U. S. DEPARTMENT OF THE INTERIOR SEPTEMBER 197O
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FEASIBILITY OF ALTERNATIVE MEANS OF COOLING
FOR THERMAL POWER PLANTS NEAR LAKE MICHIGAN
Prepared by:
National Thermal Pollution Research Program
Pacific Northwest Water Laboratory
and
Great Lakes Regional Office
U. S. Department of the Interior
Federal Water Quality Administration
August 1970
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1
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CONTENTS
Chapter Page
I. INTRODUCTION 1-1
Scope 1-1
Waste Heat Load 1-2
Cooling Methods 1-4
Regional Considerations 1-5
II. METEOROLOGY II-l
Data Requirements II-l
Seasonal Considerations II-l
Meteorological Data Summary II-3
Design Meteorological Data 11-8
Theoretical Limitations of Cooling Devices 11-13
Lake Temperatures 11-14
References 11-19
III. ECONOMIC CONSIDERATIONS I II-l
o General Cost Factors III-1
Study Approach III-2
> References III-9
(Vs
'{ IV. ENGINEERING CONSIDERATIONS IV-1
J>
Introduction IV-1
General Optimization Procedure IV-2
Dynatech Program IV-3
Ceramic Cooling Tower Program IV-8
R. W. Beck Program IV-10
References I V-l 2
V. RESULTS V-l
A. Cooling Systems V-l
Introduction V-l
Wet Cooling Towers V-l
Performance Data V-l
Mechanical Draft V-l
Natural Draft V-4
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Chapter
System Cost V-4
Mechanical Draft V-4
Natural Draft V~4
Cooling Ponds V-9
Performance Data V-9
System Cost V-9
Spray Cooling Canals V-13
Performance Data V-13
System Cost V-13
Dry Cooling Towers V-13
Performance Data V-13
Cooling System Cost V-16
Capital Cost V-16
System Cost V-17
B. Economics of Cooling Systems and Total Plants . . .V-20
VI. ENVIRONMENTAL EFFECTS OF COOLING DEVICES VI-1
Introduction VI-1
Fog Potential VI-2
Definition of the Problem VI-3
Environmental Studies VI-5
Potential in Lake Michigan Area VI-6
Calculations of Fog Potential VI-9
Method 1 VI-9
Method 2 VI-13
Consumptive Water Loss by Evaporation VI-20
Drift VI-27
Slowdown VI-28
Summary VI-38
References VI-39
VII. CONCLUSIONS VII-1
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I. INTRODUCTION
Scope
This report presents an evaluation of various methods of
dissipating waste heat from thermal power plants near Lake Michigan.
The feasibility of the cooling methods are considered from both an
engineering and economic standpoint.
It must be emphasized at the outset that the following analyses
are directed towards determining the feasibility of various cooling
methods; no attempt is made to optimize any particular plant or site.
In addition to determining the engineering and economic feasibility
of cooling devices, the effect of their operation on the environment is
examined.
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1-2
Haste Heat Load
The engineering calculations on the various cooling devices are
made on the basis of a "typical" 1000 MWe fossil-fueled power plant
with a nominal thermal efficiency of 40 percent. With in-plant and
stack losses of 15 percent of the total heat input, such a plant
will discharge 3.84 x 109 Btu/hr to the condenser cooling water. This
same waste heat load would be created by a 600 MWe nuclear power plant
with a boiling water or pressurized water reactor, assuming a nominal
thermal efficiency of 33 percent and 5 percent in-plant losses. Other
combinations of plant size and thermal efficiency which result in
3.84 x 109 Btu/hr waste heat to cooling water are shown in Figure 1-1
for both 5 percent and 15 percent in-plant losses. For example, a
750 MWe fossil-fueled plant (15 percent in-plant losses) with a thermal
efficiency of 34 percent has a waste heat load equivalent to the "base"
1000 MWe, 40 percent efficient plant.
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1100
1000
900
800
O)
O)
N
C/)
700 -
600
500 -
400
28 30 32 34 36 38
Nominal Thermal Efficiency (%}
40
42
Figure 1-1: Equation of Plant Size and Thermal
Efficiency for Waste Heat to Cooling
Water of 3.84 x lp9 Btu/hr.
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1-4
Cooling Methods
A wide variety of cooling methods are available for dissipating
waste heat from thermal power plants. The feasibility of the follow-
ing cooling devices are evaluated:
1) Evaporative cooling towers
a) Mechanical draft
b) Natural draft
2) Cooling ponds
3) Spray cooling canals
4) Dry cooling towers (Heller System)
a) Mechanical draft
b) Natural draft
A cooling system employing each of the above devices is sized
for a closed-cycle, recirculating configuration using design
meteorological data representative of critical summertime conditions.
The annual operating characteristics and costs of the selected systems
are evaluated using long-term seasonal average weather conditions.
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1-5
Reg i ona1 Con s i de ra t i on s
In order to account for regional variations in climatic con-
ditions, the Lake Michigan area is divided into four geographical
sections. Figure 1-2 shows these four sections: NW, NE, SE, and SW.
