834
0.440
0.027
0.075
26.78
1.216
1523.12
3
154.0
89
69
200
102
75
208
102
72
65(
76
4820
6507
7230
18557
0.440
0.027
0.075
27.09
1.314
4
165.2
99
76
209
111
82
216
110
79
71
84
5543
6989
7471
20003
0.440
0.027
0.075
27.49
1.535
3.
5
181.5
113
85
220
123
89
225
122
86
77
93
6748
8194
8676
23618
0.440
0.027
0.075
28.00
2.000
lb
983 Qw,l * 12,291 Cooling Tower Characteristic
983 Qw,2 " 12,291 KaY/L - 1.17
080 QW,:
046
6
195.2
125
93
230
134
96
234
130
91
84
101
7712
9158
9399
26269
0.440
0.027
0.075
28.45
2.343
1 • 13,496 Watb*/w« Ml.D
*«»M 4 W» »f»
38,078 RL/\ "2.24
7 B
202.7 201.4
132 131
96 95
234 233
139 138
100 99
239 238
138 137
96 95
86 86
105 104
8676 8676
9399 9399
10122 10122
28197 28197
0.440 0.440
0.027 0.027
0.075 0.075
28.68 28.62
2.571 2.563
9
187.7
119
86
221
126
89
225
125
86
77
93
7953
8917
9399
26269
0.440
0.027
0.075
28.10
2.367
10
172.7
105
80
214
116
85
220
116
82
74
88
6025
7471
8194
21690
0.440
0.027
0.075
27.72
1.755
11
134.0
89
69
200
102
75
208
102
72
65
76
4820
6507
7230
18557
0.440
0.027
0.075
27.09
1.314
12
151.5
86
66
196
99
72
204
99
69
62
74
4820
6507
7230
18557
0.440
0,027
0.075
26.95
1.224
(cdntinued)
-------
TABLE 2-17 (continued)
Design intermediate temperature T • 180°F
O
to
Design ft2/1000 Ib ft2/1000 Ib lb/1000 Ib gpm/1000 Ib
AD,1 " 12.254 AW(1 - 43.485 RL,i " 684.44 R-fl - 1.369 Qw,l » 17,111 Cooling Tower Characteristic
AD,2 ' 6.255 AW(2 " 26.091 RLf2 " 684.44 R^ " 1.369 Qqi2 " 17,111 KaY/L - 1.17
AD,3 " 5.068 AW(3 • 21.647 RL(3 - 732.64 t\j'3 - 1.465 QW 3 - 18,316
Total: 23.577
Month
T
vl
T2,i
T
2,o
T -
X,2
T3,i
T,
3,0
T
X,3
T ,
air
tc (avg)
th (avg)
QW1
°W2
2*3
Total Qw
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
-------
TABLE 2-17 (continued)
o
CO
Jesign intermediate temperature
)esign ft2/1000 Ib
AD , 1 * 0
AD,2 - 0
AD,3 - °
Total: 0
Month
T
1,0
T
Tz!i
T2]o
TX,2
T3,i
T,
3,0
T ,
X,3
T .
air
t (avg)
c
th (avg)
QW1
CW2
QW3
Total Qw
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
ft2/100
AW 1 m ^
AW 2 ™ ^
AW,3 ' I
T - all wet
0 Ib lb/1000 Ib gpm/1000 Ib
1.134 RLfi • 1205.0 R ! - 2.410 Cwfl - 30,125 Coo!
0.681 RLi2 - 1205.0 RQ 2 " 2-410 QW 2 " 30,125 KaY,
4.292 Rr.', - 1253.2 R_', -2.506 ft,', - 31,330 ...
106.107
1
144.0
144
69
200
200
78
211
211
77
61
81
18075
29402
32294
79771
0
0.065
Circulation pump energy 0.180
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
27.004
5.890
2
146.5
147
73
205
205
83
218
218
82
66
86
17834
29402
32776
80012
0
0.065
0.180
27.196
5.949
*
3663.2
3
154.0
154
78
211
211
89
225
225
88
72
91
18316
29402
33017
80735
0
0.065
0.180
27.492
6.223
4
165.2
165
86
221
221
98
236
236
96
79
100
19039
29643
33740
82422
0
0.065
0.180
27.944
6.577
7.326
5
181.5
182
91
228
228
102
241'
241
100
83
105
21931
30366
33981
86278
0
0.065
0.180
28.327
7.362
6
195.2
195
98
236
236
106
246
246
102
88
111
23377
31330
34704
89411
0
0.065
0.180
28.710
7.951
Ling Towi
(It - 1.1'
sr/Gas R<
it Characteristic
J
ate in Tower
91,580 R /R - 2.24
L A
7
202.7
203
100
239
239
108
249
249
104
90
113
24823
31571
34945
91339
0
0.065
0.180
28.885
8.285
8
201.4
201
99
238
238
107
248
248
103
89
112
24582
31571
34945
91098
0
0.065
0.180
28.832
8.245
9
187.7
188
95
233
233
106
246
246
102
87
109
22413
30607
34704
87724
0
0.065
0.180
28.554
7.657
10
172.7
173
88
224
224
99
238
238
97
81
102
20485
30125
33981
84591
0
0.065
0.180
28.101
7.028
11
154.0
154
78
211
211
89
225
225
88
72
91
18316
29402
33017
80735
0
0.065
0.180
27.492
6.223
12
151.5
152
76
209
209
85
220
220
84
69
88
18316
29884
32776
80976
0
0.065
0.180
27.352
6.184
-------
TABLE 2-18 CALCULATIONS ON INTERSTAGE COOLING OF AN AIR COMPRESSOR HANDLING 1000 LBS AIR/HR
AT BEULAH, NORTH DAKOTA
Design ft2/1000 Ib
AD,1 = 31'92
AD,2 = 20'19
A^ , = 13.16
\J t 3
Total: 65.27
Month
T,
1,0
T
X,l
T
2,i
T,
2,O
T
X,2
T. .
3,1
T
3,0
T
X,3
air
t (avg)
c
t (avg)
QW1
QW2
QW3
Total 0
ft2/1000
Vi-
V3--
1
124.
33
33
155
49
49
175
54
54
_
-
0
0
0
0
X
Ib lb/1000 Ib
34.91 R^
20.95 Rj^
19.46 R,
75.32
tf
0 132.7
40
40
164
56
56
184
62
62
_
-
0
0
0
0
l = 298.
2 = 298'
3 = 347'
i J
944.
3
144.0
50
50
176
66
66
196
71
71
_
-
0
0
0
0
X
gpiii/1000 Ib
8 RG,1
8 RG,2
0 R_ ,
— G,3
6
4
167.7
70
64
194
84
69
200
86
86
61
76
1470
3770
0
5240
= 0.598
= 0.598
= 0.694
1.890
5
183.9
83
74
206
97
79
213
99
78
70
82
2090
4400
5180
11670
QW,1
QW 2
n t £.
QW,3
6
195.1
93
82
216
107
87
223
108
86
77
91
2580
4890
5580
13050
= 7,471
» 7,471
= 8,676
23,616
7
203.9
100
83
218
112
88
224
114
86
75
93
4050
6070
6990
17110
Cooling Tower Characteristic
KaY/L
= 1.30
Water/Gas Rate
RL/RA = 1.85
6
201.4
98
85
220
111
90
226
113
88
79
94
3070
5240
6040
14350
9
186.4
85
78
211
101
84
219
102
83
75
86
1600
42GO
4880
10740
in Tower
10
171.4
73
67
198
88
73 •
205
90
90
65
79
1250
3770
0
5020
11 12
148.9 136.5
54 44
54 44
181 169
70 60
70 60
201 189
76 65
76 65
-
-
0 0
0 0
0 0
0 0
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
0.731 0.731 0.731 0.731 0.731 0.731 0.731 0.731 0.731 0.731 0.731 0.731
000 0.011 0.017 0.017 0.017 0.017 0.017 0.011 0 0
000 0.029 0.046 0.046 0.046 0.046 0.046 0.029 0 0
25.562 25.928 26.432 27.059 27.633 28.068 28.225 28.259 27.824 27.233 26.641 26.119
000 0.423 0.992 1.226 1.624 1.367 0.974 0.407 0 0
(continued)
-------
TABLE 2-18 (Continued)
Design intermediate temperature T
160°F
Design ft2/1000 Ib ft2/1000 Ib lb/1000 Ib
Ag = 21.56 AW = 39.61 R^ . = 491
t^i2 = 13.64 AW(2 = 23.76 ^ 2 = 491
ftf, , = 8.90 \, , - 20.88 R, , = 539
\J t 3 — W
Total: 44.10
Month
T,
1,0
T
T
2,1
T2,o
T
T
3,1
T,
3,0
TX,3
T ,
air
t (avg)
c
t^ (avg)
QW1
QW2
QW3
Total QM
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
r, -> u,
84.25
1 2
124.0 132.7
49 57
49 57
175 185
78 86
56 60
184 189
82 88
82 88
50 52
61 65
0 0
5180 6360
0 0
5180 6360
0.494 0.494
0.009 0.009
0.024 0.024
25.963 26.293
0.263 0.375
1523
3
144.0
67
67
198
97
68
199
97
67
60
74
0
6850
7180
14030
0.494
0.018
0.051
26.763
0.920
gpm/1000 Ib
.6 RQ t = 0.98
.6 RG 2 = 0.98
.8 R = 1.08
G,3
.0
4
167.7
87
72
204
110
78
211
113
77
68
81
3510
7860
8790
20160
0.494
0.027
0.075
27.355
1.578
3 QW(1
13 ^W 2
0 QW,'3
3.046
5
183.9
101
79
213
121
84
219
124
81
73
89
5180
8950
9680
23810
0.494
0.027
0.075
27.807
1.922
6
195.1
111
88
224
131
92
229
133
91
81
97
5600
9280
10110
24990
0.494
0.027
0.075
28.259
2.332
= 12,291 Cooling Tower Characteristic
= 12,291
Water/Gas Rate in Tower
= 13^496 / = 1-85
T, A
30,078
7
203.9
119
94
231
138
98
236
140
96
86
103
6190
9700
10450
26340
0.494
0.027
0.075
28.590
2.519
8
201.4
117
92
229
136
97
235
139
96
85
102
5930
9530
10580
26040
0.494
0.027
0.075
28.503
2.461
9
186.4
104
84
219
125
89
225
128
88
78
93
4850
8780
9770
21390
0.494
0.027
0.075
28.016
2.036
10
171.4
90
73
205
112
78
211
115
77
68
82
4070
8190
9130
23400
0.494
0.027
0.075
27.424
1.720
11
148.9
71
66
196
98
73
205
102
72
65
77
1080
6190
7180
14450
0.494
0.027
0.075
26.902
0.978
12
136.5
60
60
189
89
70
201
94
94
64
74
0
4680
0
4680
0.494
0.009
0.024
26.572
0.263
(continued)
-------
TABLE 2-18 (Continued)
Design intermediate temperature T
180°F
Design ft2/1000 Ib ft2/1000 Ib
AD = 14.28 AW = 43.
A = 5.91 A,.', = 22.
U, J
Total: 29.24
Month
Tl,o
T
T
2,i
T,
2,o
T
X,2
T. .
3,1
T,
3,o
T
AX,3
T
air
tc (avg)
^ (avg)
Q
QM2
QW3
Total Q,.,
" F -*
91.
1
124.0
66
49
175
101
55
183
81
81
45
56
4220
11170
0
15390
lb/1000 Ib
48 R = 684.
Li, 1
09 R, _ = 684.
iif 2
34 R, , = 732.
L, 3
91
2
132.7
74
54
181
108
60
189
88
88
50
62
4750
11520
0
16270
2101.
3
144.0
84
63
193
119
70
201
98
65
59
71
4930
12010
7980
24920
gpm/1000
4 RG,2
£ RG,3
4
4
167.7
106
75
207
135
81
215
106
75
69
82
7300
13190
7620
28110
Ib
= 1.369
= 1.369
= 1.465
4.203
5
183. 9
120
84
219
147
89
225
127
84
76
92
8800
14210
10460
33470
CW,2
• QW,3 =
6
195.1
131
90
226
155
94
231
134
89
81
98
9980
14740
10820
35540
17,111
17,111
18,316
52,538
7
203.9
138
96
234
163
101
240
142
96
87
104
10160
15220
11330
36710
Cooling Tower Characteristic
KaY/L =1.30
Water/Gas Rate in Tower
R1/RA = 1-85
8
201.4
136
94
231
160
98
236
139
93
85
102
10160
14910
11000
36070
9
186.4
123
87
223
150
91
228
129
87
79
95
8800
14080
10280
33160
10
171.4
109
78
211
138
83-
218
118
78
71
87
7610
13370
9580
30560
11
148.9
89
68
199
124
75
208
103
70
64
76
4930
12010
7980
24920
12
136.5
78
60
189
114
66
196
92
92
56
68
4390
11520
0
15910
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
0.327 0.327 0.327 0.327 0.327 0.327
0.024 0.024 0.037 0.037 0.037 0.037
0.067 0.067 0.103 0.103 0.103 0.103
25.945 26.241 26.728 27.459 27.981 28.329
0.790 0.950 1.624 2.223 2.836 3.341
0.327 0.327 0.375 0.327 0.327 0.327
0.037 0.037 0.037 0.037 0.037 0.024
0.103 0.103 0.103 0.103 0.103 0.067
28.677 28.555 28.103 27.598 26.972 26.502
3.491 3.409 2.891 2.468 1.677 0.950
(continued)
-------
TABLE 2-18 (Concluded)
o
-j
Design intermediate temperature T
= all wet
Design ft2/ 1000 Ib ft2/ 1000 Ib lb/1000 Ib
AD,1 = ° *W 1 = 51-95 \ i = 1275-
AD,2 = ° *ll.2 " 31'74 V2 = 1359'
A^ .. = 0 PL , •= 26.29 R, , = 1407.
'
Total: 0
Month
Tl,o
T
T2 i
T2,o
T
XX,2
T3 i
T3 o
T
X,3
T .
air
t (avg)
t^ (avg)
QW1
QW2
QW3
Total Qw
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
, j
110.00
1
124.0
124
59
188
188
65
195
195
65
52
71
15500
29600
31550
76650
0
0.078
0.217
26293
4.538
2
132.7
133
62
191
191
67
198
198
67
54
73
17090
29800
31750
78640
0
0.078
0.217
26502
5.110
4042.
3
144.0
144
70
201
201
75
208
208
75
62
82
17660
30180
32130
79970
0
0.078
0.217
26937
5.508
gpm/1000
4 R« ••
2 <2
4 RG,3
0
4
167.7
168
82
216
216
87
223
223
86
73
94
20390
31220
32910
84520
0
0.078
0.217
27685
6.688
Ib
= 2.551 QWjl -
= 2.718 Qw 2 =
8.084
5
183.9
184
90
226
226
94
231
231
93
80
102
22360
31800
33100
87260
0
0.078
0.217
28172
7.344
6
195.1
195
96
234
234
100
239
239
99
85
107
23760
32630
33980
90370
0
0.078
0.217
28538
8.210
' 31,884
'• 33,981
' 35,186
101,051
7
203.9
204
99
238
238
102
241
241
101
88
111
24900
32560
33490
90950
0
0.078
0.217
28747
8.542
Cooling Tower Characteristic
KaY/L =1.30
Water/Gas Rate in Tower
8
201.4
201
99
238
238
102
241
241
101
87
110
25350
33020
33980
92350
0
0.078
0.217
28712
8.656
9
186.4
187
92
229
229
97
235
235
96
82
104
22500
32250
33780
88530
0
0.078
0.217
28294
7.738
10
171.4
171
87
223
223
92
229
229
92
78
99
20010
31600
33400
85010
0
0.078
0.217
27911
6.898
11
148.9
149
76
209
209
82
216
216
81
68
88
17470
30830
32520
80820
0
0.078
0.217
27233
5.770
12
136.5
137
68
199
199
75
208
208
74
61
81
16260
30250
32330
78840
0
0.078
0.217
26798
5.246
-------
TABLE 2-19 SUMMARY OF WET/DRY COMPRESSOR INTERSTAGE COOLING
FOR AIR COMPRESSOR
Farmington, New Mexico
Basis: 1000 Ib air compressed/hr.
Design intermediate temperature, °F 140 160 180 all wet
Dry cooler area, ft2/1000 lb/hr 58.480 40.059 26.819 0
Wet cooler area, ft2/1000 lb/hr 75.368 83.853 91.123 106.560
Circulation rate, gpm/1000 lb/hr 1.890 3.046 4.203 7.443
Avg. fan & pump energy, kw-hr/1000 Ib 0.704 0.551 0.440 0.249
Compression energy, kw-hr/1000 Ib 27.618 27.796 27.889 28.132
Water consumed, gal/1000 Ib 0.851 1.929 3.097 7.215
Casper, Wyoming
Basis: 1000 Ib/air compressed/hr.
Design intermediate temperature, °F 140 160 180 all wet
Dry cooler area, ft2/1000 Ib 54.052 39.323 23.577 0
Wet cooler area, ft2/1000 Ib 75.368 83.855 91.123 106.107
Circulation rate, gpm/1000 lb/hr 1.890 3.046 4.203 7.326
Avg. fan & pump energy, kw-hr/1000 Ib 0.658 0.542 0.404 0.245
Compression energy, kw-hr/1000 Ib 27.503 27-640 27.839 27.991
Water consumed, gal/1000 Ib 0.868 1.779 3.275 6.965
Beulah, North Dakota
Basis; 1000 Ib air compressed/hr.
Design intermediate temperature, °F 140 160 180 all wet
Dry cooler area, ft /1000 lb/hr 65.27 44.10 29.24 0
Wet cooler area, ft2/1000 lb/hr 75.32 84.75 91.91 110.0
Circulation rate, gpm/1000 lb/hr 1.890 3.046 4.203 8.084
Avg. fan & pump energy, kw-hr/1000 Ib 0.764 0.576 0.455 0.295
Compression energy, kw-hr/1000 Ib 27.082 27.371 27.424 27.652
Water consumed, gal/1000 Ib 0.584 1.447 2.221 6.686
108
-------
2.4 HYDROGEN COMPRESSORS IN COAL CONVERSION PLANTS
Hydrogen compressors are important in direct hydrogenation plants,
mostly coal liquification and solvent refined coal plants. The energy con-
sumed in compressing a gas is inversely proportional to the molecular weight
and hydrogen compressors will not be the same as air compressors.
The example chosen for study is shown on Figure 2-24. Hydrogen is
assumed to be produced at 400 psia and 95°F leaving the gas purification
system. A three stage compressor, having a compression ratio of 2.15 per
stage, is used to compress the hydrogen to 4000 psi. The compressed hydrogen
is used hot so coolers do not follow stage three.
For hydrogen the following values apply:
w = 16.67 Ib/min = 1000 Ib/hr
e = 0.77, polytropic efficiency
Z Z = 1.0, compressibility at suction and discharge
k = 1.41, ratio of specific heats
M = 2, molecular weight (n-l)/n = 0.378
c = 3.47 btu/(lb)(°F)
Calculations proceed as for the air compressor already described, with changes
for the change in gas. Stage outlet temperatures are calculated from stage
inlet temperatures by Equation (40) which becomes
T = 1.336 T. (60)
o i
replacing Equation (48). It must not be forgotten that the temperatures in
Equation (60) are in °R (= 460 + °F). The compression power per stage is
P = 1.0 Ti (r°-378 - 1)
= 0.336 T. (61)
which replaces Equation (44). The load on a cooler is
Q = 3460 (T. - T ) (62)
* in out
which replaces Equation (47).
109
-------
. = 109°F T2,0 = T T, , = 109°F T. n = 300°F
1 300°F 'x ' '
N
2
CX
1850 psia
4000 psia
Figure 2-24. Hydrogen compressor design conditions.
-------
1) The stage outlet temperatures are calculated from Equation (60).
2) The dry cooler areas are calculated as described in Step 2 for air
compressors.
3) The wet cooler areas are calculated as described in Step 3 for air
compressors.
4) The circulating water flow rates are calculated as described in Step
4 for air compressors.
5) Since the entry to Stage 1 is constant at 95°F, the exit is constant
at 281°F.
6) The exit from the first dry cooler, T , is calculated as described
X, 1
in Step 6 for air compressors.
7) A first calculation of T . and of the cold temperature of the
2. ,'i.
circulating water, t , is made as described in Step 7 for air compressors.
8) Stage 2 is calculated by repeating Steps 6 and 7. An average cold
water temperature is determined and the second calculations made as described
under Step 8 for air compressors.
9) The remaining calculations are made as for air compressors.
The results for Farmington, New Mexico, Casper, Wyoming and Beulah, North
Dakota are shown on Table 2-20 to 2-22 with summaries on Table 2-23.
Ill
-------
TABLE 2-20 CALCULATIONS ON INTERSTAGE COOLING OF A HYDROGEN COMPRESSOR HANDLING 1000 LB H /HR
AT FARMINGTON, NEW MEXICO 2
Design intermediate temperature T « 115°F (all dry)
ft2/iooo
AD,1 = 105
AD,2 * 112
Total: 217
Month
Tl,o
Tx,l
T
2,1
T2,o
T
X,2
T3 i
T,
3,0
t (avg)
t^ (avg)
QW1
QW2
:al cw
iir
lergy
•/1000 Ib)
:an energy
•/1000 Ib)
ition pump
Ib
. 64S •
.096 i
.744
1
281
50
50
221
42
42
211
-
-
0
0
0
2.831
0
0
ft2/1000 Ib lb/1000 Ib gpm/1000 Ib
S/ 2 " °
0
2
281
56
56
229
49
49
220
-
-
0
0
0
2.831
0
0
\
3
281
64
64
240
58
58
232
-
-
0
0
0
2.831
0
0
,1 = 0
,2 * °
0
4
281
71
71
249
65
65
241
-
-
0
0
0
2.831
0
0
RG,1
RG,2
5
281
81
81
263
76
76
256
-
-
0
0
0
2.831
0
0
. * o'
, * o
0
6
281
90
90
275
87
87
271
-
-
0
0
0
2.831
0
0
QV/2
w, *
7
281
95
95
281
93
93
279
-
-
0
0
0
2.831
0
0
• 0
* £
0
8
281
93
93
279
90
90
275
-
-
0
0
0
2.831
0
0
Cooling Tower
Characteristic
KaY/L =1.24
Water/Gas Rate in Tower
RL/FA - 2.12
9
281
84
84
267
80
80
261
-
-
0
0
0
2.831
0
0
10
281
72
72
251
67 .
67
244
-
-
0
0
0
2.831
0
0
11
281
62
62
237
55
55
228
-
-
0
0
0
2.831
0
0
12
281
51
51
223
43
43
212
-
-
0
0
0
2.831
0
0
Total air
fan en
(kw-hr
Tower f
(kw-hr.
Circula
energy
(kw-hr/1000 Ib)
Compression
energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
514.476 518.744 524.326 528.922 535.817 542.383 545.995 544.353 538.115 529.907 522.684 515.133
000000000000
(continued)
-------
TABLE 2-20 ''(Farmington, N.M.) (Continued)
Design intermediate temperature T - 140°F
Design
ft2/iooo
AD 1 " 65
AD'Z " 70
Totals 136
Month
T.
1,0
T
Tx,i
T2 i
T
T2,o
TX,2
T3,i
T,
3,0
t (avg)
th (avg)
QW1
QW2
:al °w
iir
Ib ft2/1000
.636 A,, , - 40.
.394 A/* - 40.
W,2
.030 80.
1
281
85
69
247
72
61
236
58
69
55360
38060
93420
1.768
2
281
90
74
253
79
67
244
64
75
55360
41520
96880
1.768
Ib lb/1000 Ib
100 RL>1 - 4290.
100 R. „ = 4290.
L,
200
3
281
97
79
260
87
73
252
68
81
62280
48440
110720
1.768
8580.
4
281
103
83
265
94
79
260
72
86
69200
51900
121100
1.768
gpm/1000 Ib
4 RQ,! * 8.5808
4 R^ - 8.5808
8
5
281
111
90
275
105
87
271
79
95
72660
62280
134940
1.768
17.1616
6
281
119
96
283
114
93
279
84
102
79580
72660
152240
1.768
W f 2
7
281
124
100
288
120
97
284
87
106
83040
79580
162620
1.768
' 107,260
1 107 , 260
214,520
8
281
121
98
285
117
95
281
85
103
79580
76120
155700
1.768
Cooling Tower Characteristic -
KaY/L = 1.24
water/Gas Rate in Tower
Rj/Rfc - 2.12
9
281
114
92
277
108
89
273
80
97
76120
65740
141860
1.768
10
281
104
86
269
96
81
263
75
89
62280
51900
114180
1.768
11
281
95
78
259
85
72
251
68
80
58820
44980
103800
1.768
12
281
86
70
248
73
63
239
60
71
55360
34600
89960
1.768
Total air
fan energy
(kw-hr/1000 Ib)
Tower fan energy 0.153
(kw-hr/1000 Ib)
Circulation pump 0.422
energy
(kw-hr/1000 Ib)
Compression
energy
(kw-hr/1000 Ib)
Water consumed 6.171
(gal/1000 Ib)
0.153 0.153 0.153 0.153 0.153 0.153 0.153 0.153
0.422 0.422 0.422 0.422 0.422 0.422 0.422 0.422
0.153 0.153 0.153
0.422 0.422 0.422
526.952 530.564 534.175 537.456 542.383 546.323 548.950 547.636 543.697 539.100 533.519 527.937
6.851 8.357 10.058 12.002 14.140 15.306 14.480 12.682
9.329 7.726 5.928
(continued)
-------
TABLE 2-20 (Farmington, N.M.) (Continued)
Design Intermediate temperature T
160"F
ft2/1000
AD.l * 49
AD,2 " 53
Total: 102
Month
Tl
TX!I
T2,i
T,
2,o
TX,2
T3,i
T,
3,o
t (avg)
th (avg)
Qwl
QW2
al ^w
ir
ergy
/1000 Ib)
Ib
.049 A
.462 A
.511
1
281
112
76
256
96
69
247
63
79
124560
93420
217980
1.333
an energy 0.251
/I 000 Ib)
tion pump
0.695
ft2/1000
W.l " 45.
W 2 " 45'
90.
2
281
116
80
261
103
75
255
68
84
124560
96880
221440
1.333
0.251
0.695
Ib lb/1000 Ib gpm/1000 Ib
496 RL,1 - 7058.4 R^.i - 14.117 QW i =
496 R^
992
3
281
123
87
271
112
81
263
74
90
124560
107260
231820
1.333
0.251
0.695
2 - 7058
14116
4
281
128
89
273
118
84
267
76
94
134940
117640
252580
1.333
0.251
0.695
" r 2
.8
5
281
135
95
281
128
92
277
82
101
138400
124560
262960
1.333
0.251
0.695
- 14.117
28.234
6
281
142
99
287
137
97
284
86
106
148780
138400
287180
1.333
0.251
0.695
Qw 2 =
", *
7
281
146
103
292
142
101
289
89
110
148780
141860
290640
1.333
0.251
0.695
176,460
176,460
352,920
8
281
144
101
289
139
99
287
88
108
148780
138400
2871BO
1.333
0.251
0.695
Cooling Tower Characteristic
KaY/L - 1.24
Water/Gas Rate
VRA
9
281
138
96
283
131
93
279
83
102
145320
131480
276800
1.333
0.251
0.695
- 2.12
10
281
129
92
277
120
87
271
79
96
128020
114180
242200
1.333
0.251
0.695
in Tower
11
281
121
85
268
109
80
261
73
89
124560
100340
224900
1.333
0.251
0.695
12
281
113
77
257
98
70
248
64
80
124560
96880
221440
1.333
0.251
0.695
Total air
fan en
(kw-hr
Tower f
(kw-hr.
Circula
energy
(kw-hr/1000 Ib)
Compression
energy
(kw-hr/1000 lb)-
Water consumed
(gal/1000 Ib)
543.436 546.790 551.151 552.829 557.525 560.544 563.228
15.028 16.148 18.306 20.944 23.182 26.300 27.579
561.886 558.196 554.841 550.145 544.107
26.380 24.781 20.065 17.187 15.348
(continued)
-------
TABLE 2-20 (Farmington, N.M.) (Continued)
Design intermediate temperature T - 180°F
Design ft2/1000 Ib ft2/1000
AD i =• 36.860 AW 1 * 49'
A '2 - 41.112 A,.,', - 49.
Total : 77
Month
T,
1,0
T
Tx,l
T2,i
T2,o
TX,2
T3 i
T
3,o
t (avg)
th (avg)
QW1
Q
Total QM
Total air
•»,*
.972
1
281
140
94
280
129
87
271
74
110
159160
145320
304480
1.014
99.
2
281
144
100
288
137
96
283
82
117
152240
141860
294100
1.014
Ib lb/1000 Ib
945 RL(i «• 4290.
945 R. „ - 4290.
L,
890
3
281
149
105
295
145
103
292
88
123
152240
145320
297560
1.014
8580.
4
281
153
107
298
150
105
295
89
125
159160
155700
314860
1.014
gpm/1000 Ib
4 R,rl - 17.165
4 R,' - 17.162
Glf £.
8
5
281
159
111
303
159
112
304
94
132
166080
162620
328700
1.014
! QW 1 =
•- Qw;2 =
34.324
6
281
165
115
308
167
116
310
97
137
173000
176460
349460
1.014
7
281
168
118
312
172
119
314
99
141
173000
183380
356380
1.014
' 107,260
• 107,260
214,520
8
281
166
116
310
170
118
312
98
139
173000
179920
352920
1.014
Cooling Tower Characteristic
KaY/L = 1.24
Water/Gas Rate in Tower
Rr /JL " 212
9
281
161
113
306
163
114
307
95
134
166080
169540
335620
1.014
10
281
154
109
300
152
108
299
92
128
155700
152240
307940
1.014
11
281
147
103
292
142
101
289
66
120
152240
141060
294100
1.014
12
281
141
97
284
132
91
276
78
112
152240
141B60
294100
1.014
fan energy
(kw-hr/1000 Ib)
Tower fan energy 0.557
(kw-hr/1000 Ib)
Circulation pump 0.844
energy
(kw-hr/1000 Ib)
Compression 543.697
energy
(kw-hr/1000 Ib)
Water consumed 24.198
(gal/1000 Ib)
0.557 0.557
0.844 0.844
0.557 0.557 0.557 0.557 0.557 0.557
0.844 0.844 0.844 0.844 0.844 0.844
0.557 0.557 0.557
0.844 0.844 0.844
548.621 552.561 553.875 557.486 560.113 562.083 561.098 558.799 555.52 551.248 545.995
23.809 24.829 27.210 29.640 32.215 33.430 32.555 30.272
26.579 24.198 23.275
(continued)
-------
TABLE 2-20 (Farmington, N.M.) (Concluded)
Design intermediate temperature T « all wet
Design ft2/10l
An 1 = 0
O,l "
30 Ib
Total : 0
Month
Tl,o
Tx,i
T2 i
T,
2,o
T
X,2
T
T3,i
T,
3,0
t (avg)
t^ (avg)
QW1
QM2
Total Qw
Total air
fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump
energy
(kw-hr/1000 Ib)
Compression
energy
(kw-hr/1000 Ib)
Hater consumed
(gal/1000 Ib)
1
281
281
89
273
273
84
267
71
97
664320
653940
1318260
0
0.894
2.472
551.335
99.570
x
ft2/1000 Ib lb/1000 Ib gpm/1000 Ib
AH i = 64.223 Rj.,1 = 23804.8 RQfi - 47.610 Quti
A^' - 66.098 R, „ - 26434.4 R/, - 52.869 Q,./,
130.321
2
281
281
95
281
281
91
276
77
103
643560
657400
1300960
0
0.894
2.472
555.684
101.562
3
281
281
98
285
285
96
283
82
107
633180
653940
1287120
0
0.894
2.472
558.361
102.131
** t
50239.2
4
281
281
99
287
287
97
284
83
108
629720
657400
1287120
0
0.894
2.472
559.030
108.105
5
281
281
101
289
289
101
289
86
110
622800
650480
1273280
0
0.894
2.472
561.037
111.519
", *
100.479
6
281
281
104
294
294
103
292
88
114
612420
660860
1273280
0
0.894
2.472
562.710
116.355
7
281
281
108
299
299
107
298
92
118
598580
664320
1262900
0
0.894
2.472
565.386
116.924
Cooling Tower Characteristic
- 595,120 M't - *-M
- 660,860 Hater/Gas Rate in Tower
1,255,980 'V'Sv "* 2'12
8
281
281
106
296
296
105
295
90
116
605500
660860
1266360
0
0.894
2.472
564.048
116.640
9
281
281
103
292
292
102
291
87
112
615880
657400
1273280
0
0.894
2.472
562.040
112.372
10
281
281
100
288
288
99
287
84
109
626260
653940
1280200
0
0.894
2.472
560.034
107.536
11
281
281
97
284
284
95
281
80
106
636640
653940
1290580
0
0.894
2.472
557.692
102.984
12
281
281
90
275
275
87
271
73
99
660860
650480
1311340
0
0.894
2.472
552.674
99.570
-------
TABLE 2-21 CALCULATIONS ON INTERSTAGE COOLING OF A HYDROGEN COMPRESSOR HANDLING 1000 LB H-/HR
AT CASPER, WYOMING
Design intermediate temperature T - 115°F (all dry)
Design ft2/1000 Ib
AD 1 - 101.220
A,/, « 107.568
Total: 208.788
Month
Tl,o
Tx.i
T2',i
T2.o
T
X,2
T3 i
T,
3,o
t (avg)
c
th (avg)
CW1
QW2
Total Cw
Total air
fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump
energy
(kw-hr/1000 Ib)
Compression
energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
1
281
50
50
221
42
42
211
-
-
0
0
0
2.714
0
0
525.657
0
ft2/1000 Ib
\ 2 " °
",'
0
2
281
52
52
224
44
44
213
-
-
0
0
0
2.714
0
0
526.999
0
lb/1000 Ib gpm/1000 Ib
R, ., - 0 RG „ - 0 !?„ o
i
3
281
58
58
232
50
50
221
-
-
0
0
0
2.714
0
0
531.024
0
0
4
281
66
66
243
59
59
233
-
-
0
0
0
2.714
0
0
536.727
0
5
281
77
77
257
72
72
251
-
-
0
0
0
2.714
0
0
544.778
0
,£. —
0
6
281
87
87
271
83
83
265
-
-
0
0
0
2.714
0
0
551.822
0
7
281
92
92
277
89'
89
273
-
-
0
0
0
2.714
0
0
551.822
0
= 0
- 0
0
8
281
92
92
277
89
89
273
-
-
0
0
0
2.714
0
0
555.512
0
Cooling
KaY/L =
Tower Characteristic
1.17
Water/Gas Rate in Tower
R /R =
L A
9
281
82
82
264
77
77
257
-
-
0
0
0
2.714 2
0
0
548.132 540
0
2.24
10
281
71
71
249
65
65
241
-
-
0
0
0
.714
0
0
.417
0
11
281
58
58
232
50
50
221
-
-
0
0
0
2.714 2
0
0
531.024 529
0
(continued)
12
281
56
56
229
48
48
219
-
-
0
0
0
.714
0
0
.682
0
-------
00
TABLE 2-21 (Casper, Wyoming) (Continued)
Design intermediate temperature T « 160°P
2£ ft /1000
AD,1 * 48
AD,2 ' 52
Total : 100
Month
T.
1,0
Tx,l
T2,i
T
2,0
T
X,2
T .
T,
3,0
tc (avg)
t^ (avg)
Qwl
CW2
Total Qw
il air
i energy
;-hr/1000 Ib)
;r fan energy
f-hr/1000 Ib)
mlation pump
Ib
.149
.516
.665
1
281
113
74
253
96
68
245
61
77
134940
96880
231820
1.309
0.251
0.695
ft2/1000 Ib lb/1000 Ib
*W 1 " 45
A..' " 45
90
2
281
114
76
256
98
70
248
63
79
131480
96880
228360
1.309
0.251
0.695
.496 RL,l
.496 R^ ,
.992
3
281
118
82
264
105
78
259
71
86
124560
93420
217980
1.309
0.251
0.695
- 7058.
" 7058.
14116.
4
281
124
88
272
113
83
265
76
92
124560
103800
228360
1.309
0.251
0.695
gpm/1000 Ib
4 R- i
4 *\5 2
8
5
281
133
94
280
125
91
276
82
100
134940
117640
252580
1.309
0.251
0.695
- 14.117
i - 14.117
28.234
6
281
140
99
287
135
97
284
86
106
141860
131480
273340
1.309
0.251
0.695
Qw,l *
°W,2 '
7
281
144
101
289
139
99
287
88
108
148780
138400
287180
1.309
0.251
0.695
176,460
176,460
352,920
8
281
143
100
288
138
98
285
87
107
148780
138400
287180
1.309
0.251
0.695
Cooling Tower Characteristic
KaY/L
- 1.17
Water/Gas Rate
B /» « *> *>&
*V ' j|l
9
281
136
96
283
129
94
280
84
102
138400
121100
259500
1.309
0.251
0.695
10
281
128
90
275
119
87
271
78
94
131480
110720
242200
1.309
0.251
0.695
in Tower
11 12
281 281
118 117
82 80
264 261
105 102
78 74
259 253
71 68
86 83
124560 128020
93420 96880
217980 224900
1.309 1.309
0.251 0.251
0.695 0.695
energy
(kw-hr/1000 Ib)
Compression
energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
530.892 532.205 536.802 540.413 545.010 548.621 549.935 549.278 546.652 542.383 536.802 534.832
15.585 15.283 15.888 18.082 21.940 23.832
26.404 26.404 22.243 19.746 15.888 16.493
(continued)
-------
TABLE 2-21 (Casper, Wyoming) (Concluded)
Design intermediate temperature T » all wet
Design ft2/1000 Ib
AD.l - 0 '
AD,2 " ° ;
U I «. —
Total : 0
Month
T,
1,0
Tx,i
T
T,
2,0
T „
X,2
T3 i
T,
3,o
t (avg)
t (avg)
QW1
QW2
Total QM
Total air
fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump
energy
(kw-hr/1000 Ib)
Compression
energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
ft2/1000 Ib lb/1000 Ib gpm/1000 Ib
^1 - 64.223 RL,! " 23804.8 RQ,l " 47.610 QW,!
*u , • 66.098 RT , = 26434.4 R,, , " 52.869 Qu ,
130.321
1
281
281
89
273
273
86
269
72
98
664320
647020
1311340
0
0.894
2.472
553.499
98.813
2
281
281
92
277
277
89
273
75
101
653940
650480
1304420
0
0.894
2.472
555.512
98.813
3
281
281
96
283
283
93
279
79
105
640100
657400
1297500
0
0.894
2.472
558.196
102.314
50239.2
4
281
281
101
289
289
100
288
85
110
622800
653940
1276740
0
0.894
2.472
562.221
104.468
5
281
281
103
292
292
102
291
87
112
615880
657400
1273280
0
0.894
2.472
563.563
109.045
100.479
6
281
281
105
295
295
104
294
89
115
608960
660860
1269820
0
0.894
2.472
564.905
113.891
7
281
281
107
298
298
106
296
91
117
602040
664320
1266360
0
0.894
2.472
566.247
115.776
Cooling Tower Characteristic
KaY/L = 1.17
- 595,120
" 660,860 Water/Gas Rate in Tower
1,255,980 'Vft "
8
281
281
106
296
296
105
295
90
116
605500
660860
1266360
0
0.894
2.472
565.576
115.776
9
281
281
103
292
292
101
289
87
112
615880
660860
1276740
0
0.894
2.472
563.228
111.737
10
281
281
101
289
289
100
288
85
110
622800
653940
1276740
0
0.894
2.472
562.221
106.622
11
281
281
96
283
283
93
279
79
105
640100
657400
1297500
0
0.894
2.472
558.196
102.314
12
281
281
94
280
280
91
276
77
103
647020
653940
1300960
0
0.894
2.472
556.854
102.044
-------
TABLE 2-22 CALCULATIONS ON INTERSTAGE COOLING OF A HYDROGEN COMPRESSOR HANDLING 1000 LBS H /HR
AT BEULAH, NORTH DAKOTA
NJ
Design intermediate temperature T = UST (all dry)
Design ft2/1000 Ib ft2/1000 Ib
D,l ' Yl
A „ = 112.931 A = 0
Yi
R, ,
0
0
Total: 239.514
Month
T.
l.o
Tx i
T
2,1
T,
2,o
?„ -
X,2
T3 i
T
3,0
t (avg)
t^ (avg)
-------
TABLE 2-22 (Continued)
Design intermediate temperature T = 160°F
Design ft2/1000 lb
\,1 = 50'887
A = 55.312
U, £ .