Personnel at the Weather Bureau Office in Chicago agreed that the
four sections are representative of the climatic areas around Lake
Michigan. As can be seen from Figure 1-2, the NW section is bounded by
the Mackinac Straits in the north and Sheboygan, Wisconsin in the
south; the SW section extends from Sheboygan to Gary, Indiana; the SE
section lies between Gary and Pentwater, Michigan; and the NE section
extends from Pentwater to the Mackinac Straits.
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SW
5ary, Indiana
Figure 1-2: Climatic Sections -- Lake Michigan
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11. METEOROLOGY
Data Requirements
The operation of the devices used to dissipate waste heat is
primarily a function of the weather. Therefore, an evaluation of
their feasibility requires an accurate set of meteorological data.
Significant variations in the design climatic factors with respect
to season and location must be accounted for.
The nature of the heat transfer phenomena which a particular
cooling device uses to dissipate heat to the atmosphere determines
the meteorological data requirements for the device. A compilation
of the heat transfer mechanisms and associated meteorological data
requirements for the alternative heat dissipation methods is given
in Table II-l.
In addition to the weather data requirements shown in Table II-l,
information on lake temperatures is needed to compare once-through
cooling systems with the alternative cooling systems.
Seasonal Considerations
Four seasons are selected to represent a full annual cycle:
Winter - December, January, February
Spring - March, April, May
Summer - June, July, August
Fall - September, October, November
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II-2
TABLE I1-1
METEOROLOGIC DATA REQUIREMENTS
Cooling Method
Heat Transfer
Mechanism
Meteorologic Data
Required
Evaporative Cooling Convection
Towers Evaporation
Dry-bulb Temperature
Relative Humidity*
Cooling Ponds
Radiation
Convection
Evaporation
Solar Radiation
Dry-Bulb Temperature
Relative Humidity*
Wind Speed
Cloud Cover
Spray Cooling
Canals
Evaporation
Convection
Dry-bulb Temperature
Relative Humidity*
Wind Speed
Dry Cooling
Towers
Convection
Dry-bulb Temperature
*Wet-bulb or dew point temperature can also be used.
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II-3
Meteorological Data Summary
Table II-2 presents a summary of average meteorological data
for each of the four seasons and geographical sections. The major
data source used to compile this table was the Climatic Atlas of
the United States (Reference II-7) prepared by ESSA in 1968. This
publication presents a wide variety of weather data on maps with
isolines for the specified meteorological parameter.
Data for the parameters shown in Table II-2 were obtained as
follows:
(1) Dry-bulb Air Temperature
Average monthly temperatures were compiled for each
of the four seasons for the four sections from maps
on pages 1-23 of the Atlas. These data are shown in
Table II-3.
(2) Relative Humidity
Average monthly relative humidities were compiled
from maps on pages 61 and 62 of the Atlas. While
seasonal variations were detected from these maps, it
was difficult to obtain enough detail to show
variations in relative humidity between the four sections
around Lake Michigan. These data are given in Table II-4.
(3) Wet-bulb Air Temperature
These data were calculated from the dry-bulb temperature
and the relative humidity using tables relating wet-bulb
depression (i.e., dry-bulb minus wet-bulb temperature)
versus relative humidity (Reference 11-15).
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TABLE II-3
AVERAGE MONTHLY DRY-BULB TEMPERATURES (°F)
(Reference 11-7)
II-5
Month
December
January
February
March
April
May
June
July
August
September
October
November
Season
Winter
Spring
Summer
Fall
Section
NW
24
20
20
21
30
42
55
42
63
69
68
67
61
50
36
49
SW
27
23
24
25
34
45
56
45
66
72
71
70
64
53
38
52
SE
30
26
25
27
35
46
56
46
67
72
71
70
64
52
40
52
NE
27
21
21
23
30
42
52
41
62
68
67
66
61
50
36
49
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II-6
TABLE II-4
AVERAGE MONTHLY WEATHER DATA
Month
December
January
February
March
April
May
June
July
August
September
October
November
Season
Winter
Spring
Summer
Fall
Relative
Humidity
(%)
80
80
80
80
70
70
70
70
70
70
70
70
75
75
75
75
Cloud
Cover
(1/10's)
8
8
7
8
7
6
6
6
6
5
5
5
6
6
8
7
Solar Radiation
(ly/day)
120
125
225
160
325
400
475
400
525
525
475
510
350
225
125
230
GPO a 197772
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II-7
(4) Cloud Cover
Maps on pages 71 and 72 of the Atlas were used to
obtain cloud cover data. As with relative humidity,
sectional variations were difficult to determine.
Table 11-4 contains the monthly and seasonal data,
(5) Mind Speed
The wind data were obtained from Asbury (Reference
II-l), where average monthly wind speeds from
Chicago, South Bend, Escanaba, Muskegon, Sault Ste.
Marie, Green Bay, and Milwaukee were compiled for
the years 1952, 1953, 1954, 1955, 1960, and 1962
and plotted in a curve showing wind speed versus
month for a complete annual cycle (Figure 7 of
Reference II-l).
(6) Solar Radiation
Data for mean daily solar radiation were obtained from
the Atlas using maps on pages 69 and 70 and are
presented in Table II-4. Again, variations between
the four sections were difficult to detect.