Total: 106. 199
Month
T,
1,0
TX
T
2,1
T,
2,0
TX,2
T3,'i
T3,o
tc (avg)
t. (avg) •
x
ft2/1000 lb lb/1000 lb gpm/1000 lb
Vi" 45
*W 2 = 45
90
1
281
97
64
240
77
59
233
54
67
.496 RL(
.496 R
,992
2
281
102
67
244
83
62
237
56
70
- 7058.4
„ = 7058.4
14,117
3
281
108
74
253
92
69
247
63
77
RG
RG,'2
4
281
121
85
268
110
82
264
74
90
- 14.117
- 14.117
28.234
5
281
129
92
277
121
89
273
80
97
QW,1
c
6
281
136
98
285
130
95
281
86
104
- 176,460
= 176,460
352,920
7
281
140
100
288
136
98
285
88
107
Cooling Tower Characteristic
KaY/L =1.30
Water/Gas Rate
VR;
8
281
139
98
285
134
96
283
85
105
- 1.85
9
281
131
93
279
123
91
276
82
99
in Tower
10
281
123
87
271
113
84
267
76
92
11 12
281 281
111 104
77 68
257 245
96 85
73 63
252 239
67 57
81 71
Total Q
Total air fan energy
(kw-hr/1000 lb)
Tower fan energy
(kw-hr/1000 lb)
Circulation pump energy
(kw-hr/1000 lb)
Compression energy
(kw-hr/1000 lb)
Water consumed
(gal/1000 lb)
115,300 123,700 121,300 126,100 132,100 134,500 139,300 145,300 130,800 126,100 117,600 126,100
61,200 72,000 76,700 96,000 109,200 116,300 127,100 130,800 109,200 98,400 76,700 74,400
176,500 195,700 198,000 222,100 241,300 250,800 266,400 276,100 240,000 224,500 194,300 200,500
1.381 1.381 1.381 1.381 1.381 1.381 1.381 1.381 1.381 1.381 1.381 1.381
0.251 0.251 0.251 0.251 0.251 0.251 0.251 0.251 0.251 0.251 0.251 0.251
0.695 0.695 0.695 0.695 0.695 0.695 0.695 0.695 0.695 0.695 0.695 0.695
536.928 538.944 543.648 551.712 556.416 560.448 562.128 560.784 557.424 553.056 546.000 539.616
9.44 11.73 13.05 17.56 20.81 23.19 25.17 13.45 21.16 18.19 13.08 12.09
(continued)
-------
TABLE 2-22 (Concluded)
Desi
gn intermediate temperature T
«• all wet
. * x
•an. ft2/1000 Ib ft2/1000 Ib lb/1000 Ib gpm/1000 Ib
\>,1 " ° \,1 = 64-223 RL ! - 23,805 RG i - 47.61
A^ , = 0 A,. „ = 66.098 R. _ - 26,434 R_ . - 52.87
Total: 0
Month
T.
1,0
T
T2
T
2,0
T
X,2
T
T
3,0
tc (avg)
t (avg)
Qwl
QW2
Total C.
n t £
Lj,t
130.321
1
281
281
75
255
255
71
249
57
84
713,000
633,000
1346,000
2
281
281
84
267
267
81
263
66
93
687,800
646,700
1334,500
\,,t
50,239
3
281
281
87
271
271
85
268
70
96
671,900
646,700
4
281
281
95
281
281
94
280
79
105
641,900
648,600
1318,600 1291,500
100.48
5
281
281
99
287
287
98
285
83
109
630,700
655,200
1285,900
CW,2 =
1,
6
281
281
105
295
295
104
294
89
114
613,900
660,900
1274,800
595,120
660,860
255,980
7
281
281
107
297
297
106
296
91
116
608,200
660,900
1269,100
Cooling Tower Characteristic
KaY/L =1.30
Water/Gas Rate in Tower
VRA =
a
281
281
105
295
295
104
294
89
114
613,900
660,900
1274,800
= 1.85
9
281
281
101
289
289
100
288
85
110
625,100
655,200
1280,300
10
281
281
96
283
283
95
281
80
106
639,100
652,400
1291,500
11 12
281 281
281 281
91 84
276 267
276 267
89 82
273 264
74 67
100 93
660,600 680,300
649,600 643,900
1310,2001324,200
Total air fan energy
(kw-hr/1000 Ib)
Tower fan energy
(kw-hr/1000 Ib)
Circulation pump energy
(kw-hr/1000 Ib)
Compression energy
(kw-hr/1000 Ib)
Water consumed
(gal/1000 Ib)
000000000000
0.894 0.894 0.894 0.894 0.894 0.894 0.894 0.894 0.894 0.894 0.894 0.894
2.472 2.472 2.472 2.472 2.472 2.472 2.472 2.472 2.472 2.472 2.472 2.472
544.656 551.040 553.392 559.104 561.792 565.824 567.168 565.824 563.136 559.776 556.080 551.376
91.93 94.87 97.80 105.3 113.3 125.5 120.0 119.6 113.4 106.9 100.0 95.16
-------
TABLE 2~23 SUMMARY OF WET/DRY COMPRESSOR INTER-STAGE COOLING
FOR HYDROGEN COMPRESSORS
Farmington, New Mexico
Basis: 1000 lb hydrogen compressed/hr.
Design intermediate temp., F all dry
Dry cooler area, ft /1000 Ib/hr 217.744
2
Wet cooler area, ft /1000 Ib/hr 0
Circulation rate, gpm/1000 Ib/hr 0
Avg. ran t* pump eneigy, , -.__ , , i.bJi
1000 lb
Compression energy, kw-hr/1000 lb 531.738
Water consumed, gal/1000 lb 0
Casper, Wyomj
Basis: 1000 lb hydrogen compressed/hr.
Design intermediate temp., F all dry
Dry cooler area, ft /1000 Ib/hr 208.788
Wet cooler area, ft /1000 Ib/hr 0
Circulation rate, gpm/1000 Ib/hr 0
kw-hr „ _,, ,
Avg. fan & pump enery, IQ'OO lb
Compression energy, kw-hr/1000 lb 539.466
Water consumed, gal/1000 lb 0
Beulah, North
Basis: 1000 lb hydrogen compressed/hr.
Design intermediate temp., F all dry
Dry cooler area, ft2/1000 Ib/hr 239.514
Wet cooler area, ft2/1000 Ib/hr 0
Circulation rate, gpm/1000 Ib/hr 0
kw-hr ., , n ,,
Avy. Ian & pump eaeiyy, 1000" lb J.11J
Compression energy, kw-hr/1000 lb 534.436
Water consumed, gal/1000 lb 0
140
136.030
80.200
17.1616
2.343
538.224
10.3
Lng
160
100.665
90.992
28.234
2.255
541.152
19.8
Dakota
160
106.199
90.992
28.234
2.327
550.592
16.6
160 180
102.511 77.972
90.992 99.890
28.234 34.324
2.279 2.415
553.723 554.258
20.9 27.7
all wet
0
130.321
100.479
3.366
560.852
107
all wet
0
130.321
100.48
3.366
558.264
107
all wet
0
130.321
100.479
3.366
559.169
107
123
-------
2.5 TURBINE CONDENSERS IN STEAM-ELECTRIC POWER PLANTS
2.5.1 Introduction
In a steam-electric power plant utilizing an all evaporative cooling
system, the water consumed for cooling is always a large amount and can
amount to more than 90 percent of the total water consumption. In Farmington,
New Mexico, for example, maximum evaporation occurs in July with an evap-
orative tower loss of 0.46 gal/kw-hr*; the average annual evaporation rate is
0.41 gal/kw-hr or 14,400 gal/cal min (20.7 x 10 gal/cal day) for a 3000 Mwe
plant operating at a load factor of 70 percent. The maximum evaporation loss
from a cooling tower situated in Beulah, North Dakota also occurs in July and
is 0.42 gal/kw-hr with an average annual evaporation rate of 0.39 gal/kw-hr or
13,700 gal/cal min (19.7 x 10& gal/cal day) for a 3000 Mwe plant operating at
a load factor of 70 percent.
In the water short regions of the West dry cooling systems such as
mechanical-draft finned-tube heat exchangers may offer a viable alternative.
In the broadest way dry cooling requires a larger capital investment than wet
cooling and also requires that the unrecovered heat be thrown away at a higher
temperature. Offsetting the increased capital costs and decreased thermal
efficiency is a savings in water consumed and its cost and the cost of treatment.
As we have pointed out previously, the choice of cooling is an economic one.
In the previous study we showed that if the cost of water exceeds about $4.20
to $5.00 per 1000 gallons of evaporated water, then an all dry cooling system
should be selected. If the actual cost of water is less than $4.20 - $5.00/1000
gal, then all wet cooling or a combination of wet/dry cooling should be selected.
We showed that for Navajo/Farmington, New Mexico, a wet/dry cooling system
wquld be more economical than all wet cooling if water costs more than about
$2.50/1000 gal.
In Reference 1 we also made some estimates of the actual cost of water.
We have shown that if the plant is located about twenty miles from the water
f
source, the cost of water is equally dependent upon the cost of transporting
water to the site and the cost of water treatment and disposal. The total
water cost for this case is approximately $0.50 per 1000 gallons. We assumed
that all water rights have been obtained at a negligible cost. Under these
conditions all wet cooling would be desirable. However, at a distance greater
than about fifty miles from the water source the water cost is primarily
dependent on the cost of transporting water. In the West the cost of transporting
water by a pipeline or aqueduct is about 1-2* per thousand gallons per mile.
124
*kw-hr generated
-------
It is unlikely that water would be transported over 100 miles to the plant so
that the actual cost of water would not exceed $2.00 per thousand gallons.
Under this condition a combination wet/dry cooling system would be economically
comparable to an all wet system. The main advantage is that the savings in
total water consumed in the wet/dry system would be about 75% of the total
water consumed for an all wet cooling system under optimum economic conditions.
Moreover, in .water short areas the total consumptive use might well determine
the choice of a cooling system, regardless of the cost of water. Thus, it is
important to analyse in some detail the wet/dry cooling system.
It is clear that large changes in water consumption will occur at relatively
modest costs for water. The previous set of calculations for wet/dry cooling
reported in Reference 1 was limited to one set of calculations and does not
show, for example, the sensitivity to the cost of money nor the sensitivity
to climate. In the present study we have updated the equipment costs and
varied both the amortization rate and fuel charge. Within the Western states
only two climates need be studied: New Mexico on one hand and Wyoming, Montana
or North Dakota on the other hand. We have repeated the calculations for
Navajo/Farmington, New Mexico presented in Reference 1 but with the variations
pointed out above and extended the calculations to a power plant located in
Beulah, North Dakota.
We are interested in comparing the costs of a wet/dry cooling system to
an all wet cooling system so that the differences in costs, rather than the
absolute costs, are of primary concern.
2.5.2 Operation and Costs of Wet/Dry Cooling System
In Section 4 of Reference 1 we described in some detail the performance
and costs associated with all wet, all dry and combination wet/dry cooling
systems. In this section we will briefly summarize the major costs.
The following costs were considered in the study:
Capital cost of cooling system; Includes the capital expenditures for
installation and materials necessary to construct the cooling system.
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,
amortization and other charges incidental to the acquisition and use of the
initial capital expense.
125
-------
Annual cost of operation and maintenance: This is the cost of operating
and maintaining the cooling system and is taken to be one percent of the
capital cost of the cooling system.
Annual credit for excess power generation: The turbine generator is
assumed to operate 6132 hours per year at constant throttle full-load conditions
except when it is throttled back to avoid exceeding the specified back
pressure limit of the unit. At some ambient conditions the turbine may
generate a greater output than the nominal generating output. The annual
credit for excess power generation is the product of the average fuel cost
per kw-hr and the excess energy generated.
Annual cost of replacement energy: Sufficient peaking capacity must be
installed for the ten highest temperature hours of the year. Above a temperature
of 82°F replacement energy is assumed to come from installed gas turbine
units at a fuel cost of 35 mills/kw-hr and below this temperature replacement
energy is provided by excess capability available elsewhere in the utility
system at a fuel cost of 6 mills/kw-hr. The capital cost of replacement
capacity is assumed to be $175/max kw; the annual replacement capacity cost
is based on the capital cost at the annual fixed charge rate.
Annual cost of auxiliary power: This is the cost of the power necessary
to run the cooling system. The incremental cost of sufficient additional
plant capacity to provide the auxiliary power required is assumed to be
$922/max kw with the annual cost based on the annual fixed charge rate and
the capital cost.
Annual fuel cost; The unit fuel cost was varied from $0.50/10 Btu to
$1.50/106 Btu.
cAnnual cost of water; Includes 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. It was assumed that the makeup water was 20 percent more
r
than the evaporation rate to allow for blowdown and drift. The water costs
are expressed in $/1000 gallons of water evaporated.
Total annual cost: This cost is the algebraic sum of all of the annual
costs discussed above.
A summary of the unit price data used in this study is found in Table 2-24.
The unit price data used in Reference 1 is also shown for comparison.
126
-------
TABLE 2-24 SUMMARY OF UNIT PRICE DATA
Ref. 1
Present Study
Annual Fixed Charge Rate (percent)
Unit Fuel Cost ($/106 Btu)
Replacement Capacity Charge Above 82°F
($/maximum kw)
Replacement Capacity Charge Below 82°F
($/maximum kw)
Replacement Energy Cost At and Above 82°F
(mills/kwh)
Replacement Energy Cost Below 82 °F
(mills/kwh)
Auxiliary Power Capital Cost
($/maximum)
Auxiliary Energy Cost
Interest During Construction (percent)
Site Construction Cost Index
Materials
Labor
Construction Period (years)
Scheduled Start-up (year)
15
0.50
175
0
35
6
400
*
8
0.989
0.850
2
1977
15, 18, 21
0.50, 1.00, 1.50
175
35
6
922
*
8
0.976
0.841
2
1978
*Based on average fuel cost plus operation and
maintenance. O&M is 4% of average fuel cost.
127
U.S EPA Headquarters Library
Mail code 3404T
1200 Pennsylvania Avenue NW
Washington, DC 20460
202-566-0556
-------
Figure 2-25 was analyzed 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 water for each tower flows in separate circuits.
The dry tower operates during the whole year with its greatest operating
efficiency in winter while the evaporation tower operates in warmer weather
during periods of peaking. The evaporative tower operates only when the
turbine back pressure exceeds a maximum operating pressure with the dry tower
alone. Calculations for the wet/dry tower were run for four different maximum
operating pressures: 5.0, 4.5, 4.0 and 3.5 inches of Eg. Calculations were
also performed for an all wet cooling system. For the all wet system a design
back pressure was specified; the turbine condenser can operate at pressures
higher than the design back pressure. The design back pressures that were
selected are: 4.5, 4.0 and 3.5 inches of Hg.
The wet/dry and all wet tower calculations were done by R. W. Beck and
Associates, as described in Reference 1. Figures 2-26 and 2-27 show the
optimum evaluated costs as a function of the fraction of water consumed for
all wet cooling for a range of water costs and for a typical set of fixed
charges and fuel costs. For the all wet system the optimum total evaluated
cost was taken to be the lowest cost within the range of design pressures
considered. The optimum cost for the wet/dry system at a given evaporation
rate was taken to be the lowest cost within the range of maximum operating
pressures considered. In all cases if a true minimum was not found within the
range of pressures, the variation in costs with pressure was fairly small
indicating that the true minimum was fairly insensitive to the design or
maximum operating pressure.
We are primarily concerned on the dependence of the changeover water cost
on the fixed charge rate, fuel cost and site. The changeover water cost is
the cost of water above which wet/dry cooling is more economical than all wet
cooling (or below which all wet cooling is more economical than wet/dry cooling)
For example, the changeover water cost at Navajo/Farmington, New Mexico is
$3.83/1000 gal water evaporated (see Figure 2-26) and at Beulah, North Dakota
is $3.60/1000 gal water evaporated (see Figure 2-27). We will not present nor
discuss the breakdown of the operating costs, for example, into the annual
cost of replacement energy or auxiliary power. These are presented in some
detail for a large number of sites in a recently released EPA report by United
Engineers and Constructors, Inc. .
128
-------
HOT WATER
HOT WATER
CONDENSER
*r— -
K
- )
•J
i
r
DRY
COOLING
TOWER
k
1
<
> <
>
<> $
V
<:
»
>
EVAPORATIVE
COOLING
TOWER
COLD WATER COLD WATER
HEAT
EXCHANGER
Fig. 2-25. Wet/dry cooling system.
-------
LO
o
NAVAJO/FARMINGTON, NEW MEXICO
WATER COST $/1000 GAL EVAPORATED
35 —
30
0.2 0.4 0.6
WATER CONSUMED/WATER CONSUMED ALL WET COOLING
0.8
1.0
Figure 2-26. Total annual evaluated cost of wet/dry cooling system
located at Navajo/Farmington, New Mexico.
-------
K 40-
«t
o
BEULAH, NORTH DAKOTA
1000 MWe
FIXED CHARGE RATE 151
FUEL COST $0.50/106 BTU
WATER COST J/1000 GAL EVAPORATED
30
O.Z 0.4 0.6 0.8
WATER CONSUMED/WATER CONSUMED ALL WET COOLING
Figure 2-27. Total annual evaluated cost of wet/dry cooling system
located at Beulah, North Dakota
-------
The changeover water costs are listed in Table 2-25 and shown graphically
in Figure 2-28 for Farmington, New Mexico and Beulah, North Dakota as a
function of both the fixed charge rate and the fuel cost. The changeover
water costs range from $3.65 to $5.47 per 1000 gals water evaporated in North
Dakota and $3.83 to $5.87 per 1000 gals water evaporated in New Mexico for the
fixed charge rates and fuel costs considered. We should point out that in
Reference 1 the changeover water cost for New Mexico was found to be $2.50/1000
gal and should be compared to the lowest value cited above, namely $3.83/1000
gals. The difference can be attributed to the higher auxiliary power and
cooling tower capital costs used in the present study-
For a given fixed charge rate and fuel cost the ratio of the changeover
water cost at New Mexico to that at North Dakota is shown in Figure 2-29. In
every case the ratio does not exceed 7.5 percent. The slightly higher change-
over water costs for New Mexico reflects the longer periods of peaking with
the concomitant larger and more expensive wet cooling tower and the higher
annual costs of replacement energy.
The variation in the changeover water cost with fixed charge rate is
shown in Figure 2-30 for various fuel costs. For a given fuel cost the ratio
of the changeover water cost at a fixed charge rate to the changeover water
cost at a fixed charge rate of 15 percent is shown. The fixed charge ratio is
the ratio of the fixed charge to the fixed charge of 15 percent. For example,
in New Mexico for a fuel cost of $1.50/10 Btu and a fixed charge rate of 21
percent (fixed charge ratio is 21/15 = 1.4), the changeover water cost ratio
is (5.87/4.34) = 1.35. Also shown in Figure 2-30 is a line with a slope of
unity corresponding to the case where the.water cost varies as the fixed
charge rate. The figure shows that the variation in the changeover water cost
is primarily dependent on the fixed charge rate and relatively independent of
the fuel cost.
In a similar manner the variation in the changeover water cost with fuel
cost ratio is shown in Figure 2-G1 for various fixed charge rates. The fuel cost
ratio is the ratio of the fuel cost to the fuel cost of $0.50/10 Btu. Also
shown is a line with a slope of unity corresponding to the case where the
water cost varies as the fuel cost. It is seen, as pointed out above, that
the water cost is relatively insensitive to the fuel cost, i.e. for a three-
fold variation in the fuel cost, the changeover water cost does not vary by
more than 17 percent. The wet/dry cooling system operates at a slightly
greater turbine back pressure (higher condensing temperature) with a slightly
higher fuel cost.
132
-------
TABLE 2-25 CHANGEOVER WATER COSTS FOR NEW MEXICO AND NORTH DAKOTA
Changeover Water Cost
($/10QO gals evaporated)
Fixed Charge
Rate (percent)
15
18
21
Fuel Cost
($/10 Btu)
0.50
1.00
1.50
0.50
.1.00
1.50
0.50
1.00
1.50
Farmington
New Mexico
3.83
4.16
4.34
4.43
4.80
5.18
5.03
5.44
5.87
Beulah
North Dakota
3.65
3.95
4.18
4.22
4.57
4.85
4.82
5.26
5.47
We have found the changeover water cost for each set of fixed charge
rate and fuel cost considered in this study. For each changeover water
cost there are two cooling systems that are of particular interest. One is
the optimized (with respect to cost) all evaporation cooling system and the
other is the wet/dry cooling system which has the lowest annual cost and the
lowest evaporation rate at the changeover water costs shown previously. The
evaporation rates corresponding to both cooling systems are shown in Table 2-26.
The wet/dry evaporation rate expressed as a percentage of the all wet evapora-
tion rate is also shown in the table. For North Dakota the optimized wet/dry
system has an evaporation rate in the range 12 to 15 percent for all of the
cases considered, while for New Mexico the range is 11 to 15 percent at the
lowest fixed charge rate and increases to 18 to 22 percent at the highest
fixed charge rate. Other systematic variations are not evident. This can be
attributed to the fact that the calculational procedure was set up to determine
the tower conditions corresponding to the optimum or minimum annual evaluated
cost. In the vicinity of the optimum cost, the annual costs are fairly
133
-------
6.Or
5.5
i
5.0
§
s
4.5
4.0
3.5
BEULAH. NORTH DAKOTA
FARMINGTON, MEM MEXICO
FIXED "CHARGE
RATE
0.5 1.0
FUEL COST, HO6 BTU
1.5
Figure 2-28. Changeover water costs for Beulah, North Dakota and Navajo/
Farmington, New Mexico.