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II-8
Design Meteorological Data
While the weather information presented in Tables II-2, II-3,
and II-4 is useful in evaluating the performance of a particular
cooling device over a complete annual cycle, it is not appropriate
for designing the device. Cooling systems must be designed to
assure adequate performance under all conditions, not just under
"average" conditions. Therefore, one usually selects a set of design
data which represents a severe condition from the standpoint of
operating the cooling device.
Severe summertime weather conditions represent the "design" case
for thermal power plant cooling systems operating in the vicinity
of Lake Michigan. This is true for two reasons:
(1) The efficiency with which the cooling device
dissipates heat to the atmosphere is lowest
during the summer.
(2) The demand for electric power and hence the
requirement for full load operation of the
plant is highest during the summer for the
majority of electrical consumers in the area.
Table II-5 shows the design conditions selected for the four
sections.
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II-9
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11-10
The data in Table I1-5 were selected as follows:
(1) and (3) Dry- and Wet-bulb Temperatures
The Marley Company, one of the nation's largest manufacturers
of cooling towers, states in Cooling Tower Fundamentals and Application
Principles (Reference 11-14, page 8):
"Performance analyses have shown that most industrial
installations based upon wet-bulb temperatures which
are exceeded by no more than S% during a normal
summer have given satisfactory results. The hours
that the wet-bulb temperature exceeds the average
maximum by 5% need not be consecutive hours and
may occur in periods of relatively short duration."
On the basis of this recommendation, as well as others (Reference
11-13, page 157)^ wet- and dry-bulb temperatures not exceeded more
than 5 percent of the time during the months of June through September
were selected as design conditions. The Marley Company has tabulated
these data for a large number of U. S. and foreign cities (Reference
11-14) and Table II-6 gives these data for various locations around
Lake Michigan with averages for each of the four selected sections.
(4) Cloud Cover
Zero cloud cover was selected as the design condition to coincide
with the occurrence of maximum solar radiation.
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TABLE II-6
DESIGN DRY- AND WET-BULB TEMPERATURES (°F)
(Reference 11-14)
11-11
City
Oshkosh
Green Bay
Mariitowoc
Iron Mtn.
Marquette
Chicago
Milwaukee
Burlington
Aurora
Muskegon
Grand Rapids
Benton Harbor
Michigan City
Gary
Traverse City
Charlevoix
Manistee
Glen Arbor
State
Wisconsin
Wisconsin
Wisconsin
Michigan
Michigan
Illinois
Wisconsin
Wisconsin
Illinois
Michigan
Michigan
Michigan
Indiana
Indiana
Michigan
Michigan
Michigan
Michigan
Section
NW
NW
NW
NW
NW
Ave. NW
SW
SW
SW
SW
Ave. SW
SE
SE
SE
SE
SE
Ave. SE
NE
NE
NE
NE
Ave. NE
Dry- bulb
85
82
82
83
78
82
89
84
85
88
86
82
85
84
87
86
85
83
84
83
82
83
Wet-bulb
72
72
72
68
68
70
75
73
73
75
74
73
73
73
74
74
73
72
71
72
71
71
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11-12
(5) Wind
The selection of a design wind speed is made difficult by the
lack of data on the temporal distribution of wind velocity in the
Lake Michigan area. Available U. S. Weather Bureau data do not provide
adequate information of this type. Therefore, the average summer wind
speed data from Asbury (Reference II-l) is applicable as the design
case, since it does represent the wind condition concurrent with the
other design meteorological variables. Also, only cooling ponds have
wind speed as a major design variable, and the large retention time
in ponds makes the average wind speed an appropriate design variable.
(6) Solar Radiation
One of the most complete summaries of meteorological data for the
Lake Michigan region was prepared by Moses and Bogner from data collected
at the Argonne National Laboratory Weather Station (Reference 11-19).
This summary includes a complete compilation of solar radiation data for
September 1950 through December 1964. Figure 46 on page 244 of Moses
and Bogner (Reference 11-19) gives a percentile distribution of daily
total solar radiation. A value of 750 langleys/day represents the
June-July conditions at the 95 percent level (i.e., exceeded not more
than 5 percent of the time). Therefore, this value was selected as the
design condition.
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11-13
(7) Equilibrium Temperature
The equilibrium temperature of a body of water is reached when
the net exchange of energy at the water surface equals zero. In other
words, it is the temperature reached by a body of water exposed to a
given set of climatic conditions for an infinite period of time (i.e.,
until equilibrium is reached).
Column 7 of Table 11-5 shows the equilibrium temperature for each
geographical section for the design meteorological conditions in
Columns 1, 3, 4, 5, and 6. The computations were made using a computer
program (Reference 11-9) according to methodology described by Edinger
and Geyer (Reference II-8).
Theoretical Limitations of Cooling Devices
Each of the cooling devices discussed previously have theoretical
limits on their ability to cool water. These limits are as follows:
Wet Tower -- Wet-bulb temperature
Cooling Pond -- Equilibrium temperature
Spray Cooling Canal Wet-bulb temperature
Dry Tower -- Dry-bulb temperature
The data in Table II-5 can be used to determine the theoretical
lower limit of cooling for each device in each of the four geographical
sections. It should be emphasized, however, that engineering and
economic considerations require the outlet temperatures from the cooling
devices to exceed these theoretical lower limits.
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11-14
Lake Temperature^
Numerous publications (References II-1-6; 10-12; 16-18; 20-22)
contain information on the temperature of Lake Michigan. However, no
available compilation of data adequately describes the temporal distribu-
tion of temperatures in the nearshore areas where power plants would
obtain cooling water. Good sources of data for the nearshore zone are
municipal water intakes and existing power plant intakes. Table II-7
presents values for average water temperature determined from these
records for each of the four geographical sections.
The following sources were used to compute the data in Table II-7:
SW - Gary, Indiana and Milwaukee, Wisconsin water intakes;
average depth = 38 feet; average distance from shore =
6500 feet; time period: 1959-1969. These stations
are part of the National Water Quality Network; the
data are contained in FWQA's "STORET" Information
System.
SE - St. Joseph, Benton Harbor, Holland, Grand Rapids,
and Muskegon, Michigan water intakes; average depth =
40 feet; average distance from shore = 4500 feet.
These values were developed from Michigan Water
Resources Commission data for maximum, minimum,
and 90 percentile temperatures (Reference 11-16).
The SW region data and surface water data (References
11-4,10,16) were used as aids in establishing specific
values.
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11-15
TABLE II-7
AVERAGE LAKE TEMPERATURES (°F)
Month
December
January
February
March
April
May
June
July
August
September
October
November
Season
Winter
Spring
Summer
Fall
Section
NW
34
34
33
34
34
36
43
38
49
53
54
52
60
52
42
51
SW
39
35
34
36
36
41
46
41
51
55
56
54
61
55
47
54
SE
40
34
34
36
36
41
47
41
52
57
58
56
61
55
47
54
NE
35
34
34
34
35
37
44
39
50
54
55
53
60
53
44
52
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11-16
NE - Ludington and Big Rock, Michigan water intakes;
average depth = 30 feet; average distance from
shore = 2200 feet. These data were also developed
from Michigan Water Resources Commission data.
SW region data and surface water data were again
used as aids in establishing specific values.
NW - Escanaba, Michigan steam station water inlet
temperatures; shoreline intake. These data are
not very representative of the NW region, however,
data from the NE and SW regions were used to
establish values along with BT data (Reference 11-10).
It is a common rule of thumb that the Wisconsin
side of the lake is slightly cooler than the
Michigan side in summer and roughly the same at
other times.
In addition, a design lake water temperature is needed to size a
plant's once-through condenser system for comparison with the alternative
cooling systems. The above sources were used to establish temperatures
at the 95 percentile level. Averages of the 95 percentile values for
the three summer months are shown in Table II-8 and used as design
temperatures for the four geographical sections.
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11-17
TABLE II-8
DESIGN LAKE TEMPERATURES (°F)
(95 Percentile)
Month
June
July
August
NW
60
67
69
Section
SW
64
71
72
SE
65
72
73
NE
60
68
70
Summer 65 69 70 66
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11-18
It should be recognized that the temperatures In Tables II-7
and II-8 refer to points in the main body of the lake at about a mile
from shore and at depth. Surface and beach water tend to follow air
temperature more closely and display more daily and yearly variation;
similar remarks apply to Green Bay, Traverse Bay and the southern tip
of Lake Michigan. As an example, data from several municipal water
intakes between Chicago and Gary, Indiana indicate 95 percentile
temperatures as much as 4 degrees warmer than shown for the SW section
in Table II-8.
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11-19
References
11-1. Asbury, J. 6., Effects of Thermal Discharges on the Mass/
Energy Balance of Lake Michigan, Argonne National
Laboratory, Argonne, Illinois 60439. June 1970.
(unpublished)
II-2. Ayers, John C., The Climatology of Lake Michigan. Publication
No. 12, Great Lakes Research Division, The University
of Michigan. 1968.
II-3. Ayers, John C., "Great Lakes Water, Their Circulation and
Physical and Chemical Characteristics," Great Lakes
Basin. Publication No. 71 of the American Association
for the Advancement of Science. 1962.
II-4. Ayers, John C. and Joseph C. K. Huang, Benton Harbor Power
Plant Limnological Studies, Part I: General Studies,
November 1967.
II-5. Ayers, John C., et al., Currents and Water Masses of Lake
Michigan, Publication No. 3, Great Lakes Research
Institute, The University of Michigan. 1958.
II-6. Church, P. E., The Annual Temperature Cycle of Lake Michigan,
University of Chicago, Miscellaneous publications nos.
4 and 18. 1942 and 1945.
II-7. Commerce, U. S. Department of, Climatic Atlas of the United
States, Environmental Science Services Administration,
Environmental Data Service. June 1968.
II-8. Edinger, Dr. John E. and Dr. John C. Geyer, Heat Exchange in
the Environment. Cooling Water Studies for Edison
Electric Insitute, Research Project RP-49, The Johns
Hopkins University, Baltimore, Maryland. June 1, 1965.