134
-------
1.10
w
K05
o
S
1.0
0.50
IS
IB
21
FIXED CHARGE RATE
(PERCENT)
1.00
FUEL COST, >/106 BTU
1.W
Figure 2-29. Ratio of changeover water cost at New Mexico to North Dakota.
-------
w
15
FIXED CHARGE RATE, PERCENT
18
1.1
1.2
FIXED CHARGE RATE RATIO
1.3
1.4
Figure 2-30. Ratio of changeover water costs as a function of fixed charge rate ratio.
-------
u>
0.50
l.lb
o
h-
1.10
I.Ob
1.0
FUEL COST, S/10D BTU
1.00
FIXED CHARGE
RATE (PERCENT)
O 15
FARHINGTOH,
IB j NEW MEXICO
o 21
• Ib
* 18
• 21
SLOPE - 1
BEULAH.
NORTH DAKOTA
l.bO
FUEL COST RATIO
Figure 2-31. Ratio of changeover water costs as a function of fuel cost ratio.
-------
TABLE 2-26
EVAPORATION RATE FOR OPTIMIZED WET/DRY AND ALL WET COOLING SYSTEMS
ui
oo
Fixed Charge Fuel Cost
Rate (Percent) ($/10 Btu)
15 0.50
1.00
1.50
18 0.50
1.00
1.50
21 0.50
1.00
1.50
Farmington, New Mexico
Wet /Dry*
693
686
534
847
686
856
847
1012
1028
All Wet
4762
4762
4753
4762
4762
4762
4762
4762
4762
Percent
14.6
14.4
11.2
17.8
14.6
18.0
17.8
21.3
21.6
Beulah, North Dakota
Wet/Dry*
661
650
513
661
650
513
661
651
513
All Wet
4346
4346
4346
4426
4346
4346
4426
4346
4346
Percent
15.2
15.0
11.8
14.9
15.0
11.8
14.9
15.0
11.8
*Evaporation rate in gallons per calendar minute.
-------
insensitive to the tower conditions. However, the wet/dry evaporation rate
is very sensitive to the tower conditions, thus, a slight change in the tower
conditions, although not affecting the optimum cost very much, will lead to a
larger variation in the evaporation rate.
REFERENCES (Section 2)
1. Gold, H. et al, Water Requirements for Steam-Electric Power Generation and
Synthetic Fuel Plants in the Western United States." EPA Report No.
400/7-77-037, U.S. Environmental Protection Agency, Washington, D.C.,
February, 1977.
2. Water Purification Associates, "Water Conservation and Pollution Control
in Coal Conversion Processes", EPA Report 600/7-77-065, U.S. Environmental
Protection Agency, Research Triangle Park, N.C., June 1977.
3. Goldstein, D.J. and Probstein, R.F., "Water Requirements for an Integrated
SNG Plant and Mine Operationg", pp 307-332 in Symposium Proceedings;
Environmental Aspects of Fuel Conversion Technology, II, (December 1975,
Hollywood, Florida), EPA report 600/2-76-149, U.S. E.P.A., Research
Triangle Park, North Carolina 27711, June 1976.
4. Gold, H. and Goldstein, D.J., "Water Related Environmental Effects in
Fuel Conversion," EPA Report 600/7-78-197a,b, U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina, October 1978.
5. Hu, M.C. and Englesson, G.A., "Wet/Dry Cooling System for Fossil-Fueled
Power Plants: Water Conservation and Plume Abatement," Report No. EPA-600/
7-77-137, Environmental Protection Agency, Research Triangle Park, N.C.,
6. Kelly's Handbook of Crossflow Cooling Tower Performance, Neil W. Kelly
and Associates, Kansas City, Missouri.
7. Neerken, R.F., "Compressor Selection for the Chemical Process Industries",
Chemical Engineering, 7894, January 20, 1975.
139
-------
3. REGIONAL WAlfiH REQUIREMENTS AND RESIDUALS DISPOSAL
3.1 INTRODUCTION
In Reference 1, calculations' of the water requirements and wet-solid
residuals were presented for three standard size coal conversion plants
(Lurgi, Synthane and Synthoil) each located at four Western sites and for two
oil shale plants located at one Western site. In order to extend the data
base to include more plant-site combinations and provide more meaningful
regional water impact assessments, results from a program recently completed
by Water Purification Associates for the U.S. Environmental Protection Agency
(Contract No. 68-03-2207) and the Department of Energy (Contract No. EX-76-C-
01-2445) will be summarized in this section. Details of the complete study
are given in Reference 2.
3.2 PROCESS AND SITE SELECTION
A total of 42 plant-site combinations were studied in the Western states.
Table 3-1 lists the plant-site combinations while Figure 3-1 shows the locations
of these sites with respect to the major energy reserves and the primary water
resources characteristics. The map shows more sites than the ones given in
Table 3-1. Primary sites correspond to the sites listed in the table and
secondary sites were selected to provide a larger study area with respect to
water availability. These plants were sited in the same regions as in the
Technology Assessment of Western Energy Resource Development Study . Plant
design considerations included the following broad categories of water related
process criteria: (i) low temperature gasifiers, (ii) high temperature gasifiers,
(iii) coal refining and liquefaction processes, and (iv) surface retorting of
oil shale. Site considerations include: water supply and alternative demands,
climate and rank of coal and mine type. The water requirements and water uses
within the plant, the waters to be treated within the plant and the waste
effluents are dependent on the site of the coal and oil shale conversion
complex, as well as on the process itself. The water control technology and
disposal of the waste solid residues are dependent on the quality of the
supply water, which is also site dependent. The large number of site and
process combinations were studied in order to derive generalized rules as to
the feasibility of siting and its subsequent environmental impact resulting
from the consumptive use of water at that site.
140
-------
TABLE 3-1 COAL AND OIL SHALE CONVERSION PLANT-SITE COMBINATIONS FOR WESTERN STATES,
State
Montana
New
Mexico
North
Dakota
Wyoming
Mine
Decker-Diet!
Foster Creek
U.S. Steel Chupp Mine
East Moorhead
Pumpkin Creek
Otter Creek
Col 3 trip
Coalridge
Gallup
El Paso
Wesco
Scran ton
Bentley
Underwood
Knife River
Center
Slope
Dickinson
will is ton
Belle Ayr
Gillette-Wyodak
Spotted Horse Strip
Hanna
Antelope Creek Mine
Lake-de-Snet
Xemnerer
Jin Bridger
Rainbow 18
Water Source
Surface Ground
X
Tongue R.
Yellowstone R.
Powder R.
Tongue R.
X
Yellowstone R.
Missouri River
X
San Juan R.
San Juan R.
Grand R.
Knife R.
L. Sakakawea
Knife R.
Knife R.
Yellowstone R.
L. Sakakawea
Missouri R.
Crazy Woman Cr.
Crazy Woman Cr.
Powder R.
Medicine Bow
Beaver Cr. x
Tongue R.
Hani Fork
Green R.
Green R.
a °
Mining Coal
S S
S S
S L
S L
S L
S L
S S
S L
S S
S S
S S
S L
S L
S L
S L
S L
S L
S L
S L
S S
S S
S S
S S
S S
S S
S B
S S
U B
Coal Gasification
High Temp.Gasifier Low Tenp.Gasifier
Hygas Bigas Lurgi Syn thane
X X
X
X
X
X X
X X
X X
X
X
X
X
X
X
X
X
X
X
X X
X X
Coal Liquefaction
and Coal Refining
Synthoil SRC
X
X
X
X
X
X
X
X
X
X
X
X
X
Plant-Site Combination*
Ho. Total State
2
1
1
1
1
1
3
1 11
3
2
1 6
1
1
1
i
i
i
i
1 - B
1
2
1
1
3
1
2
2
1 14
TOTAL
39
State
Colorado
Mine
Parachute Creek
Water Source
Surface Ground
Colorado R.
a c
Mining Shale
U HG
Direct Retort
Paraho Direct
X
Indirect Retort
Paraho Indirect TOSCO II
X X
Plant-Sit* Conbinatloni
Ho. Total State
3 3
• D » Underground] S - Surface
b B - Bituminous) L - Lignitei S - Subbituminotu
c HG » High grade shale
TOTAL
-------
NORTH DAKOTA,
HANNAH COAL FIELD
RAJNBOW\8 BJIMBRIDGERl
\m I
• TRACT W-G/W\ WYOMING
UPPER
MISSOURI
CREEK RIVER BASIN
TRACT U-a/U-b V _„_
TRACT C-a/C-bf
DEVELOPMENT
UPPER COLORADO^
RIVER BASIN
SITE LOCATIONS
B PRIMARY SITES
• SECONCARYSITES
Figure 3-1. Coal and oil shale conversion site locations in Western states.
142
-------
The synthetic fuel technologies examined include: coal gasification to
convert coal to pipeline gas; coal liquefaction to convert coal to low sulfur
fuel oil; coal refining to produce a de-ashed, low sulfur solvent refined (clean)
coal; and oil shale retorting to produce synthetic crude. Detailed conceptual
designs for integrated mine-plant complexes were made for each of the representa-
tive conversion processes in order to compare water requirements, types of
water treatment plants, and the quantities of wet-solid residuals generated.
The products and processes chosen for comparison are shown in Table 3-2.
The process criteria for the conversion of coal were defined based on the
quality of the foul condensate recovered after gasification or liquefaction.
Low temperature gasifiers (e.g. Lurgi and Synthane) using lower rank subbitumin-
ous coals produce a very dirty condensate (typical values: BOD ^ 10,000 mg/1,
phenol ^ 3,000 mg/1 and ammonia ^ 7,000 mg/1). The high temperature gasifiers
(e.g. Koppers - Totzek and Bigas) produce a relatively clean process condensate
(typical values: ammonia ^ 4,500 mg/1, BOD and phenol ^ small), while the
intermediate temperature Hygas gasifier using a higher rank bituminous coal
produces a condensate of intermediate quality. Both the Synthoil and Solvent
Refined Coal (SRC) processes have the foulest condensate (typical values for
SRC: BOD ^ 30,000 mg/1, phenol ^ 5,000 mg/1 and ammonia ^ 8,000 mg/1).
For oil shale conversion, we only considered underground mining followed by
surface retorting. In situ retorting processes are under development and cannot
yet be considered suitable for commercial operation. Oil shale retorts are
classified into two basic types, those that are direct heated, such as the
Paraho Direct process, and those that are indirect heated, such as the TOSCO II
and Paraho Indirect processes. From the point of view of water management, the
type of retort is quite important. When the retort is direct heated, most of
the water is recovered, while with indirect heated retorts, the water in the
combustion products is generally lost up a furnace stack and not recovered.
Furthermore, for direct heated processes, no intermediate medium is used to
transfer heat from the pyrolysis and the thermal efficiency is high, resulting
in reduced cooling loads, as compared to the indirect heated retorts. Finally,
large amounts of water are required for the disposal and revegetation of the
spent shale piles and different procedures with considerably different water
requirements have been proposed for the Paraho and TOSCO spent shales.
143
-------
TABLE 3-2 PRODUCT FUEL OUTPUT OF STANDARD SIZE SYNTHETIC FUEL PLANTS
Product
Technology and Heating Value
Conversion Process Product Output (10 Btu/day)
Coal Gasification Pipeline Gas 250x10 scf/day 2.4
Lurgi*
Synthane*
Hygas
Bigas
Coal Liquefaction Fuel Oil 50,000 barrels/day 3.1
Synthoil*
Coal Refining Solvent Refined 10,000 tons/day 3.2
SRC C°al
Oil Shale Synthetic Crude 50,000 barrels/day 2.9 (2.8)
Paraho Direct
Paraho Indirect
TOSCO II*
*Processes studied in Reference 1 for the Technology Assessment of
Western Energy Resource Development study.
Value used in Reference 1.
144
-------
Site selection was based on the availability of coal and oil shale, the
type of coal (bituminous, subbituminous or lignite) or oil shale (high grade
or low grade), the type of mining (underground or surface) and the availability
of surface and ground water.
In the West, lignite is found in North Dakota and eastern Montana, while
subbituminous coal is found in southeastern Montana, Wyoming, and New Mexico.
Some bituminous coal is found in southern Wyoming. Sites were selected based
on the coal reserves required for a standard size conversion plant operating
at 90 percent production capacity over a thirty-year period. For a Synthane
plant a total recoverable reserve of approximately 200 x 10 tons of lignite
are required. The recoverable reserve is the amount of coal actually mined or
recovered as distinguished from the amount of coal present in the ground, or
coal reserve. The total recoverable coal reserve is about 50 percent of the
total coal reserve for underground mining and about 80 percent for surface
mining. The sites were chosen in those coal regions where the largest and
most easily mined deposits are located. These are the Powder River and Fort
Union coal regions in Montana, Wyoming and North Dakota, and the Four Corners
coal region in New Mexico. A total of 28 coal conversion sites were selected;
9 in Wyoming, 8 each in Montana and North Dakota, and 3 in New Mexico.
Depending on the shale grade and the particular process, approximately
75,000 to 100,000 tons of high grade shale must be mined daily from an under-
ground shale mine integrated with a shale oil plant to produce 60,000 to
75,000 barrels/day of shale oil. This is the range of shale oil needed to
produce 50,000 barrels/day of synthetic crude in a self-sufficient integrated
plant. For one plant a total recoverable reserve of from 600 x 10 to 730 x
10 barrels of shale oil are needed, assuming a 90 percent load factor and a
3*0 year mine life. If 30 percent of the shale remains underground with conven-
tional room-and-piliar mining techniques, then a total reserve in the range of
860 x 10 and 1,040 x 10 barrels of shale oil is required for a plant producing
50,000 barrels/day of synthetic crude. The only oil shale considered was high
grade shale from the Green River Formation in Colorado and Utah.
3.3 WATER SUPPLY AND DEMAND
Potential water supply sources for each site were evaluated on a site
specific base in terms of total available water supply, required plant use,
needs and rights of other competing water users, and the quality of the alternative
145
-------
water supplies. Factors considered were the extent and variability of nearby
stream flows or groundwater aquifers, legal institutions regulating the use of
these waters and the implications of competing users for limited supplies in
certain areas. The water sources listed in Table 3-1 are assumed to be the
nearest reliable water sources of sufficient size for which there was water
quality data available.
The water resources in the major coal and oil shale bearing regions of
the Western United States were conveniently separated into two major water
shed regions: the Upper Missouri River Basin and the Upper Colorado River
Basin. Each one of the Basins was further divided into several hydrologic
subregions and estimates made of water availability within each subregion for
coal and oil shale production.
In the Powder River and Ft. Union coal regions shortages occur in parts
of the Yellowstone River Basin during periods of low flow. Water can be
obtained by appropriation and transferred by transbasin diversions. However,
there are a number of serious institutional conflicts in the region, particularly
in Montana and Wyoming, concerning the authority to allocate water. Competitive
pressures from agricultural water users are very high and irrigation needs
are large because of the semi-arid climate. Environmental problems associated
with the disruption of natural underground reservoirs by mining may also be
important.
The coal and oil shale regions of the Upper Colorado River Basin are
situated in an arid area marked by an inadequate water supply of poor quality-
The region is subjected to highly variable annual stream flows. It may be
possible to utilize groundwater as a conjunctive supply, but this water is
generally of a poor quality and often drawn from underground reservoirs which
would eventually be depleted. However, we should note that for some proposed
oil shale developments, the quantity of groundwater produced by mine dewatering
would exceed the plant water requirements. Strong competition- exists among
agricultural, municipal and industrial users for the available supply, most
of which is now either appropriated or over-appropriated. Serious institutional
conflicts involving Indian water rights also exist in the area.
Because agriculture has long been an important part of the Western
economy, numerous storage reservoirs have been built throughout both Basins
to more evenly distribute spring runoff during the year, particularly the
growing season.
146
-------
Two limiting cases were examined with respect to water availability in
the West: low water demand and high water demand. Low water demand corresponds
to a synthetic fuel production rate of approximately 1.0 x 10 barrels/day of
12
synthetic crude, or its equivalent of 5.8 x 10 Btu/day, while high water
demand corresponds to a synthetic fuel production rate of 4.0 x 10 barrels/day
of synthetic crude, or its equivalent in other fuels of 23.2 x 10 Btu/day.
For low water demand, two standard size coal or oil shale conversion plants
(without regard to type) were assumed to be located in each of eleven hydrologic
subregions for a total of 22 plants. This corresponds to the production of
approximately 1.0 x 10 barrels/day of synthetic crude. For high water
demand, 1 x 10 barrels/day of synthetic crude, or its equivalent in other
fuels, were produced in each of the three principal coal bearing regions (Ft.
Union, Powder River and Four Corners) and in the principal oil shale region
(Green River Formation), for a total production of 4 x 10 barrels/day.
Low water demand can be accommodated by available supplies in most of
the subregions. However, chronic water shortages do exist, especially in the
northern Wyoming area of the Powder River coal region and the Tongue-Rosebud
drainage area in the Ft. Union coal region. In the Four Corners-San Juan
region in northwestern New Mexico and the Belle-Fourche-Cheyenne basin in
northeast Wyoming, the water demands are greater than about twenty percent of
the total water availability, which may be considered to be excessive. For
high water demand, projected loads cannot be accommodated by available supplies
in most subregions. Only in the Yellowstone, Upper Missouri, Lower Green and
Upper Colorado mainstem basins does it appear that sufficient supplies are
available for the expected loads of energy production. However, water avail-
ability in the Upper Colorado River Basin may be limited because all of the
water rights to most of the free flowing water in the Basin are already
allocated. These rights would have to be transferred to support additional
energy development or water transferred by transbasin diversion.
i
The cost of water and its availability determines the degree to which
wet cooling should be used. At a site where water is plentiful and inexpensive
to transport, high wet cooling should be used. In regions where water is
marginally available or moderately expensive to transport, an intermediate
degree of wet cooling should be used, and where water is expensive to transport
or scarce, minimum practical wet cooling should be used.
147
-------
The results presented in Section 2 suggest that the three cooling options
could be denoted by the different degrees of wet cooling used for turbine
condensers and gas-compressor interstage coolers. High wet cooling would
correspond to the case where the cooling loads on both the turbine condensers
and interstage coolers are all wet cooled. Estimates for the Synthane process
show that wet cooling is used to dispose of from 30 to 33 percent of the total
unrecovered heat for high wet cooling. High wet cooling would be used when
water costs less than $0.25/1000 gals.
Intermediate wet cooling assumes that wet cooling handles 10 percent of
the cooling load on the turbine condensers and all of the load of the interstage
coolers. Approximately 15 to 18 percent of the unrecovered heat is dissipated
by wet cooling in the Synthane process. Intermediate wet cooling would be used
when water costs in the range $0.25/1000 gals and $1.50/1000 gals.
Minimum practical wet cooling assumes that wet cooling handles 10 percent
of the cooling load on the turbine condensers and 50 percent of the load on the
interstage coolers. Approximately 12 to 16 percent of the total unrecovered
heat is dissipated by wet cooling in the Synthane process under these conditions.
Minimum cooling is used when the cost of water exceeds $1.50/1000 gals.
Estimates have been made of the cost of transporting water to the point of
use. Figure 3-2 shows the cost of transporting water to all sites for low water
demand. We assumed that a single pipeline supplies water to a single plant.
Except for plants located near the mainstern of major rivers or near large reservoirs,
Figure 3-2 shows that intermediate or minimum practical wet cooling is desirable
for most of the sites in the West.
For large scale synthetic fuel production, it is more economical to have a
large pipeline built to transport water to a large number of plants than
to have a large number of individual pipelines supplying individual plants.
Figure 3-3 shows for high water demand the cost of transporting large quantities
of water to some of the major coal producing areas and indicates that except for
large scale development near the mainstem of major rivers, intermediate cooling
is desirable for most of the study region.
148
-------
I t—
NORTH DAKOTV
UPPER
MISSOURI
RIVER BASIN
l"*
\ WYOMING
COLORADO
Cost Of Water
(S/ICXD GALS)
<0-25
- 1-50
UPPER COLORADO
RIVER BASIN
9TE LOCATIONS
H primary sftes
• secortdary sttes
Figure 3-2. .Cost of transporting water to specific site
locations in the Western states.
149
-------
UPPER
MISSOURI
RIVER BASIN
Cost Of Ytater
(S/IOOO GALS)
<0-25
UPPER COLORADO
RIVER BASIN
primary sites
• secondary sites
pipeline
Figure 3-3. Cost of transporting water to coal regions
in the Western states.
150
-------
3.4 TOTAL WATER CONSUMED AND RESIDUALS GENERATED
Water consumption is based on net water consumption. All effluent
streams are assumed to be recycled or reused within the mine or plant after
any necessary treatment. These streams include the organically contaminated
process condensate waters and the highly saline water blown down from the
cooling system. Water is released to evaporation ponds as a method of salt
disposal. However, we have generally assumed that the highly saline waters
can be disposed of with the coal ash. We have not considered the recovery of
water from the drying of high moisture content coal such as lignite, because
the costs are high, in the range of $1.30 to $1.50 per 1000 gallons . However,
recovery is a serious possibility when water is particularly scarce, especially
in the West. The rest of the water leaves the plant as vapor, as hydrogen
in the hydrocarbon products, or as occluded water in the solid residues.
Dirty water is cleaned but only for reuse and not for returning it to a
receiving water. No waters are returned to the receiving waters. The totals
for wet-solid residuals include the solid residue as well as the occluded
water in the solid residue.
We have found it convenient to present the results by coal and oil shale
region and by coal rank within each region, in contrast to a breakdown by state,
as was done in Table 3-1. Table 3-3 shows the sites located within each major
coal and oil shale bearing region, together with the coal rank and shale grade.
Mining Rates
The daily coal and oil shale mining rates for standard size synthetic fuel
plants operating at a capacity of 90 percent are shown in Table 3-4. For a
limited number of process-region-coal rank combinations not covered in Reference 2,
the results of Reference 4 have been used. The results of Reference 2 are compared
to those of Reference 1 (Technology Assessment). Most of the differences can be
attributed to some minor differences in the way the calculations were carried out.
For the Synthoil plant at Four Corners, the large difference is due mainly to the
different coals used. The daily mining rates per unit of heating value in the
product fuel are shown in Table 3-5.
Total Net Water Consumed
Tables 3-6 and 3-7 summarize the total net water consumed for the three differ-
ent cooling options described in Section 3.3. The range in the total water consumed
reflects the variation with site. The results of Reference 1 (Technology Assessment)
and Section 1 of this report are compared to those of Reference 2.
151
-------
TABLE 3-3 STUDY SITES COMPRISING COAL AND OIL SHALE BEARING REGIONS
Coal Region
Four Corners
Powder River and Fort
Union Basins
Coal Conversion
Coal Rank
Subbituminous
Lignite
Subbituminous-
Bituminous
Site
New Mexico (all sites)
U.S. Steel Chupp Mine, Montana
Coalridge, Montana
East Moorhead, Montana
Otter Creek, Montana
Pumpkin Creek, Montana
North Dakota (all sites)
Colstrip, Montana
Decker, Montana
Foster Creek, Montana
Wyoming (all sites)
Oil Shale Conversion
Oil Shale Region
Green River Formation
Shale
High Grade
Site
Parachute Creek, Colorado
152
-------
TABLE 3-4 SUMMARY OF COAL AND OIL SHALE MINING RATES
IN 1000 TONS PER CALENDAR DAY FOR STANDARD SIZE SYNTHETIC FUEL PLANTS
OPERATING AT 90 PERCENT CAPACITY
Powder R/Ft. Union Basin
S ubb i tuminous
-Bituminous Lignite
Four Corners
Subbituminous
Green River
Formation
Oil Shale
Coal Gasification
Lurgi
Synthane
Hygas
Bigas
15.0-23.6 (24.7-25.1)
19.9-21.3 (22.2-22.6)
13.9-19.3
11.8
26.7-31.6 (31.1)
27.5* (28.0)
22.0
23.7-28.9
17.5-23.4 (25.6)
23.3* (23.0)
13.1-17.4
ui
Coal Liquefaction
Svnthoil
22.2-23.1 (21.9)
28.4* (27.6)
17.0 (22.7)
Coal Refining
SRC
17.9-26.0
25.4-38.5
25.5*
Oil Shale
Paraho Direct
Paraho Indirect
TOSCO II
83
95
66 (60)
*From data in Ref. 4
+Numbers in parentheses are from Ref. 1 (Technology Assessment of Western Energy Resource Development study)
-------
TABLE 3-5 SUMMARY OF COAL AND OIL SHALE MINING RATES
NORMALIZED WITH RESPECT TO THE HEATING VALUE IN THE PRODUCT FUEL IN 100 LBS/10 BTU
Powder R/Ft. Union Basin
Subbituminous
-Bituminous
Lignite
Four Corners
Subbituminous
Green River
Formation
Oil Shale
Coal Gasification
Lurgi
Synthane
Hygas
Bigas
1.4-2.2 (2.3)
1.8-2.0 (2.1)
1.3-1.8
1.1
2.5-2.9 (2.9)"
2.5* (2.6)
2.0
2.2-2.7
1.6-2.2 (2.4)
2.2* (2.1)
1.2-1.6
Coal Liquefaction
Synthoil
1.6-1.7 (1.6)
2.0* (2.0)
1.2 (1.6)
Coal Refining
SRC
1.2-1.8
1.8-2.7
1.8*
Oil Shale
Paraho Direct
Paraho Indirect
TOSCO II
6.3
7.2
5.0 (4.7)
*From data in Ref. 4
+Numbers in parentheses are from Ref. 1 (Technology Assessment of Western Energy Resource Development Study)
-------
TABLE 3-6. SUMMARY OF NET WATER CONSUMED IN 106 GPD FOR STANDARD SIZE SYNTHETIC FUEL PLANTS
OPERATING AT 90 PERCENT CAPACITY
!-•
l/l
Ul
Coal Gasification
Lurgi
Synthane
Hygai
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SRC
Oil Shale
Paraho Direct
Paraho Ind.
TOSCO II
Powder River/Ft. Union Regions
Subbituininous-Bituninous
123
5.0-6.2(5.3-5.6)* 3.3-4.6(3.8-4.1) 3.0-4.3(3.3-3.7)
5.4-5.8(6.9-7.0) 3.7-4.0(5.2-5.3) 3.3-3.7(4.9-5.0)
4.4-4.9 3.3-3.8 3.2-3.6
5.3 3.3 3.1
4.7-4.8(4.1-4.6) 3.0-3.1(3.4-3.8) 2.7-2.8(3.1-3.5)
3.9-4.4 2.3-2.7 2.1-2.3
Lion it*
123
4.8-5.1(4.4) 3.0-e>.2(3.0) 2.6-2.9(2.5)
5.1* (6.8) 3.2* (5.2) 2.8 (4.9)
4.S 3.4 • 3.2
5.7-5.9 3.8-3.9 3.5-3. 6
5.5* (4.5) 3.9* (3.6) 3.6* (3.4)
4.4-5.9 2.6-3.3 2.3-2.8
Four Corners
Subbi tuminous
123
6.3-6.5 (6.4) 4.6-4.8 (5.0) 4.2-4.4 (4.7)
5.9* (7.7) 3.7* (6.0) 3.4' (5.6)
4.9-5.0 3.8-3.9 3.6-3.7
5.4-6.0* (5.1) 3.9-4.6* (4.3) 3.6-4.3* (4.1)
4.3* 3.1* 3.0*
-
Green River
Formation
oil Shali>
2
-
4.6 (4.6)
7.4 (7.4)
7.5 (7.5)**
1 - High Net Cooling, 2 - Intermediate Net Cooling,' 3 - Minimum Practical Met Cooling
*Data from R«f. 4, only applies to particular number and not range.
4-Nunbers in parentheses are from Ref. 1 (Technology Assessment of Western Energy Resource Development Study)
"Modified from calculations presented in Ref. 1.
-------
TABLE 3-7. SUMMARY OF NET WATER CONSUMED NORMALIZED WITH RESPECT TO THE HEATING VALUE
IN THE PRODUCT FUEL IN GAL/106 BTU
Coal Gasification
Lurgi
Synthane
Hygas
Bigas
Coal Liquefaction
Synthoil
Coal Refining
SMC
Oil Shale
Paraho Direct
Paraho Ind.
TOSCO II
Powder River/Ft. Union Regions
Subbituminous-Bituninous
123
23-29 (24-26)* 15-21 (17-19) 14-20 (15-17)
25-27 (32) 17-19 (24) 16-17 (23)
21-23 16-18 15-17
24 16 14
17 (15-17) 11 (12-14) 10 (11-13)
13-15 8-9 7-8
Lignite
123
22-24 (20) 14-15 (14) 12-13 (12)
24* (32) 15* (24) 13* (23)
21 16 15
26-27 18 16-17
19* (16) 14*(13) 13* (12)
15-21 8-9 7-8
Four Comers
Subbituntinous
123
29-30 (29) 21-22 (23) 2O-21 (22)
28* (36) 18* (28) 16* (26)
23 18 17
20-22* (18) 14-16* (IS) 13-16* (14)
15* ' 11* 10*
-
Green River
Formation
Oil Shale
2
.
-
18 (18)
28 (28)
29 (29)"
01
1 • High Net Cooling, 2 - Intermediate Wet Cooling, 3 - Minimum practical Net Cooling
•Data from Kef. 4, only applies to particular number and not range.
+Hunbers in parentheses are from Xef. 1 (Technology Assessment of Western Energy Resource Development study.
••Modified fron calculations presented in Kef. 1.
-------
Except for the Synthane process the results of the limited six site-
specific studies are in general agreement with the results of the expanded
site studies. As was mentioned previously, small differences are attributed
to differences in the way the calculations were carried out. For Synthane,
the major difference is in the degree to which wet cooling was used to dissipate
9
the unrecovered heat. In Ref. 1 (p. 53) approximately 2.7 x 10 Btu/stream hr
was dissipated by wet cooling. However, in Ref. 2, a more detailed thermal
9
balance was made and only about 1.85 x 10 Btu/stream hr was dissipated by wet
cooling at some of the Western sites. This difference results in a difference
in the net water consumed of 1.5 x 10 gal/cal. day, or about 7 gals/10 Btu.
These differences are shown in Tables 3-6 and 3-7.
Figures 3-4 and 3-5, taken from Ref. 2, show a breakdown of the average
net water consumption by region and by process and for the three cooling options.
Four water use categories are presented for each coal conversion process in each
region: net process water based on reuse of all condensate; cooling water, flue
gas desulfurization water, if necessary; and water for mining, dust control,
solids disposal, water treatment, revegetation and other uses. For oil shale it
is most convenient to break down the water use categories in a slightly different
way to reflect the large quantities of water required for spent shale disposal:
net process water for retorting and upgrading; cooling water; water for spent
shale disposal and revegetation; and water for dust control, mining and other
uses. For the cases where the net process water is negative (i.e., net water-
produced in the process), the cooling water requirements can be obtained by
adding the absolute value of the process water to the cooling water component.
Except for the Hygas process, the net water consumed for the Four Corners
region is higher than for the other regions because of the larger amount of
water needed for dust control and the handling of ash for the high ash Navajo,
New Mexico coal. Water is required for revegetation in New Mexico because the
rainfall is less than 10 inches per year, but is not required at any other
location. For the Hygas process there are many other competing demands which
make the above generalization invalid.
It should be noted that within a given coal region and for a given process,
rank of coal, and wet cooling option, differences in the net water consumed from
site to site are not significant. However, within a given region there might be
large, variations in water availability and water costs and different cooling
options at different sites will produce large differences in the cooling water
157
-------
30
20
•6
So
POWDER RIVER AND FORT UNION REGIONS
SUBBITUMIIIOUS COALS
POWDER RIVER AND FORT UNION REGIONS
LIGNITE COALS
®
FOUR CORNERS
-10
en
03
2000
1000
DUST CONTROL AND OTHER
FLUE GAS DESULFURIZATION
COOLING
NET PROCESS
1 - HIGH WET COOLING
2 - INTERWDIATE WET COOLING
3 - MINIMUM PRACTICAL WET COOLING
1
i
BIGAS SYNTH01L
SRC
LURGI
HVGAS
BIGAS
SRC
LURGI
HYGAS SYMTHOIL
LURGI SYNTHAHE HYGAS
Figure 3-4. Summary of average net water consumed for coal conversion plants located in the Western states.
-------
Ui
VD
3000
2000
1000
GREEN RIVER FORMATION
OIL SHALE
1 - HIGH WET COOLING
2 - INTERICOIATE WET COOLING
- 3 - MINIMUM PRACTICAL WET COOLING
-
I
m
I
\\f\\
1
T1
I
•a:
X;
„_
-
-
PARAHO PARAHO TOSCO
DIRECT INDIRECT II
30
20
10
GREEN RIVER FORMATION
OIL SHALE
E3 DUST CONTROL AHD OTHER
EU SPENT SHALE DISPOSAL
CD COOLING
0 RETORTING AIIU UPGRADING
PARAHO PARAHO TOSCO
DIRECT INDIRECT II
Figure 3-5 Summary of net water consumed for oil shale conversion plants
located in the Western states
-------
consumed and the plant water requirements. Thus, for a particular process
and coal rank, the cost of water and the particular cooling technology
selected for a given plant are the main factors which determine the water
use. As we pointed out in Section 3.2, intermediate and minimum practical
wet cooling should be used at most of the sites.
Total Wet-Solid Residuals Generated
Solid residuals generated in coal and oil shale conversion plants are
generally disposed of wet with occluded water. Tables 3-8 and 3-9 summarize
the total wet solid residuals by coal region and rank and oil shale region
and grade. Figures 3-6 and 3-7, taken from Ref. 2, show a breakdown of the
average wet solid residuals by region and by process. Three categories are
presented for each conversion process: ash sludge, flue gas desulfurization
sludge and water treatment sludge. Flue gas scrubbing is not required for
the Synthoil and SRC processes. Only the category of wet spent shale is
shown for oil shale conversion.
The results of Ref. 1 (Technology Assessment) are compared to those of
Ref. 2 in Tables 3-8 and 3-9. The total wet solid residuals generated for
the expanded site study are about twice those of the Technology Assessment
study for coal conversion due primarily to the much larger quantities of flue
gas desulfurization sludge and water treatment sludge generated.
In general coal gasification generates the largest quantity of wet
residuals normalized with respect to the product heating value, followed in
turn by coal liquefaction and coal refining. For the same process, there are
no significant variations with coal rank in the Powder River and Fort Unibn
coal regions except for the Bigas process; for Bigas the variation is due to
the higher ash coals. The larger quantities of wet solids generated in the
Four Corners region are due to the high ash content of the Navajo coal.
REFERENCES (Section 3)
1. Gold, H., et al, "Water Requirements for Steam-Electric Power Generation
and Synthetic Fuel Plants in the Western United States," EPA Report No.
600/7-777-037, U.S. Environmental Protection Agency, Washington, D.C.,
April 1977.
2. Gold, H. and Goldstein, D.J., "Water Related Environmental Effects in Fuel
Conversion," EPA Report 600/7-78-197a, b, U.S. Environmental Protection
Agency, Research Triangle Park, N.C., October, 1978.
3. Goldstein, D.J- and Yung, D., "Water Conservation and Pollution Control in Coal
Conversion," EPA Report 600/7-77, EPA, Research Triangle Park, June, 1977.
4. Probstein, R.F. and Gold, H. , Water in Synthetic Fuel Production - The
Technology and Alternatives, MIT Press, Cambridge, Mass., 1978.
160
-------
en
ca
100
80
60l_
40
ZO
POWDER RIVER AND FORT UNION REGIONS
SUBBITUMINOUS COALS
POWDER RIVER AND FORT UNION REGIONS
LIGNITE COALS
w//
FOUR CORNERS
800
3 600
§
o
400
200
II FLUE GAS OESULFURIZATION SLUDGE
E22 ASH SLUDGE
TREATICHT SLUDGE
LURGI SYNTHANE HYGAS BIGAS SYNTHOIL SRC
LURGI
HYGAS
BIGAS
SRC
LURGI
HYGAS SYNTHOIL
Figure 3-6 Summary of average wet-solid residuals generated from
standard size coal conversion plants located in the Western states
-------
GREEN RIVER FORMATION
bOOO
6000
8
- 4000
2000
f^j SPENT OIL SHALE
—
i
1
-
1UO
80 *.
S
-^
-------
TABLE 3-8 SUMMARY OF TOTAL WET RESIDUALS GENERATED
IN 10 TONS/DAY FOR STANDARD SIZE SYNTHETIC FUEL PLANTS OPERATING AT 90 PERCENT CAPACITY
Powder R/Ft. Union Basin
Subbituminous
-Bituminous
Lignite
Four Corners
Subbituminous
Green River
Formation
Oil Shale
Coal Gasification
Lurgi
Synthane
Hygas
Bigas
6.8-7.7 (2.0-3.5)
5.0-6.0 (1.9-3.1)
3.4-5.0
3.2
6.6-9.0 (3.3)
3.5* (3.0)
3.8
3.7-7.5
6.4-13.6 (8.2)
6.3* (7.8)
4.2-6.9
Ul
Coal Liquefaction
Synthoil
3.0-3.6 (1.7-2.8)
4.8* (2.8)
2.9-10.1* (7.3)
Coal Refining
SRC
1.8-3.4
2.9-4.2
12.3*
Oil Shale
Paraho Direct
Paraho Indirect
TOSCO II
68
94
61 (56)
*From data in Ref. 4
+Numbers in parentheses are from Ref. 1 (Technology Assessment of Western Energy Resource Development Study)
-------
TABLE 3-9 SUMMARY OF TOTAL WET RESIDUALS GENERATED
NORMALIZED WITH RESPECT TO THE HEATING VALUE IN THE PRODUCT FUEL IN LBS/10 BTU
Powder R/Ft. Union Basin
Subbituminous
-Bituminous
Lignite
Four Corners
Subbituminous
Green River
Formation
Oil Shale
Coal Gasification
Lurgi
Synthane
Hygas
Bigas
61-68 (18-32)
46-56 (18-28)
32-46
30
61-83 (31)
33* (27)
35
34-69
59-126 (76)
59* (72)
39-64
Coal Liquefaction
Synthoil
21-26 (12-20)
34* (20)
28-72* (52)
Coal Refining
SRC
12-24
20-34
19-86*
Oil Shale
Paraho Direct
Paraho Indirect
TOSCO II
520
630
470 (440;
*From data in Ref. 4
+Numbers in parentheses are from Ref. 1 (Technology Assessment of Western Energy Resource Development Study)
-------
4. ECONOMICS OF WATER TREATMENT AND COOLING TOWER SLOWDOWN
TREATMENT AND DISPOSAL
4.1 INTRODUCTION
The estimates of the quantities of net water consumed and wet solid
residuals generated calculated earlier are based on the assumption that no
water streams leave the mine-plant boundaries and that all effluent streams
are recycled or reused within the mine or plant after any necessary treatment.
These streams include the organically contaminated waters generated in the
conversion process, which are unfit for disposal without treatment, and the
highly saline water blown down from evaporative cooling systems or produced
during regeneration of the ion exchange units required to treat the source
water to boiler feed water quality. The process waters are treated for use as
makeup to the cooling towers while we have generally assumed that the highly
saline wastes are disposed of with the coal ash, or used for flue gas desulfurization.
If the saline wastes cannot be disposed of with the coal ash, it can be released
to evaporation ponds as a method of salt disposal. However, the saline wastes
must be highly concentrated before disposal to evaporation ponds to reduce the
evaporation loss. The rest of the water leaves the plant as vapor, as bonded
hydrogen (after hydrogenation) in the hydrocarbon product, and as occluded
water in the solid residues. The plants are designed not to be wasteful of
water by utilizing a relatively high degree of water reuse and conservation.
However, they are not designed for minimum water consumption, nor are they
designed to return wastewater to the source water. Returning water to a
source is not economic when the water must be cleaned to a quality equal to or
better than the source water to meet environmental regulations.
All wet solid residuals must be disposed of in an environmentally acceptable
manner. Toxic and soluble organic materials must be destroyed and toxic heavy
metal salts must be converted to insoluble forms. Soluble inorganic sludges
and toxic residuals from the coal ash must be contained in disposal sites to
prevent leaching into drinking water sources.
In this section we will estimate the costs of treating water in a coal
gasification plant for the purpose of recycling and reusing the water for
165
-------
in-plant uses to minimize the problem of disposal of contaminated waste streams.
In addition we will estimate the costs of the treatment and disposal of cooling
tower blowdown for the two cases of zero discharge and effluent discharge to
the receiving water. We did not consider the cost of disposal of all of the
wet-solid streams, nor did we consider the treatment to remove trace contaminants
since it was beyond the scope of this program.
The cost and energy estimates for water treatment and blowdown disposal
are much less well defined than the water quantities. Although the water
treatment technologies considered are achievable, experimental evidence for
coal conversion process waters is not available to fully assess them. For
this reason designs and costs must be regarded with a greater degree of uncertainty
than the estimates of water quantity requirements. In addition we have only
used one or two water flow diagrams for treating the waters in gasification
plants, each applicable to one or more process at many sites. We have only
considered a limited number of blowdown treatment and disposal procedures to
arrive at a range of costs.