II-9. Fuller, W. D., A Survey and Economic Analysis of Alternate
Methods for Cooling Condenser Discharge Water in Thermal
Power Plants: Phase II-Task I Report: System Selection,
Design, and Optimization, Dynatech Report No. 921,
Federal Water Quality Administration Contract No. 12-14-477,
1970.
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11-20
11-10. Interior, U. S. Department of, Lake Michigan BT Data from
1962 and 1963. Federal Water Quality Administration,
Lake Michigan Basin Office (unpublished).
11-11. Interior, U. S. Department of, Hater Quality Investigations -
Lake Michigan Basin - Lake Currents, Federal Water
Quality Administration, Chicago, Illinois. 1967.
11-12. Interior, U. S. Department of, Water Temperature Data From
FWQA Buoy Stations. 1962-64. Federal Water Quality
Administration, Great Lakes - Illinois River Basins
Project, (Summer data is unpublished).
11-13. McKelvey, K. K. and Maxey Brooke, The Industrial Cooling Tower,
Elsevier Publishing Company. 1959.
11-14. The Marley Company, Cooling Tower Fundamentals and Application
Principles, Kansas City, Missouri 64114.1967.
11-15. Marvin, C. F., Psychrometric Tables for Obtaining the Vapor
Pressure, Relative Humidity, and Temperature of the Dew
Point. U. S. Department of Commerce, Weather Bureau,
W. B. No. 235. 1941.
11-16. Michigan Water Resources Commission, Lake Michigan Water
Temperature Data (C. Fetterolf & D. Seeburger)
(unpublished). 1970.
11-17. Michigan Water Resources Commission, Public Hearing -- Recon-
sideration of Temperature Standards for Fish and Aquatic
Life. March 1970.
11-18. Mortimer, C. H., Frontiers in^Physical Limnology with Particular
Reference to Long Waves in Rotating Basins, "Internal
Waves and Associated Currents Observed in Lake Michigan
During the Summer of 1963," Publication No. 10, Great
Lakes Research Division, The University of Michigan. 1963.
11-19. Moses, Harry and Mary A. Bogner, Fifteen-Year C1imatolpgjcal
Summary -- January 1, 1950-December 31, 1964, Argonne
National Laboratory, Argonne, Illinois, September 1967.
11-20. Noble, Vincent E., Winter Temperature Structure of Lake
Michigan, Publication No. 13, Great Lakes Research Division,
The University of Michigan. 1965.
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11-21
11-21. Noble, Vincent E. and Robert F. Anderson,"Temperature and
Current in the Grand Haven, Michigan, Vicinity During
Thermal Bar Conditions," Proceedings of llth Conference
Great Lakes Research, Internat. Assoc. Great Lakes Res.,
pp. 470-479. 1968.
11-22. Noble, Vincent E. and John C. Wilkerson, "Airborne Temperature
Surveys of Lake Michigan, October 1966 and 1967,"
Limnology and Oceanography, Volume 15, Number 2.
March 1970.
GPO 8197773
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Ill ECONOMIC CONSIDERATIONS
General Cost Factors
The cost of power generation, i.e. the busbar cost, is expressed
in Mills/KWH and is usually broken down into fixed and variable
cost components. Fixed charges are those which are unaffected by
plant output and include interest on money, amortization of the
plant capital cost, interim replacements, insurance, and taxes.
Although income taxes vary somewhat with plant use, they are usually
included in fixed charges because they are reasonably predictable
and the courts have held that the return which a utility is entitled
to earn must be computed after allowance for such taxes (Reference
III-4). The annual fixed charge rate is expressed as a percentage
of plant capital cost. It is the sum of the charges alloted to
each contributing item noted above. In determining the fixed cost
contribution to total busbar cost, the annual cost is calculated
in dollars and then converted to Mills/KWH in accordance with plant
operation time.
Variable costs, also called operating costs or production
costs, are those associated with the amount of generation and
include fuel, payroll labor, and other operating and maintenance
expenses. Each of these items is expressed in terms of Mills/KWH.
Both fixed and variable costs are influenced by the heat dissipa-
tion system of a plant. The opposite is also true, because general
cost factors play a major roll in the optimal design of a plant-
cooling system combination. Hence, it is important to establish
economic criteria in the early stages of this itudy.
-------
III-2
The sum of charges noted above make up the busbar cost of
power from a given plant without regard to its location. For an
overall optimization of power costs at the load center in a large
system, the location of a new plant must also be assessed in
terms of transmission and distribution costs. These costs may
outweigh additional costs involved in off-stream cooling devices.
Battelle Northwest (Reference III-2) cites a cost of about 0.3 Mills/
KWH per 100 miles of transmission. This figure is substantiated by
the analysis of Hauser (Reference III-6) who concludes that the
additional cost of wet cooling towers, about 0.2 Mills/KWH, is
equivalent to a transmission distance of about 80 miles. In a
discussion of evaporative cooling systems related to costs of
nuclear plants at numerous locations throughout the United States,
Kempf and Fletcher (Reference III-7) state that "...the use of a
costlier evaporative system at a site situated favorably with
respect to load centers may be economically preferable to the
transmission of power from sites which can use once-through cooling
but are remote from load centers."