4.2 PROCESS AND COOLING WATER TREATMENT
In any synthetic fuel plant high quality water is required for the process
as boiler feed water, intermediate quality is required for cooling and low
quality for mine uses. Central to any water reuse scheme in a coal gasification
plant is the disposition of the wastewater out of the process which is so
contaminated that its release to the environment in any form is unacceptable.
The water contains the products of coal reaction, coal decomposition, coal
pyrolysis and varying amounts of soluble inorganic products from coal ash and
gangue. The quality of this foul condensate wastewater depends on the coal
and the conversion process, particularly on the gasifier temperature, and to a
lesser extent on the reactor residence time and configuration. A summary of
the qualities of foul condensate wastewaters for coal conversion processes is
given in Reference 2. If chemical oxygen demand, COD, is taken as the primary
measure of the pollutant level, the dirtiest water is from the lowest temperature
166
-------
processes such as Synthane and Lurgi, using the lower rank lignite and subbituminous
coals. The range of COD is from about 17,000 to 43,000 mg/12. Intermediate
quality water with a COD -x. 3,0002 is obtained from higher temperature processes,
such as Hygas, with the higher rank bituminous coals. Entrained flow gasifiers,
such as Koppers and Bigas, are very hot and the condensate is not organically
2
contaminated to any important extent (COD <100) .
The condensate wastewaters contain large quantities of ammonia and carbon
dioxide. In gasifying Western low sulfur coals, the wastewater will not
contain much hydrogen sulfide. The condensates are also high in phenols and
contain fatty acids and other compounds which are mostly biodegradable ' .
Large amounts of hydrogen sulfide are found in the wastewater when gasifying
Eastern high sulfur coals.
The foul condensate wastewater is assumed to be treated and used as
makeup to the cooling tower. Additional makeup to the cooling tower comes
from the source water. The cooling tower is blown down to prevent scale
formation in the cooling system. In this section the costs and energy required
to treat (1) the source water to boiler water makeup quality, (2) the foul
condensate wastewater for use in the cooling tower, and (3) the circulating
cooling water will be estimated for the Synthane and Lurgi processes. The
costs for disposing of the wastewater streams are estimated in the next section.
Figure 4-1 are water treatment block diagrams used for all of the Synthane
and Lurgi plants (taken from Reference 5). The schemes are not unique, but
contain the main components of any water treatment plant: boiler feed water
preparation, process water or condensate cleanup, and cooling water treatment.
Figure 4-lA is used when the process condensate is insufficient to meet all of
the cooling needs of the plants. It was used for the Synthane plants at
Beulah, North Dakota; Colstrip, Montana; Gillette, Wyoming; and Navajo/Farmington,
New Mexico; and for the Lurgi plant at Colstrip and Navajo/Farmington. Figure
4-IB is used when the process condensate is sufficient to meet all of the
cooling needs of the plant and was used for the Lurgi plants at Beulah and
Gillette. The Lurgi process is assumed to accept wet coal, while the feed
167
-------
RAW HATER
Streams are numbered for identification
RAH WATER
cn
CO
21
1 "
25
26
1
(REVEGETATION^
2T
1
POTABLE
TREATMENT
U
(SERVICE & "N
ANITARY USE^
29
32
20*-,
\ , i **
£ RESERVOIR ^il-* EVAPORATION
ii
3
[SOFTENER NO. i ^> SLUDGE
s
BOILER FEED
TREATMENT ~> HASTE
FIG. 11-2 ~^
1«
34 .. CONDENSATE
POLISHING
. A^
4-^ f PROCESS J
i.
EXTRACTION 1 — t- PHENOL
i»
AMMONIA _>. AMMONIA
SEPARATION
36 J10
Til
^
* BIOTREATMENT ^* SLUDGE
16
FILTER | ia ^
1 , J
,M (CONTROL 0 CFC
^-^V TOWER V
,is '1 NO, 3 J
(ASH ~\ ^
DISPOSAL J SLUDGE
EVAPORATION
SLUDGE
WASTE
1
(^REVEGETATION)
/'SERVICE & A
^SANITARY USE 7
*j BIOTREATHENT f^>SlUDGE
A. Water treatment plant block diagram for
all Synthane and some Lurgi plants.
B. Water treatment plant block diagram for
some Lurgi plants.
Figure 4-1 Water treatment block diagrams.
-------
coal for the Synthane process is dried and the water lost in evaporation. At
Beulah and Gillette, because of the high moisture content of the coals, enough
water is produced during Lurgi gasification to more than supply all of the
cooling needs of the plant.
Table 4-1 lists the water flow quantities for each of the plant-site
combinations which are derived from the results presented in Reference 1,
Section 10, and Reference 5. The stream numbers correspond to those in Figure
4-1. In the analysis of Ref.l, the process stream flow rates for Synthane
were assumed to be the same at all sites.
In all cases but one the cycles of concentration in the cooling tower
were assumed to be equal to ten (10) as compared to the value of 51 used in
Reference 1. Ten cycles of concentration is a well established value in
cooling towers in the West. The flow quantities were adjusted to accomodate
this change. The one exception was the Lurgi plant in New Mexico in which the
cycles of concentration were reduced to 5.2 so that all of the blowdown would
be used for ash disposal. In preparing the flow diagrams, small errors were
found in some of the flow quantities calculated in Reference 1. In terms of
the total water consumed, the error for the Lurgi plants varied between 0.8 to
2.7 percent of the results presented in Reference 1 while for the Synthane
plants the variations did not exceed 0.5 percent.
The methods used to estimate cost and energy requirements for wastewater
treatment are given in Reference 5 while background information is found in
Reference 2. A brief description of the treatment blocks used in the water
treatment plant, together with the cost and energy estimates, are given below.
Boiler Feed Water Treatment
Ion Exchange; This treatment is required for all plants. For the Synthane
and Lurgi processes boiler makeup consists primarily of steam which reacts,
and some excess steam which is added to the gasifier to control the
temperature. All of the plants use high pressure steam to drive rotating
machinery, but the condensate is returned with less than 2 percent loss. The
cost of ion exchange depends on the quantity and quality of the intake water
and on the pressure of the steam raised in the boiler; the higher the pressure,
169
-------
TABLE 4-1 WATER FLOW QUANTITIES IN 10 LB/HR
Stream
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
A*
2623
-
1861
1861
1861
1852
1994
1069
1069
1069
1500
-
-
1208
58
297
164
133
-
1713
762
7
-
0
762
0
22
22
5
-
132
740
573
142
-
431
132
-
190
2630
Synthane
Navaj o/
Beulah Colstrip Gillette Farmington
N.D. Montana Wyoming New Mexico
Beulah Colstrip Gillette Farmington
N.D. Montana Wyoming New Mexico
A*
2660
1861
1861
1861
1852
1994
1069
1069
1069
1500
1268
60
237
147
90
1800
799
16
0
799
0
22
22
5
140
777
573
142
431.
140
200
2676
A*
2646
1861
1861
1861
1852
1994
1069
1069
1069
1500
1299
39
206
133
73
1814
785
19
0
785
0
23
23
5
163
762
573
142
431
163
202
2665
A*
2945
1861
1861
1861
1852
1994
1069
1069
1069
1500
1141
171
364
258
106
1880
1084
28
0
1084
65
24
24
5
38
995
573
142
431
38
209
2973
B*
1167
1145
1145
1145
1511
1501
1790
1782
1782
1732
1782
372
1209
1581
83
206
58
148
1059
22
3
366
0
22
0
22
22
5
_
407
289
289
A*
* 1567
-
1411
1411
1411
1403
1672
1313
1313
1313
1313
-
-
1127
87
191
92
99
1113
156
10
-
0
156
0
22
22
5
37
134
269
269
B*
1443
1420
1420
1420
1492
1484
1770
1476
1476
1476
1476
5
1296
1301
51
180
99
81
1136
23
10
72
o"
23
0
23
23
5
_
80
286
286
A*
1904
-
1461
1461
1461
1453
1732
1172
1172
1172
1172
-
-
899
238
278
161
117
996
443
18
-
0
443
65
24
24
5
0
354
279
279
35
118
1170
37
124
1577
75
126
1466
0
238
1922
*Designates block diagram used (See Figure 4-1)
170
-------
the more restrictive are the feed water requirements and the higher the cost.
The pressure of the Lurgi gasifier is in the range of 350-450 psig, while the
Synthane gasifier has a pressure of approximately 1000 psig. The boiler feed
water makeup (Stream No. 5 in Table 4-1) for the Lurgi plant ranged from about
1410 to 1510 x 10 Ib/hr, while for Synthane the value was 1861 x 103 Ib/hr.
In Reference 1 not enough information was available to distinguish between
coals fed to the Synthane process so that the flows entering and leaving the
boiler and gasifier were assumed to be the same at all four sites.
The ion exchange system used to treat the river water source at all four
sites consists of a weak acid resin, a strong acid resin, a degasifier, a weak
base resin, a strong base resin and a mixed bed or mixture of strong acid and
strong base resins. The weak acid resin removes only that part of the total
positive ions equivalent to the bicarbonate alkalinity and replaces them with
j_ ti
H ions. It is particularly suitable for removing divalent ions such as Ca
and Mg . Its main advantage is that it is easy to regenerate with sulfuric
acid requiring about 110% of stoichiometry. The strong acid resin replaces
all of the other positive ions with H . However, it is much less efficient
than the weak acid resin and requires H SO regenerant usage of about 200%
stoichiometry. In all of the designs the sulfuric acid regenerant is first
passed through the strong acid resin and then through the weak acid resin,
ensuring a high degree of acid use.
Carbonic acid is formed in the weak acid column. It decomposes to water
and gaseous carbon dioxide with the latter removed in the degasifier. The
degasifier is placed after the strong acid resin to take advantage of the shift in
the dissolved carbonate equilibrium to carbonic acid with decreasing pH.
The weak base resin is used to replace Cl and SO with OH . This resin cannot
.remove the weakly dissociated carbonic acid from the alkalinity or silicic
acid from the silica content in the water. It is easily regenerated with
caustic soda requiring about 110 percent of stoichimetry. The strong base
resin removes all of the remaining weakly dissociated and strongly dissociated
acids, particulary SiO , but i£s regeneration with caustic soda is not efficient.
As with the weak acid/strong acid resin system, the caustic soda is first
passed through the strong base resin to the weak base resin, thus ensuring a
high degree of chemical usage.
171
-------
The mixed bed polishes the demineralized water to the desired boiler feed
water quality without large swings in pH.
Condensate polishing, although necessary, is minor and its cost is
neglected in the calculations.
The cost of the ion exchange system is 9.5 QC/hr for Lurgi and 10.5 Q«?/hr
for Synthane, where Q is the flow rate in 103 lb/hr2'5. The energy requirements
are assumed to be negligible. The wastewater flow is approximately 6 percent
by weight of the feed water.
Reverse Osmosis: This is used to return treatment condensate to the
boiler in those Lurgi plants where all of the condensate is not required in
the cooling tower (at Beulah, North Dakota and Gillette, Wyoming). It is
followed by activated carbon adsorption. The cost of the reverse osmosis
2 3
system is 19.5 Q - 0.0043 Q , where Q is the flow rate in 10 lb/hr. Sequester-
ing chemicals are included in the cost. The energy requirements are 10,000 Q
Btu/hr. The waste is approximately 10 percent of the feed water.
Activated Carbon Adsorption: The cost is 12 Q C/hr, where Q is the feed
flow rate in 10 lb/hr, and the energy requirements are 4,500 Q Btu/hr. It may
be necessary for the carbon bed to precede reverse osmosis so as to prevent
membrane fouling, but the arrangement shown in Figure 4-IB is preferable
because it reduces the load on the carbon. The waste is negligible.
Process Condensate Treatment
In gasification plants the treated process condensate wastewater will
be used as makeup to the cooling tower either by itself or blended with water
from the river. Most of the contaminants in the treated process condensate
wastewater will end up more concentrated in the blowdown from the cooling
tower. However, some contaminants will be reduced in concentration; for example,
ammonia will volatalize . Similarly, data from refineries using phenolic
wastewaters as makeup to cooling towers show that bio-oxidation of phenol will
•7 Q Q
occur with very high removal efficiencies ' ' . The blowdown from the cooling
tower will be used for ash disposal and flue gas desulfurization and/or will
be disposed of in a lined evaporation pond. We have assumed that any environmental
limitations on phenol and ammonia will be met by suitable treatment of the
process condensate. The dirty process condensate is assumed to have the
quality shown in Table 4-2.
172
-------
TABLE 4-2 QUALITY OF PROCESS CONDENSATE FROM SYNTHANE AND LURGI PROCESSES
USING SUBBITUMINOUS AND LIGNITE COALS (IN MG/L)
Phenol as C^H^OH 6,000
D 3
Ammonia as NH 7,000
BOD 20,000
Ca++
Mg
HCO~ 14,000
Sulfide as S small
SO_ small
173
-------
The flow rate of the process condensate wastewater is in the range of
approximately 1170 to 1780 x 1Q3 Ib/hr for the Lurgi process and is 1069 x 10
Ib/hr for the Synthane process.
Phenol Extraction: This is a solvent extraction of phenolic compounds in
2
which the phenols are recovered to help defray the cost of the treatment .
The process is used only when the foul condensate is highly concentrated and
was used at all plant-sites. The capital investment, maintenance and energy
costs are relatively insensitive to the feed concentration and is not less
than $3.00/1000 gals. The value of the recovered phenol is probably limited to
its fuel value, about 2.3C/lb phenol. Ninety-five percent removal of phenol
is assumed while BOD is reduced by 2.26 p where p is the influent phenol
concentration. The net process cost, in C/hr is given by 36 Q - 0.00219 y Q,
where Q is the feed rate in 10 Ib/hr and y is the phenol concentration in the
feed stream in mg/1. The energy requirements are 10 Btu/1000 gals, or 120,000 0
Btu/hr . The waste flows are negligible.
Ammonia Separation: Ammonia is derived from nitrogen in the coal and,
except for gasifiers which run so hot that ammonia is not formed, is produced in
large quantities whether or not organic molecules are produced. The ammonia
is removed from the gas stream in the condensate. Blowing ammonia into the
air is not permissible from strong solutions because it is odorous. Ammonia
separation is required for all process-site combinations. The process is a
distillative, extractive one in which the wastewater is steam stripped and the
ammonia recovered from the stripper overhead gases and sold as
2
anhydrous ammonia to defray the costs of treatment . Approximately 20 to 40
trays are required at a steam rate of about 0.9 Ib steam per gallon wastewater.
Ammonia is reduced to 450 mg/1 at which concentration it is a suitable nutrient
for subsequent biotreatment. The USS Engineers and Consultants PHOSAM-W
process producing anhydrous ammonia was the one selected as it appears to be
the most economical of the processes studied. The cost of ammonia stripping
and recovery is given by [43Q - 0.007(y -450)Q] £/hr, where it has been assumed
2
that the value of the recovered ammonia is 7
-------
Biological Treatment; Most of the organic material in the process condensate
is biodegradable. Biological oxidation is a suitable treatment to remove the
organic contamination. Two multistage air or high purity oxygen activated
sludge tanks used in series give a high removal efficiency. The product water
is in the range of 200-500 mg/1 BOD and 10-100 mg/1 phenols. The most probable
cost is in the range 4.5 to 6.5
-------
Total Costs and Energy Requirements
The total costs and energy requirements for water treatment in standard
size Synthane and Lurgi plants are listed in Tables 4-3 and 4-4 and shown
graphically in Figures4-2 and 4-3. The results are also normalized with
respect to the heating value of the product gas. The water treatment costs
range from 8.0 to 12.2C/106 Btu product output, while the energy requirements
for water treatment range from 3.9 to 6.5 percent of the product output.
The cost of the product fuel will probably be in the range of
$3-4/105 Btu so that the water treatment costs, after taking credit
for the sale of byproduct ammonia, will not exceed 5 percent of the sale of the
product fuel. The total costs and energy requirements for water treatment are
primarily dependent on the costs and energy requirements for process condensate
treatment. The costs of cooling water treatment comprise the lowest costs
while boiler feed water treatment costs are intermediate.
The cost of water treatment for the Synthane plants are insensitive to
site. This is attributed to the fact that (1) the costs of boiler feed water
and process condensate treatments are the dominant costs of water treatment,
and (2) the flows entering and leaving the gasifier and boiler were assumed to
be the same for all four sites. The total costs of water treatment for the
Lurgi plants are dependent on the quantities of dirty process condensate
treated, with the largest amount treated at ,Beulah and the smallest amount
treated at Navajo/Farmington. The quantity of dirty process condensate
generated for Lurgi is dependent primarily on the moisture content of the
coal (see Figure 4-4) . Differences in the cost of water treatment between the
Lurgi and Synthane processes at a given site reflect the differences in the cost
of both condensate treatment and boiler feed water treatment. The ion exchange
costs for the Synthane process are greater than those for the Lurgi process
because more steam is required and the quality of the boiler feed water is higher
for Synthane. At Beulah, N. Dakota, however, more condensate is produced in the
Lurgi process than is needed for makeup to the cooling tower; the excess
condensate is treated by reverse osmosis and carbon adsorption for use in the
boiler thereby increasing the boiler feed water treatment costs above those for
Synthane. On the other hand, the processs condensate treatment costs for the
Lurgi process are greater than those for Synthane because more process condensate
is generated. The Lurgi process accepts wet coal, while the coal for the Synthane
176
-------
TABLE 4-3 COSTS OF WATER TREATMENT IN C/HR
Synthane
Boiler Feedwater Treatment
Ion Exchange
Reverse Osmosis
Activated Carbon
Adsorption
Subtotal
Process Condensate Treatment
Phenol Extraction
Ammonia Separation
Biological Treatment
Subtotal
Cooling Water Treatment
Filter
Acid Addition
Other Chemicals
Lime-Soda Softening
Subtotal
TOTAL
Beulah
N.D.
14,350
7,220
4,390
25,960
40,740
- 5,080
57,380
93,040
540
190
2,160
-
2/890
121,890
Co Is trip
Montana
13,400
-
-
13,400
30,020
- 3,740
42,280
68,560
390
190
2,270
860
3,710
85,670
Gillette
Wyoming
14,170
1,530
860
16,560
33,750
- 4,210
47,530
77,070
450
160
2,310
-
2,920
96,550
Nava j o/
Farmington
New Mexico
13,880
-
-
13,880
26,790
- 3,340
37,740
61,190
310
260
4,360
-
4,930
80,000
Beulah
N.D.
19,540
-
—
19,540
24,440
- 3,050
38,730
60,120
410
550
3,480
860
5,300
84,960
Colstrip
Montana
19,540
-
~~
19,540
24,440
- 3,050
38,730
60,120
440
480
3,660
860
5,440
85,100
Gillette
Wyoming
19,540
—
19,540
24,440
- 3,050
38,730
60,120
450
530
3,700
860
5,540
85,200
Farmington
New Mexico
19,540
™
19,540
24,440
- 3,050
38,730
60,120
390
570
3,830
860
5,650
85,310
TOTAL (C/10 Btu)
12.2
8.6
9.7
8.0
8.5
8.5
8.5
8.5
-------
TABLE 4-4 ENERGY REQUIREMENTS FOR WATER TREATMENT IN 10 BTU/HR
-j
oo
Navaj o/
Beulah Colstrip Gillette Farmington
N.D. Montana Wyoming New Mexico
Synthane
Beulah Colstrip Gillette Farmington
N.D. Montana Wyoming New Mexico
Boiler Feedwater Treatment
Ion Exchange
Reverse Osmosis
Activated Carbon
Adsorption
Subtotal
Process Condensate Treatment
Phenol Extraction
Ammonia Separation
Biological Treatment
2
6
214
364
69
_
_
158
268
51
0.3
1.3
177
301
57
_
_
141
239
45
Subtotal
Cooling Water Treatment
Filter
Acid Addition
Other Chemicals
Lime-Soda Softening
Subtotal
TOTAL
647
653
128
218
46
128
218
46
128
218
46
128
218
46
477
534
425
392
392
392
392
477
535
425
392
392
392
392
TOTAL (% of product energy) 6.5
4.8
5.4
4.3
3.9
3.9
3.9
3.9
-------
16
14
12
10
^O 8
-tx
LURGI
TREATMENT
1 I Condensote
Pg^l Bailor Feed
I-^K\ Cooling Water
SYNTHANE
BEULAH.N-D- COLSTRIP, MONT GILLETTE, WYO- NAVAJO,N-M-
ALL SITES
Figure 4-2. Cost of water treatment in C/IO^ Btu of product.
-------
00
o
I-
Ul
o
o:
UJ
a.
LURGI
TREATMENT
\ \ Condensate
Boiler Feed
SYNTHANE
BEULAH.N-D- COLSTRIf* MONT GILLETTE, WYO- NAVAJO.N-M-
ALL SITES
Figure 4-3. Energy consumed for water treatment in percent of the heating value of product fuel.
-------
1800
1700
i.
.c
_a
n
O 1600
1500
— i
Q
1400
1300
1200
1100
1000
BEULAH
GILLETTE
A COLSTRIP
NAVAJO/FARMINGTON
10 15 20 25
MOISTURE CONTENT, PERCENT
30
35
40
Figure 4-4. Quantity of dirty process condensate generated in a 250 X 10 scf/day
Lurgi plant as a funtion of moisture content of coal.
181
-------
process must be dried and the coal moisture is lost by evaporation. As a
result, the costs of water treatment for Synthane lie between the minimum and
maximum costs for Lurgi.
In a similar manner the energy requirements for water treatment primarily
are dependent on the quantity of process condensate generated and, to a lesser
extent, on the concentration of the contaminants to be removed. For the Lurgi
and Synthane processes we have assumed that the qualities of the process
condensate streams are the same (see Table 4-2) . For all of the processes the
energy required for the water treatment plants is controlled by the amount
needed for ammonia separation.
In Section 3 we defined three cooling options representing different
degrees of wet evaporative cooling for turbine condensers and interstage
coolers. The costs and energy requirements shown on Tables 4-3 and 4-4
correspond to a high degree of wet cooling for the Synthane process and an
intermediate degree of wet cooling for the Lurgi process. We would like to
estimate the water treatment costs and energy requirements for all three
levels of water consumption.
For all three cooling options we assume that the foul condensate wastewater
will be treated for use in the cooling tower or as makeup to the boiler.
Thus, the costs and energy requirements for process condensate treatment will
be unaffected by the choice of the cooling option. Tables 4-3 and 4-4 show
that the total costs and energy requirements are mainly dependent on the costs
and energy requirements of process condensate treatment. Thus, the total
costs and energy requirements are not expected to vary greatly with the cooling
water consumed in evaporation.
The costs of cooling water treatment varies almost proportionally to the
cooling tower makeup so that a reduction in the quantity of water evaporated
for cooling will lead to a similar reduction in the cost of cooling water
treatment. However, the cost of cooling water treatment does not exceed 7 per-
cent of the total cost of water treatment. If the cooling water requirements
are substantially reduced, then the process condensate may be sufficient to
meet all of the needs of the cooling tower. The excess wastewater may be
further treated for boiler water makeup (see Figure 4-IB) by reverse osmosis
and carbon adsorption, increasing the costs of boiler water makeup. Thus it
182
-------
is difficult to generalize the effect of cooling water consumption on the
costs of wastewater treatment.
For the Synthane process, the effect of going from a high degree of wet
cooling to minimum practical cooling is to reduce the costs of water treatment
by 0.1 to 0.15C/10 Btu with virtually no change in the energy requirements.
For the Lurgi process the effect of going to a high degree of water cooling
from intermediate cooling is to vary the costs of water treatment by -1.0 to
+0.25C/10 Btu, while the effect of going from intermediate cooling to minimum
practical cooling is to vary the costs from -0.07 to +0.77C/10 Btu. Similarly,
there is very little change in the energy requirements. In all cases the
variation in the water treatment costs with cooling option do not exceed 10
per cent of the costs shown in Table 4-3.
4.3 SLOWDOWN TREATMENT AND DISPOSAL
The overall effect of energy development on the Colorado River Basin is
to reduce the total salt loading or total salt content (in pounds of salt per
unit time) of the river and to increase the salinity concentration in the
downstream reaches of the river . The latter effect is attributable to the
reduced flow of water for dilution because of the large consumptive uses of
water for cooling within the conversion plants. Under the regulations of the
Colorado River Basin Salinity Control Forum, "the objective for industrial
12
discharges shall be a no-salt return policy wherever practicable." In
particular large coal-fired thermal electric generating plants have been
designed to eliminate the return of cooling tower blowdown water to the
Colorado River. This necessitates costly treatment and disposal procedures to
insure no return (zero discharge) to the receiving water. 'However, if the
blowdown is returned to the Colorado, the salinity concentration increase may
be reduced because of the increased dilution water, but at the expense of
increased salt loading. The cost to treat and return the blowdown to the
Colorado River will probably be lower than the cost of zero discharge.
We will leave the trade-off between increased dilution and increased salt
loading to other studies. In this section we are concerned about the trade-
off between the cost to treat and dispose of the blowdown and the quantity and
concentration of the blowdown, particularly with respect to total dissolved solids.
We have only considered blowdown streams from the cooling tower and not other
waste streams within the plant.
183
-------
We have estimated the costs of blowdown treatment and disposal for two
coal gasification processes, namely Lurgi and Synthane, and for steam electric
power generation at three specific sites: Beulah, North Dakota; Gillette,
Wyoming and Navajo/Farmington, New Mexico with and without zero discharge.
The Lurgi and Synthane plants each generate 250 x 10 scfd of pipeline gas at
a 90 percent load factor and the steam electric plant generates 3,000 MWe at a
70 percent load factor. We have not included the auxiliary costs associated
with piping, instrumentation, civil, structural and other detailed engineering
costs, since we are primarily concerned with the relative costs associated
with treatment and disposal. Furthermore, we have assumed for the coal gasification
plants that the process condensate has been treated sufficiently to remove
ammonia by ammonia stripping and organics by solvent extraction and biotreatment
(as described in Section 4.2) prior to addition to the cooling water system as
makeup so that disposal of the blowdown with the coal ash, or into an evaporation
pond, or into the receiving water, is environmentally acceptable. Similarly,
the blowdown from the cooling tower of a steam electric power plant is assumed
to contain non-toxic substances. Finally, only a limited number of blowdown
treatment procedures have been considered. No attempt has been made to optimize
the costs by considering a wide range of treatment procedures. An excellent
review of blowdown treatment procedures and costs is given in Reference 13.
Figure 4-5 is a general drawing showing the nomenclature. We only consider
the makeup water to the cooling tower, Q , and not the total water taken out
of the river for all consumptive uses. In the case of zero discharge, Q = 0,
the cooling tower blowdown is treated, part of the blowdown is recycled and
part is disposed of in a solar evaporation pond. In the case of effluent
discharge, the blowdown is treated and either part or all is discharged to the
receiving water.
Six cases were considered, each with the cooling tower operated at
either very few (N=2.5) cycles of concentration or at very high (N=10) cycles
of concentration. It was assumed that when the cooling tower was operated at
only 2.5 cycles of concentration, chemical treatment of the circulating cooling
water was the only treatment necessary. The high cycles example assumed was 10
cycles of concentration, which is typical of design practice in power plants
184
-------
REUSE IN PLANT
CO
cn
CCX)LING
TOWER
O.C.M
SLOWDOWN
TREATMENT
0 FLOW RATE
C CONCENTRATION OF STREAM
M QC
Q ,C ,M
3 3 3
EVAP
TO
EVAPORATION
POND
Figure 4-5. Flow diagram for blowdown treatment and disposal.
-------
located in the semi-arid West. To provide 10 cycles of concentration, sidestream
softening is required. By substituting a reactor-clarifier with multiple
chemical feeds for the traditional lime softening clarifier, several of the
treatments required for effluent discharge can be incorporated into the sidestream
treatment (see Figure 4-6). If the cooling tower blowdown stream is taken
from the overflow of the sidestream softening reactor-clarifier, separate
treatment for the removal of heavy metals, oil and grease and organics can be
eliminated. Lime-soda treatment in the reactor-clarifier will precipitate
heavy metals and polymer addition will remove those organics not originally
eliminated from the process condensate wastewater by biotreatment and/or
extraction prior to addition to the cooling tower makeup. Residual quantities
of oil and grease can be removed by designing the reactor-clarifier with a
scum skimmer and alum feed. After sidestream treatment the blowdown will only
require sand filtration for settable solids removal, pH adjustment via acid
addition and, for different cases, dissolved salts reduction. For all cases,
the river water first goes into a settling pond which is used to remove
suspended solids and provide storage capacity for the entire plant. The cost
of the settling pond was not considered since it would be approximately the
same for all cases.
The six cases are summarized in Table 4-5. Details are given on the
figures listed. Case I, shown in Figures 4-7 and 4-8 is for effluent discharge
into the receiving water when TDS reduction is not required. Case II, shown
in Figure 4-9 is the same as Case I, but a single stage electrodialysis membrane
process is used for TDS reduction. The concentrate from the electrodialysis
system goes to a solar evaporation pond for disposal, while the permeate is
discharged into the receiving water. Cases III, IV, V and VI are cases of
zero discharge. In Case III, shown in Figure 4-10, all of the blowdown from
the sidestream clarifier-reactor is disposed of in a lined solar pond for
evaporation to dryness. In Case IV, also shown in Figure 4-10, all of the
blowdown from the sidestream clarifier-reactor is used for in-plant uses, such
as ash disposal or fly ash removal, without any reduction in TDS. Case V,
which is shown in Figure 4-11, uses 3-stage electrodialysis which provides
almost 90% solids removal while recovering 90% of the cooling tower blowdown.
186
-------
POLYMER
LIME-SODA
EVAPORATION
AND DRIFT
MAKEUP
03
SCUM
COOLING TOWER
OVER
FLOW
SLOWDOWN
REACTOR-CLARIFIER
SIDESTREAM
-< <-
SLUDGE
COOLING WATER RETURN
COOLING WATER SUPPLY
Figure
4-6 Incorporation of blowdown treatment into sidestream treatment.
-------
TABLE 4-5. SUMMARY OF CASES STUDIED
Case
I A
I B
II A
II B
III A
III B
IV A
IV B
V A
V B
VI A
VI B
Figure
4-7
4-8
4-9
4-9
4-10
4-10
4-10
4-10
4-11
4-11
4-12
4-12
Cycles of
Concentration
2.5
10
2.5
10
2.5
10
2.5
10
2.5
10
2.5
10
Slowdown
Treatment Discharge
None Yes
None Yes
rSingle-Stage Yes
\_Electrodialysis Yes
Evaporation Pond No
Evaporation Pond No
Used in Plant No
Used in Plant No
fThree-Stage No
l^Electrodialysis No
Brine Concentrator No
Brine Concentrator No
188
-------
EVAP
t
I EVAPORAT
EVAPORATION AND DRIFT
00
c5
r- IT!
2S5
- -. ? i.-o:
VC ^ o'n>
cr. c <" o a>
o~' ~J f • CL Q-
cn- ~'.ro-g
1°>1"
»8|5S
si 5
COOLING TOWER MAKEUP
SLOWDOWN TO RIVER
COOLING WATER RETURN
COOLING WATER RETURN
*0.4Q,
Figure 4-7 Case I. Effluent discharge to river at low cycles of concentration.
-------
ACID
COOLING WATER RETURN
SIDESTREAH
REACTOR-
CLARIFIER
EFFLUENT DISCHARGE TO
COOLING WATER RETURN
H
&
O
FILTER
RIVER
Figure 4-8 Case I. Effluent discharge to river at high
cycles of concentration. TDS reduction not
required.
-------
vo
COXING
WATER
RETURN
SIDE-
STREAM
R EACTORJ
JCLARIFIER
COOLING WATER RETURN
FILTER
I
HIGH CYCLES OF CONCENTRATION
COOLING TOWER SLOWDOWN
LOW CYCLES OF CONCENTRATION
EFFLUENT DISCHARGE TO RIVER
ACID
SOLAR EVAPORATIO
POND
PERMEATE
CONCENTTHATE
Figure 4-9 Case II. Effluent discharge to river. TDS reduction
via single stage electrodialysis membrane system.
-------
HIGH CYCLES OF CONCENTRATION
CASE ///
LOW CYCLES OF CONCENTRATION
REACTOR-
CLARIFIER
COOLING WATER RETURN
COOLING TOWER SLOWDOWN
HIGH CYCLES OF CONCENTRATION
CASE IV
LOW CYCLES OF CONCENTRATION
REACTOR-
CLARIFIER
COOLING WATER RETURN
COOLING TOWER SLOWDOWN
IN PLANT USES
(ASH DISPOSAL, FLY ASH REMOVAL)
Figure 4-10 Cases III and IV. Zero discharge. Slowdown used for
in-plant uses or disposed of in a solar evaporation pond.
-------
VD
COOLING
WATER
R E TURN
SIDE-
STREAM
R EACTORl
jCLARIFIER
COOLING WATER RETURN
FILTER
HIGH C YCLES OF CONCENTRA TION
F ILTER
COOLING TOWER SLOWDOWN
LOW CYCLES OF CONCENTRATION
PRODUCT WATER RECYCLE TO PLANT
ACID
PERMEATE
SOLAR EVAPORATIO
POND
CONCENTRATE
Figure 4-il Case V. Zero discharge incorporating three
stage electrodialysis with wastewater recycle,
-------
In order to protect the membrane from sedimentation and scale deposits, the
blowdown is sand filtered and the pH adjusted with acid prior to electro-
dialysis treatment. The product filtrate from the electrodialysis modules is
recycled back to the cooling tower or boilers while the concentrate is pumped
to the solar ponds for evaporation. An alternative approach, which is used
extensively in power plants in the West, is to reduce the dissolved solids by
o 14
vapor compression using the system developed by Resources Conservation Co.
Case VI, shown in Figure 4-12, provides for a twenty-fold concentration of the
cooling tower blowdown and 96 percent recovery of the wastewater. The condensate
contains less than 10 ppm total dissolved solids and is usually used for high
quality water uses within the plant, such as for boiler water makeup. The
brine concentrate is sent to the solar ponds for evaporation.
Table 4-6 presents the calculated cooling tower blowdown and makeup rates
for each process-site combination. The evaporation, drift and waste treatment
flow rates are taken from Table 4-1 for the Synthane and Lurgi processes and
from Section 10 of Reference 1 for steam power generation. The blowdown and
makeup flow rates are calculated for N = 2.5 and N = 10 cycles of concentration.
Table 4-7 lists the flow rates as a fraction of the evaporation rate, and
the concentrations and total salt content of each stream as a fraction or
multiple of the makeup intake quantities (see Figure 4-5). Those cases in which
an evaporation pond is used have a higher total plant consumption of water than
those cases where a pond is not used. Cases II, III, V and VI require a higher
water consumption than Cases I and IV; Case III has the highest consumption. In
making this statement, we assume that water recycled for other plant uses decrease
the total water taken out of the river (not shown on Figure 4-5).
Relative total water consumptions are shown in the last column of Table 4-7,
(Q - Q0)/Q . Water consumption is minimized by minimizing the water evaporated
-L £ € V3.jp
in a pond (because this is not a useful consumption) and by using higher cycles
of concentration in the cooling tower.
The fraction of salt taken from the river which is returned to the river is
shown in Table 4-7 in the column headed, M /M . For the zero discharge Cases III
through VI, this is zero. The fraction of the salt taken from the river which is
disposed of in an evaporation pond is shown in the column, M /M . When M /M +
M3/M1 does not equal 1, it is because some salt is disposed of within the plant,
usually with ash. In Case IV all the salt is disposed of within the plant.
194
-------
Ln
COOLING
WATER
RETURN
SIDE-
STREAM
R EACTOR
CLARIFIER
ACID
COOLING WATER RETURN
FILTER
HIGH C YCLES OF CON CENTRA T/ON
FILTER
COOLING TOWER SLOWDOWN
LOW CYCLES OF CONCENTRATION
PRODUCT WATER RECYCLE TO PLANT
DISTILLATE
SOLAR EVAPORATIO
POND
\
I0\
CONCENTRATE
Figure 4-12 Case VI. Zero discharge incorporating vapor compression
brine concentration with wastewater recycle.
-------
TABLE 4-6 FLOW RATES IN GALLONS PER STREAM MINUTE
Lurgi
Evaporation &
Slowdown: N**
N =
Makeup: N =
N =
Synthane
Evaporation &
Slowdown : N =
N =
Makeup: N =
N =
Electric Power
Evaporation &
Slowdown: N =
N =
Makeup: N =
N =
Drift*
= 2.5
10.0
2.5
10.0
Drift*
2.5
10.0
2.5
10.0
Drift***
2.5
10.0
2.5
10.0
Beulah,
North Dakota
2,182
1,455
242
3,637
2,424
3,516
2,344
391
5,860
3,907
19,137
12,758
2,126
31,895
21,263
Gillette,
Wyoming
2,340
1,560
260
3,900
2,600
3,718
2,479
413
6,197
4,131
20,164
13,443
2,240
33,607
22,404
Nava jo/Farming ton
New Mexico
2,030
1,353
226
3,383
2,256
3,854
2,569
428
6,423
4,282
20,936
13,957
2,326
34,893
23,362
*From Table 4-1
**N is cycles of concentration
***From Section 10 of Reference 1.
196
-------
TABLE 4-7 FLOW RATES, CONCENTRATIONS AND SALT LOADING OF WASTE STREAMS
Case
I
II
III
IV
V
VI
N
2.5
10
2.5
10
2.5
10
2.5
10
2.5
10
2.5
10
Ql/Qevap
1.6667
1.1111
1.6667
1.1111
1.6667
1.1111
1.6667
1.1111
1.6667
1. 1111
1.6667
1.1111
Q2/Qevap
0.6667
0.1111
0.6
0.1
0
0
0
0
0
0
0
0
C2/C1
2.5
10
1.25
5
0
0
0
0
0.3125
1.25
0.00521
0.02083
M2/M1
1
1
0.45
0.45
0
0
0
0
0
0
0
0
Q3
"evap
0
0
0.0667
0.0111
0.6667
0.1111
0
0
0.0667
0.0111
0.0267
0.00444
24
0
evap
0
0
0
0
0
0
0.6667
0.1111
0.6
0.1
0.640
0.1067
C3
Cl
0
0
13.75
55
2.5
10
2.5
10 .
22.1875
88,75
62.375
249.5
M3
Ml
0
0
0.55
0.55
1
1
0
0
0.-8875
0.8875
0.998
0.998
QrQ2
Q
evap
1
1
1.0667
1.0111
1.6667
1.1111
1
1
1.0667
1. 0111
1.0267
1.0044
-------
A negative return of salt to the river can be made by returning water
with a lower salinity than the river water. This is expensive.
The capital costs of the major equipment components are given in Table 4-8.
The costs are based upon data presented in Appendix 11 of Reference 5 and
include installation. The equipment was sized for the stream flow rates given
in Table 4-6. A cost of $40,000 per acre was assumed for clay-lined solar
evaporation ponds with an adequate ground water monitoring system. This cost
is highly variable and very site dependent. The size of the evaporation pond
is determined by the net evaporation rate. The number of acres required for
each gpm of blowdown to be disposed of was calculated as follows: North
Dakota, 0.64 acres/gpm; Wyoming, 0.48 acres/gpm and New Mexico, 0.36 acres/gpm.
A capital cost of $6 per gallon per day was assumed for brine concentration.
The capital cost for each case and for each plant-site combination is given in
Table 4-9.
The lowest capital costs are for those cases where there is no limitation
on the method of disposing of the blowdown. This occurs for Case I, where the
blowdown is discharged directly to the receiving water, and for Case IV where
the blowdown is used in the plant. The capital costs for the other cases
increases in the following order: Case II, Case V, Case VI and Case III. For
Case II TDS reduction was required for effluent discharge to the receiving
water. Zero discharge was specified for the other three cases with final
treatment and disposal of the blowdown taking place in evaporation ponds. Of
the last three cases, the least expensive case was for blowdown treatment by
electrodialysis and the most expensive case was for complete blowdown disposal
in evaporation ponds; brine concentration fell in between the two cases.
The capital cost of the various disposal systems are strongly dependent
on the flow rate of the blowdown streams. Thus, the capital cost of the
treatment systems increases as the cycles of concentration decreases and as the
flow rate decreases in the following order: Lurgi, Synthane and electric
power generation (see Table 4-6). For a given process the variation of capital
cost with site was due to the variation in the quantity of water treated.