Study Approach
The economic analysis is directed toward the effect of cooling
system choice on the total busbar cost of generating power. An
economic life of 30 years is assumed for all plants and systems
considered.
-------
III-3
Initially, an attempt was made to determine the representative
capital and operating costs for the "Typical" 1000 MW fossil fuel
plant which could be studied at a number of general sites around
Lake Michigan. Such a single plant approach was found to be
unreasonable because of the wide variation in capital costs and
operating costs, including fuel, for existing plants adjacent to
the Lake. Federal Power Commission data (Reference III-5) for
ten such plants built since 1960 reflect capital costs ranging from
$105 to $186/KW. For the same plants, operating costs (i.e., fuel,
operation and maintenance)ranged from 2.20 to 3.53*Mills/KWH. Such
variations of over 60 percent indicate the potential inaccuracy
in assuming a single set of cost values to be representative
throughout the study area. This is particularly true when assessing
additional costs of alternative cooling systems since the busbar
cost increase for alternative systems, other than dry cooling, will
be less than 5% (Reference III-6).
In order to provide a meaningful Interpretation of plant
economics for a number of sets of cost factors, three rate values are
used for each cost component which might vary from one situation to
another. Values were grouped in "Low", "Normal," and "High" sets in
an attempt to bracket cost conditions which will be encountered
within the study area (Table III-l). The combination of factors called
"Normal", Case II, is the most representative of an overall average
of current costs; the "Low" and "High" combinations, Cases I and III,
respectively, are included to represent reasonable extremes.
* Information as of 1968.
-------
III-4
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III-S
Four additional sets of cost factors were used to show the
effect of variation in individual factors as opposed to the
combined effect of changing all factors from case to case. (See Table
III-l, Cases IV-VII). In these cases, the "Normal" level of cost
factors was used as a base except that one value from the "High"
level was substituted in each of the four cases.
Information on cost components was obtained from numerous
surveys, indexes and general references. Table 111-2 presents
sources and cost data by component category.
With this background, we can compute the basic plant cost for
the seven combinations of economic factors cited in Table III-l.
This information is presented in Table III-3 which gives the capital
cost in dollars per KW and busbar cost in Mills per KWH. The busbar
cost was calculated by summing up a constant operation and maintenance
cost of .75 Mills/KWH with the fuel and fixed charge costs.
Differences in busbar costs between Cases I, II and III are
brought about by changes in all of the first three cost factors (land
costs are included for cooling pond analysis only -- the cost of land
for the plant itself is included in the plant capital cost). As shown
in Table III-4, Cases IV-VI are used to determine the busbar cost
differences due to changes in individual cost factors. These data
provide the basis for a later comparison of the added cost of specific
cooling systems to other economic factors influencing generation cost.
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-------
III-8
TABLE II1-4
INFLUENCE OF INDIVIDUAL COST FACTORS ON BUSBAR COST
Cost Factor Item
Case No.
Difference from
Case II (Normal)
Resulting Change in
Busbar Cost, Mills/KWH
Plant Capital Cost IV $25/KW 0.49
Fixed Charge Rate V 3% 0.57
Fuel Cost VI 5C7106 Btu 0.43
-------
References m~9
III-l. Anon. "16th Steam Station Cost Survey." Electrical
World. 172 (18): 41-56. 1969.
II1-2. Battelle - Northwest. Nuclear Power Plant Siting in the
f-
Ac
Pacific Northwest for the Bonneville Power Administration
Contract No. 14-03-67868.Battelle Memorial Institute,
Richland, Washington. 1967.
III-3. Edison Electric Institute. Statistical Year Book of the
Electric Utility Industry for 1968. Number 3T;
Publication No. 69-48. EEI, New York. 1969.
II1-4. Federal Power Commission. National Power Survey.
U. S. Government Printing Office. 1964.
II1-5. Federal Power Commission. Steam-Electric Plant Construction
Cost and Annual Production Expenses"! U. S. Government
Printing Office.1968.
III-6, Hauser. L. G. "Cooling Water Sources for Power Generation."
ASCE National Water Resources Engineering Meeting,
January 26-30, Memphis, Tennessee. Meeting Reprint
1102. 1970.
III-7. Kempf, F. J. and J. F. Fletcher. Effects of Site Location
on the Capital Costs of Nuclear Electric Plants. BWL-
960 UC-80, Reactor Technology.(Battelle Memorial
Institute, Richland, Washington.) 1969.
III-8. National Coal Association. Steam-Electric Plant Factors.
1969 Edition. Washington, D. C.1969.
III-9. R. W. Beck and Associates. Personal communication. 1970.
111-10. Short, H. C. "Nuclear Power Buildup Goes Critical."
Chemical Week. 102 (21): 43-61. 1968.
III-ll. Swengel, F. M. "A New Era of Power Supply Economics."
Power Engineering, pp. 30-38. March, 1970.
111-12. U. S. Department of Commerce. U.S. Census of Agriculture.
Volume I. U. S. Government Printing Office.1964.
111-13. West Central Region Advisory Committee. West Central Region
Power Survey 1970-1990. A Report to the Federal Power
Commission.
-------
IV. ENGINEERING CONSIDERATIONS
Introduction
The initial requirements for approximating the size and performance
of alternative cooling systems are the design meteorological and lake
temperature data for the four geographical sections (Tables II-5 and
8). Based on these data and generalized cost estimates for system
components and operation, component sizes and performance characteristics
are determined via digital computer programs.
The procedure for designing each cooling device varied according
to the sources of the computer programs. A computer program developed
by the Dynatech Corporation was used as a primary means for analyzing
wet cooling towers, cooling ponds and once-through systems (Reference
IV-5). The Ceramic Cooling Tower Company provided computer runs for
the design of power spray modules for cooling canal systems (Reference
IV-2). Advanced design and cost data on mechanical and natural draft
dry (Heller) cooling systems were obtained from R. W. Beck and
Associates (Reference IV-9).
-------
IV-2
The Dynatech and R. W. Beck computer programs are the results of
FWQA research contract efforts. Back-up data from in-house sources
were provided on natural draft wet towers and cooling ponds. Supple-
mentary cost data on wet towers were obtained from The Marley Company
(Reference IV-3) and Research-Cottrell, Inc. (Reference IV-10).
Dynatech's program also had some design data on dry systems. Cross-
referencing and spot checks between Dynatech, R. W. Beck and in-house
calculations were made to assure consistency and reasonable agreement
of the results despite the varied approaches used in system design.
Descriptions of the analytical techniques used in calculating the
sizes and performance of the cooling devices are not presented in this
report. The reader is urged to consult appropriate references on the
subject (References IV-1, 4-5, 7-8, 12).
General Optimization Procedure
All cooling systems perform most effectively at elevated water
temperatures. Reduced pumping and fan power, shorter tower packing,
and smaller pond surface areas can be achieved by increasing the inlet
water temperature to the cooling system. The same temperature increase,
however, adversely affects the efficiency of the power plant as it results
in condensing the steam at a higher turbine backpressure, and thus in-
creases the turbine heat rate. An economic optimization therefore
involves the analysis of the two competing factors for the selection of
the condensing steam temperature.
-------
IV-3
Another important factor in determining the size and cost of a
cooling system (i.e., cooling device and condenser) is the approach
temperature. For a wet cooling tower and spray canal, the approach
is equal to the difference between the cold water temperature and the
ambient wet-bulb temperature. The approach temperature for a cooling
pond is equal to the difference between the outlet cold water temperature
and the equilibrium pond temperature; and for a dry tower, it is equal
to the difference between the outlet water and dry-bulb temperatures.
The smaller the approach, the larger the cooling device's heat exchange
surface and consequently the cost. The magnitude of the approach tem-
perature also affects the operation of the power generation system. The
smaller the approach, the more efficient the power generation because
of the lower sink temperature.
Dynatech Program
In designing a particular cooling system, Dynatech's computer
program (Reference IV-5) optimizes with respect to both the approach
and the condenser temperature. The calculations start with a minimum
allowable condenser temperature. System costs are then calculated for
all allowable approaches in increments of 1°F. This process is
repeated for all allowable condenser temperatures, increasing the latter
in each trial by 1°F. In this manner, the costs for all combinations
of approach and condenser temperatures are calculated. The minimum
cost that is found in this process gives rise to the "optimum" com-
bination of approach and condenser temperatures for the design meteoro-
logical conditions.
-------
IV-4
In addition to size and performance data, the computer program
provides capital system cost and total operating cost for the design
conditions. An adjusted total operating cost estimate based on the
off-design ambient meteorologic data (i.e., annual operation) and
various plant capacities is also given. All seven combinations of
economic factors presented in Table III-l were used in the analysis
for this report.
Dynatech's computer program has two options for specifying the
plant capacity factor. One is a straight 100 percent capacity factor
implying full-load year-round operation of the plant, and the other
is a variable capacity operation over an annual cycle. The latter
option was used here with an average yearly capacity factor of 82%.
The selected capacity distribution throughout an annual cycle is as
follows:
Capacity 1.00 .80 .60 .25 0
Hours/year 5150 1750 800 700 360
These data are needed for determining the yearly operating cost
of the selected cooling system.
-------
IV-5
Another important system cost factor is the turbine heat rate
and its variation with capacity factor and the condenser operating
temperature. Data for a typical 6E turbine of a 1000 MW capacity were
used with the Dynatech program. Turbine heat rates at several
capacity factors were obtained from the manufacturer's heat rate
tables (Reference IV-6). At 1" Hg turbine backpressure and a capacity
factor of 100 percent, the turbine heat rate is 7415 Btu/KWH; at
25 percent capacity it is 8807 Btu/KWH. (Note that the above are
heat rates for a specific turbine and should not be equated to an
overall plant heat rate). The Dynatech program has an interpolating
routine that evaluates the heat rate at the plant capacity factor for
the baseline design conditions*. Other heat rates are needed for the
off-design* operating conditions, since it is necessary to calculate
the total heat rejected at various capacities. From the heat rejection
data and the percent of time the plant operates at off-design conditions,
an estimate of the cooling system operating cost and the associated
fuel savings can be made.