198
-------
TABLE 4- 8 CAPITAL COST OF MAJOR EQUIPMENT COMPONENTS IN THOUSANDS OF DOLLARS
N = 2.5 Cycles of Concentration
Equipment
ND
WYO
NM
ND
Synthane
WYO
NM
Electric Generation
ND
WYO
NM
1. Reactor-Clarifier
2. Sand Filter
3. Solar Ponds (Case 3)
4. Solar Ponds (Case 2,5)
5. Solar Ponds (Case 6)
6. Electrodialysis (Case 2)
7. Electrodialysis (Case 5)
8. Brine Concentr. (Case 6)
37,570 30,132 19,896
3,752 3,012 1,992
1,503 1,212 792
850 820 790
1,414 1,365 1,315
12,560 13,500 11,700
60,800 48,200 37,540
6,078 4,818 3,756
2,430 1,926 1,500
1,050 1,200 1,200
1,822 1,930 2,000
20,280 21,420 22,200
329,160
32,916
13,140
3,720
7,440
110,220
259,860
25,986
10,380
3,920
7,840
116,120
202,980
20,298
8,100
4,070
8,140
120,600
Case I =1+2
Case II =1 + 2 + 4 + 6
Case III =1+3
Case IV = 1
Case V =1 + 2 + 4 + 7
Case VI =1 + 2 + 5 + 8
(Continued)
-------
TABLE 4-8 (concluded)
N = 10 Cycles of Concentration
o
o
Equipment
1. Reactor-Clarif ier
2. Sand Filter
3. Solar Ponds (Case 3)
4. Solar Ponds (Case 2,5)
5. Solar Ponds (Case 6)
6. Electrodialysis (Case 2)
7. Electrodialysis (Case 5)
8. Brine Concentr. (Case 6)
Lurgi
ND WYO NM
182 196 171
24 26 23
6,249 5,022 3,316
624 502 332
250 202 132
306 314 294
470 505 453
2,090 2,250 1,950
Syn thane
ND WYO NM
289 312 323
39 41 43
10,133 8,033 6,256
1,013 803 626
405 321 250
380 386 374
570 602 607
3,380 3,570 3,700
Electric Generation
ND WYO NM
821 826
213 224
54,860 43,310 33,
5,486 4,331 3,
2,190 1,730 1,
1,030 1,000 1,
1,770 1,742 1,
18,370 19,354 20,
Case I =1 + 2
Case II =1 + 2 + 4 + 6
Case III =1+3
Case IV = 1
Case V =1 + 2 + 4 + 7
Case VI =1 + 2 + 5 + 8
831
233
830
383
350
085
810
100
-------
TABLE 4-9 CAPITAL COST OF TREATMENT AND DISPOSAL SYSTEMS IN THOUSAND OF DOLLARS
N = 2.5 Cycles of Concentration
Case
Case
Case
Case
Case
Case
Case
Case
Case
Case
Case
Case
i
II
III
IV
V
VI
ND
-
4,602
37,570
-
5,166
14,063
I
II
III
IV
V
VI
206
1,136
6,431
182
1,300
2,546
Lurgi
WYO
-
3,832
30,132
-
4,377
14,712
222
1,038
5,218
196
1,229
2,674
NM
-
2,782
19,896
-
3,307
12,492
ND
-
7,128
60,800
-
7,900
22,710
N = 10
194
820
3,487
171
979
2,276
328
1,721
10,422
289
1,911
4,113
Syn thane
WYO
-
NM
-
6,018 4,956
48,200 37
-
6,748 5
23,346 23
Cycles of
353
1,542 1
8,345 6
312
1,758 1
4,244 4
,540
-
,756
,700
Electric Generation
ND WYO NM
-
36,636
329,160
-
40,356
123,360
Concentration
366
,366
,579
323
,599
,316
1,034
7,550
55,681
821
8,290
21,594
-
29,906
259,
33,
124,
1,
6,
44,
7,
22,
860
-
826
500
050
381
136
826
123
134
-
24,368
202,980
-
28,438
128,700
1,064
5,532
34,661
831
6,257
26,982
-------
The operating costs shown on Table 4-10 include a general maintenance
cost of 5% of capital per year, the cost of chemical addition estimated to be
$0.50/1000 gallons of blowdown at 2.5 cycles of concentration and $1.00/1000
gallons of blowdown at 10 cycles of concentration, the cost of membrane replacement
and power for those cases utilizing electrodialysis estimated at 30C/1000 gals
of blowdown processed, the cost of energy, labor and chemicals for brine
concentration estimated at $4.00/1000 gals of blowdown, and a discount of
$1.00/1000 gals for water recycled to the process in Cases V and VI, , which
represents the savings in water in substituting for an equal quantity of raw
makeup water which would otherwise have to be treated for suspended solids, pH
and dissolved solids to be equivalent in quality to the recycled water. The
flow rates used in estimating the operating costs are based on a load factor
of 90% for coal gasification and 70% for electric power generation.
The total amortization and operating costs are shown in Table 4-11 in
thousands of dollars per year. The amortization costs were based on a fixed
charge rate of 12 percent of the capital costs per year and were added to the
operating costs shown in Table 4-10. In general the total amortization
operating costs follow the same trend as the capital costs. However, if
credit is taken for recycle, the costs for Case V are lower than those for
Case II. Another exception is that there are some situations in which the
cost of brine concentration exceed those for treatment of the blowdown by
solar evaporation only (Case III).
We should note that brine concentration, although expensive, is a proven
method which is very, reliable and which is used extensively on many zero
discharge electric power plants in the West. It does offer investment tax
credit advantages over solar pond evaporation. In addition the product water
from the brine concentrator is of a better quality than the product water from
•
the electrodialysis unit and can be used directly for boiler water makeup.
The value of the product water is probably higher than $1.00/1000 gals assumed
for the calculations. Although we have not considered it, costs could be
reduced by using brine concentration in conjunction with electrodialysis.
202
-------
TABLE 4- 10 OPERATING COST OF TREATMENT AND DISPOSAL SYSTEMS IN THOUSANDS OF DOLLARS PER YEAR
N = 2.5 Cycles of Concentration
Case I
Case II
Case III
Case IV
o Case V
u>
Without credit for recycle
With credit for recycle
Case VI
Without credit for recycle t
With credit for recycle
ND
346
783
2,225
346
811
191
3,800
3,139
Lurgi
WYO
372
785
1,879
372
812
148
4,060
3,352
NM
322
654
1,317
322
679
103
3,508
2,894
ND
558
1,247
3,598
558
1,286
289
6,130
5,066
Syn thane
WYO
588
1,240 1,
2,998 2,
588
1,277 1,
221
6,448 6,
5,323 5,
NM
610
223
487
610
263
169
658
492
Electric Generation
ND
2,362
5,597
18,820
2,362
5,783
1,570
27,246
22,752
WYO
2,488
5,462
15,481
2,488
.5,658
1,218
28,534
23,798
NM
2,580
5,334
12,729
2,580
5,537
927
29,490
24,573.
(Continued)
-------
TABLE 4-10(concluded)
N = 10 Cycles of Concentration
NJ
O
Case I
Case II
Case III
Case IV
Case V
Without credit for recycle
With credit for recycle
Case VI
Without credit for recycle
With credit for recycle
ND
125
206
437
125
214
111
700
590
Lurgi
WYO
135
213
385
135
223
112
750
632
NM
117
180
281
117
188
92
649
547
ND
202
328
707
202
328
162
1,131
954
Syn thane
WYO
213
332
613
213
348
172
1,190 1
1,003 1
NM
221
332
532
221
344
162
,229
,035
Electric
Generation
ND WYO
839
1,399 1,
3,014 3,
839
1,436 1,
734
4,985 5,
4,236 4,
882
394
036
882
431
691
221
432
NM
913
1,393
2,593
913
1,429
661
5,621
4,802
-------
TABLE 4-11 AMORTIZATION AND OPERATING COSTS OF TREATMENT AND DISPOSAL SYSTEMS
IN THOUSANDS OF DOLLARS PER YEAR
N = 2.5 Cycles of Concentration
NJ
O
Case I
Case II
Case III
Case IV
Case V
Without credit for recycle
With credit for recycle
Case VI
Without credit for recycle
With credit for recycle
ND
346
1,335
6,733
346
1,431
811
5,488
4,827
Lurgi
WYO
372
1,245
5,495
372
1,337
673
5,825
5,117
NM
322
988
3,705
322
1,076
500
5,007
4,393
ND
558
2,103
10,894
558
2,234
1,237
8,855
7,791
Syn thane
WYO
588
1,962 1
8,749 6
588
2,087 1
1,031
9,250 9
8,124 8
NM
610
,818
,992
610
,953
859
,502
,336
Electric Generation
ND
2,362
9,993
58,319
2,362
10,626
6,413
42,049
37,555
WYO
2,488
9,051
46,664
2,488
9,717
5,277
43,714
38,978
NM
2,580
8,258
37,087
2,580
8,950
4,340
44,934
40,017
(Continued)
-------
TABLE 4-11 (Concluded)
N = 10 Cycles of Concentration
Case I
Case II
Case III
Case IV
Case V
Without credit for recycle
With credit for recycle
Case VI
Without credit for recycle
With credit for recycle
ND
150
342
1,208
147
370
267
1,005
896
Lurgi
WYO
162
338
1,011
159
370
259
1,071
953
NM
140
278
699
138
305
209
922
820
ND
241
534
1,958
237
557
391
1,625
1,448
Syn thane
WYO
255
517
1,614 1
250
560
383
1,700 1
1,512 1
NM
265
496
,321
260
536
354
,747
,553
Electric Generation
ND
963
2,305
9,696
938
2,431
1,728
7,576
6,827
WYO
1,008
2,160
8,332
981
2,286
1,546
7,877
7,088
NM
1,041
2,057
6,752
1,013
2,180
1,412
8,859
8,040
-------
For gasification the waste disposal costs (Table 4-12) range from about
0.45C/10 Btu to 14.1C/10 Btu at low cycles of concentration, and from
0.18C/10 Btu to 2.53C/10 Btu at high cycles of concentration; for steam
electric power generation the costs range from 0.40 mils/kw-hr to 9.5 milsAw-
hr at low cycles of concentration and 0.15 mils/kw-hr to 1.6 mils/kw-hr at
high cycles of concentration. As a basis of comparison, the cost of pipeline
gas is estimated to be about 300C/10 Btu, while electricity costs about 20-30
mils/kw-hr.
The total amortization and operating costs for blowdown treatment and
disposal have also been normalized with respect to the flow rate of the
blowdown. The results of these calculations are shown in Table 4-13. Across
all processes, the costs range from $0.50/1000 gals of blowdown to $12.50/1000
gals of blowdown at low cycles of concentration and $1.20/1000 gals of blowdown
to $12.50/1000 gals of blowdown at high cycles of concentration. The normalized
costs are higher for higher cycles of concentration than for lower cycles because
of the differing flow rates. At a given site and for a given number of cycles of
concentration, the costs normalized with respect to the blowdown flow rate are
relatively insensitive to either pipeline gas production or steam electric power
generation for a particular case of blowdown treatment and disposal. The
maximum difference occurs for the case of disposal of all of the blowdown into
evaporation ponds and is approximately 20 percent between electric generation and
the Lurgi process. For a given process the costs are also relatively insensitive
to site with a difference of about 40-50C/1000 gals of blowdown for all cases
except for Case III.
REFERENCES (Section 4)
1. Gold, H., et al, "Water Requirements for Steam-Electric Power generation
and Synthetic Fuel Plants in the Western United States," EPA Report No.
600/7-77-037, U.S. Environmental Protection Agency, Washington, D.C.,
April, 1977.
2. Goldstein, D.J. and Yung, D., "Water Conservation and Pollution Control
in Coal Conversion Processes," EPA Report No. 600/7-77-065, U.S. Environmental
Protection Agency, Research Triangle Park, N.C., January, 1977.
207
-------
TABLE 4-12 AMORTIZATION AND OPERATING COSTS OF TREATMENT AND DISPOSAL SYSTEMS
NORMALIZED WITH RESPECT TO THE PRODUCT ENERGY OUTPUT
N = 2.5 Cycles of Concentration
o
co
Case I
Case II
Case III
Case IV
Case V
Without credit for recycle
With credit for recycle
Case VI
Without credit for recycle
With credit for recycle
Lurgi*
ND WYO NM
0.45 0.48 0.42
1.72 1.61 1.27
8.70 7.10 4.79
0.45 0.48 0.42
1.85 1.77 1.39
1.05 0.87 0.65
7.08 7.52 6.47
6.24 6.68 5.68
Syn thane*
ND WYO NM
0.72 0.75 0.79
2.72 2.53 2.35
14.07 11.30 8.94
0.75 0.75 0.79
2.89 2.70 2.52
1.60 1.33 1.11
11.44 11.95 12.28
10.07 10.50 10.77
Electric Generation**
ND WYO
0.39 0.41
1.63 1.47
9.51 7.61
0.39 0.41
1.73 1.58
1.05 0.86
6.86 7.13
6.12 6.36
NM
0.42
1.35
6.05
0.42
1.46
0.71
7.33
6.53
(Continued)
*In C/10 Btu product
**In mils/kw-hr generated = 0.K/kw-hr generated
-------
TABLE 4-12 (concluded)
N = 10 Cycles of Concentration
Case I
Case II
Case III
Case IV
M Case V
0
^ Without credit for recycle
With credit for recycle
Case VI
Without credit for recycle
With credit for recycle
ND
0.19
0.44
1.56
0.19
0.48
0.34
1.30
1.16
Lurgi*
WYO
0.21
0.44
1.30
0.21
0.48
0.33
1.38
1.23
NM
0.18
0.36
0.89
0.18
0.39
0.27
1.19
1.06
ND
0.31
0.69
2.53
0.31
0.72
0.51
2.10
1.91
Synthane*
WYO
0.32
0.67
2.09
0.32
0.72
0.49
2.20
1.95
NM
0.34
0.64
1.71
0.34
0.69
0.46
2.26
1.98
ND
0.16
0.38
1.58
0.15
0.40
0.28
1.23
1.11
Electric
WYO
0.16
0.35
1.36
0.16
0.37
0.25
1.28
1.16
Generation**
NM
0.17
0.33
1.10
0.17
0.36
0.23
1.44
1.31
*In C/10 Btu product
**In mils/kw-hr generated = O.lC/kw-hr generated
-------
TABLE 4- 13 AMORTIZATION AND OPERATING COSTS OF TREATMENT AND DISPOSAL SYSTEMS
IN DOLLARS PER THOUSAND GALLONS OF SLOWDOWN
N = 2.5 Cycles of Concentration
Case I
Case II
Case III
Case IV
Case V
Without credit for recycle
With credit for recycle
Case VI
Without credit for recycle
With credit for recycle
ND
0.50
1.94
9.78
0.50
2.08
1.18
7.97
7.01
Lurgi
WYO
0.50
1.69
7.45
0.50
1.81
0.91
7.89
6.93
NM
0.50
1.54
5.79
0.50
1.68
0.78
7.82
6.86
ND
0.50
1.90
9.83
0.50
2.02
1.12
. 7.99
7.03
Syn thane
WYO
0.50
1.67
7.46
0.50
1.78
0.88
7.89
6.93
NM
0.50
1.50
5.75
0.50
1.61
0.71
7.82
6.86
Electric
Generation
ND WYO
0.50
2.13
12.42
0.50
2.26
1.37
8.96
8.04
0.50
1.83
9.44
0.50
1.97
1.07
8.84
7.88
NM
0.50
1.61
7.22
0.50
1.74
0.85
8.75
7.79
(Continued)
-------
TABLE 4-13 (Concluded)
N = 10 Cycles of Concentration
to
Case I
Case II
Case III
Case IV
Case V
Without credit for recycle
With credit for recycle
Case VI
Without credit for recycle
With credit for recycle
ND
1.31
2.99
10.55
1.28
3.23
2.33
8.78
7.83
Lurgi
WYO
1.32
2.75
8.22
1.29
3.01
2.11
8.71
7.72
NM
1.31
2.60
6.54
1.29
2.85
1.95
8.62
7.67
ND
1.30
2.89
10.59
1.28
3.01
2.11
8.79
7.83
Syn thane
WYO
1.30
2.65
8.26
1.28
2.87
1.96
8.70
7.74
NM
1.31
2.45
6.52
1.28
2.65
1.78
8.63
7.67
Electric Generation
ND
1.23
2.95
12.50
1.20
3.11
2.21
9.79
8.73
WYO
1.22
2.66
10.11
1.19
2.77
1.88
9.56
8.60
NM
1.22
2.40
7.89
1.18
2.55
1.65
10.35
9.31
-------
3. Singer, P.C., ot al, "Composition and Biodegradability of Organics in Coal
Conversion Wastcv/aters," in Symposium Proceedings, Environmental Aspects of
Fuel Conversion Technology, III (September 1977, Hollywood, Florida), EPA
Report No. 600/7-78-063, U.S. Environmental Protection Agency, Research
Triangle Park, N.C., April 1978.
4. Gloyna, E. F. , et al, "Petrochemical Effluents Treatment Practices," prepared
by Engineering-Science, Inc., Austin, Texas, for Federal Water Pollution
Control Administration, Contract No. 14-12-461, NTIS PB 205 824, February 1970.
5. Gold, H. and Goldstein, D.J., "Water Related Environmental Effects in Fuel
Conversion," EPA Report 600/7-78-197a, b, EPA, Research Triangle Park, N.C. ,
October 1978.
6. Grutsch, J.F. and Griffin, R.W., "Water Reuse Studies by the Petroleum
Industry," paper 5e delivered at 85th AIChE National Meeting, Philadelphia,
Pa., June 4-8, 1978.
7. Mohler, E.F., Jr., and Clere, L.T., "Bio-oxidation Process Saves H2O,
Hydrocarbon Processing,84-88, October 1973; also, same authors, "Development
of Extensive Water Reuse and Bio-oxidation in a Large Oil Refinery",
delivered at the National Conference on Complete Water Reuse, Washington, D.C.,
1973.
8. Hart, J.A., "Wastewater Recycle or Reuse in Refinery Cooling Towers",
The Oil and Gas Journal, 92-96, June 11, 1973.
9. Maguire, W.F., "Reuse of Sour Water Stripper Bottoms," Hydrocarbon Processing,
151-152, September 1975.
10. Goldstein, D.J., Hicks, R.E. and Liang, L., "Conceptual Designs for Water
Treatment in Demonstration Plants," on-going work with the Department of
Energy under Contract EF-77-C-01-2635 by Water Purification Associates.
11. Utah Water Research Laboratory, Utah State University, "Colorado River
Regional Assessment Study" prepared for the National Commission on Water
Quality, Washington, D.C., NTIS PB-249-660-01, October 1975.
12. Colorado River Basin Salinity Control Forum, "Water Quality Standards
for Salinity Including Numeric Criteria and Plan of Implementation for
Salinity Control - Colorado River System", June 1975.
13. Equitable Environmental Health, "Selected Aspects of Waste Heat Management:
A State - of-the-Art Study", EPRI Rept. No. FP-164, Electric Power Research
Institute, Palo Alto, California, June 1976.
14. Anderson, J.H., et al "Operational Experience with Brine Concentrations in
Electric Utility Wastewater Treatment". Proc. 36th Int'l Water Conf.,
Engineers' Society of Western Pennsylvania, Pittsburgh, Pa., Nov. 1975.
212
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TECHNICAL REPORT DATA
(Please read Imtntclions on the reverse before completing}
REPORT NO.
EPA-600/7-79-085
TITLE AND SUBTITLE
Wet/Dry Cooling and Cooling Tower Blowdown
Disposal in Synthetic Fuel and Steam-Electric
Power Plants
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
March 1979 issuing date
6. PERFORMING ORGANIZATION CODE
AUTHOR(S)
Harris Gold and David J. Goldstein
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Water Purification Associates
Cambridge, Massachusetts
10. PROGRAM ELEMENT NO.
EHE 62AC
11. CONTRACT/GRANT NO.
68-01-1916
12. SPONSORING AGENCY NAME AND ADDRESS
US Environmental Protection Agency
Office of Research and Development
Office of Energy, Minerals and Industry
Washington, DC 20460
13. TYPE OF REPORT AND PERIOD COVERED
Final July '77-December '78
14. SPONSORING AGENCY CODE
EPA-600/7
is.SUPPLEMENTARY NOTES A Subcontractor report to the Science and Public Policy
Program, University of Oklahoma Western Energy Study in the EPA-planned and
coordinated Federal Interagency Energy/Environment R&D Program.
16. ABSTRACT •
This report extends the results of a previous study dealing with the
detailed determination of consumptive water use and wet-solids residuals for coal
and oil shale conversion plants and coal-fired steam-electric power generation
plants located in the Western United States. The present report addresses the
problem of determining the degree to which wet cooling, dry cooling, or wet/dry
cooling should be used as a function of the true cost of water. The economics
of cooling gas compressor interstage coolers for coal conversion and cooling
steam turbine condensers for coal conversion and steam-electric power generation
are also examined. The report also includes resul.ts of a separate EPA/DOE study
of 42 coal/oil shale conversion plantsite combinations to provide an enlarged
data base for more meaningful regional water assessments. The costs of wastewater
treatment and blowdown treatment and disposal are calculated for coal conversion
and steam-electric power plants are also included.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
COSATl Field/Group
Electric Power
Fossil Fuels
Western Energy Resource
Development
Water Requirements
Blowdown Disposal
97F
18. DISTRIBUTION STATEMEN1
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
!1. NO. OF PAGES
212
20, SECUHITX CLASS (This page)
22. PRICE
EPA Form 2220-1 (0-73J
• III
-Ml-UT/M
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