The off-design spring, summer, fall, and winter conditions were
matched with the power plant capacity to allow maximum plant output
during the summer and winter peaks. Table IV-1 shows the percent of
time the cooling systems operate for various plant capacities.
*The baseline design weather conditions and lake temperatures are
given in Tables II-5 & II-8, respectively. Off-design conditions are
given in Tables II-2 and II-7.
-------
IV-6
TABLE IV-1
PERCENT OF COOLING SYSTEMS TIME AT OFF-DESIGN CONDITIONS
Plant
Capacity, %
TOO
80
60
25
0
Spring
10
15
35
40
0
Summer
40
35
15
10
0
Fall
10
15
35
40
100
Winter
40
35
15
10
0
These data are used in conjunction with the seasonal weather data
(Tables II-2 and II-7) to compute annual operating costs for the chosen
cooling system. The effect of more favorable off-design weather con-
ditions gives average operating costs (in Mills/KWH) substantially
lower than the operating costs under design conditions.
GPO 819777-4
-------
IV-7
In the course of the present studies, it was found that during
extremely cold winter conditions, the cooling system did not receive
adequate heat to prevent it from freezing. In practice, the flow rate
can be changed to prevent this, or, in the case of cooling towers, ice
rings for natural draft or fan reversal for mechanical draft towers can
be used. It may even be advantageous to burn more fuel and generate
greater quantities of electric power. No such provisions were made in
Dynatech's program. For this reason, the cost data based on the variable
ambient conditions may be too high. The 5 percent summer design data
imposed severe operating conditions for tower design with the result
that the cooling systems were "too good" during the winter off-design
conditions.
For mechanical draft wet tower cooling systems the capital cost
data developed by the Dynatech program agrees reasonably with 1970
published and unpublished information available from The Marley Company
(Reference IV-3) and Fluor Corporation (Reference IV-11), two major
tower manufacturers in the United States.
The total system cost for the natural draft towers presented in
the following section of this report may not be minimal. Research-
Cottrell (Reference IV-10) supplied current capital cost data, which
checked favorably with that published by The Marley Company (Reference
IV-3). However, this capital cost, which was inserted into the program,
is based on a tower height of 500 feet and a tower diameter of 400 feet.
-------
IV-8
Thus, the optimization process became somewhat artificial. In par-
ticular, the approach temperature had to be fixed so that the tower
size would be appropriate for the capital cost provided by Research-
Cottrell. Hence, the operating cost portion of the total system cost
may be inflated.
In determining the capital cost of a cooling pond, the Dynatech
program simply multiplies the pond size (acres) by the land cost ($/acre)
Thus, no land preparation or construction costs are included.
Ceramic Cooling Tower Program*
For this study, design data for spray cooling canals using Power
Spray Modules (PSM) were supplied by the Ceramic Cooling Tower Company*.
The output from the Ceramic program includes the number of Power Spray
Modules, the minimum canal dimensions, and module cost.
As a part of the input data required for Ceramic Cooling Tower's
computer program, the heat load, the water flow, the cooling range,
and the outlet water temperature are all specified. These data were
obtained from a cooling pond cooling system designed by the Dynatech
program. Additional input data requirements include dry- and wet-bulb
temperature, wind velocity, and barometric pressure.
*The use of this program does not imply endorsement of the product by
FWQA.
-------
IV-9
Other assumptions for complete cost evaluation of spray canals
follow:
1. The condenser system cost was obtained as calculated from
the Dynatech cooling pond system optimization.
2. The capital cost of the cooling canal system includes 15
percent of the material cost for installation and electrical work.
The cost of the land and canal preparation was assumed at 12 percent
of the material cost. The land cost was less than 1 percent, a very
small cost item compared to cooling ponds.
3. The operating cost was based on the baseline design conditions
with adjustments made for cooler temperatures. An adjustment factor
of 0.62 was calculated based on the number of units in operation during
spring, summer, and fall conditions. A maintenance cost equal to 1
percent of the operating cost was added, consistent with Dynatech's
calculations.
4. The sum of the condenser system cost, the amortized capital
cost and 0 & M cost made up the total system cost. No differential
fuel cost was included, because it was assumed that the differential
heat rate of a plant with a PSM system could be minimized by operating
adequate number of units as the ambient conditions change.
-------
IV-10
R. W. Beck Program
R. W. Beck's computer program optimizes the dry system based on
four major cost items -- capital cost, auxiliary power cost, cost due
to loss of capacity, and fuel cost. Parametric study of all cost items
are considered for initial temperature differences (ITD) between the
inlet dry-bulb air and the inlet hot water temperatures ranging from
30°F to 80°F. At large initial temperature differences, the cooling
system is highly efficient and thus compact and relatively inexpensive.
The auxiliary power requirements are also relatively small. On the
other hand, the loss of power and the resulting fuel cost are great.
Thus, the last two cost items compete for the low ITD while the first
two compete for the high ITD. The optimal ITD for a given region is
consequently dictated by the combined effects of all cost factors.
R. W. Beck's program was run for four sites around Lake Michigan
in order to show the effects of weather variations. These sites were
Chicago, Green Bay, Milwaukee, and Grand Rapids. A total of 7500 hours
per year of operation was assumed. One-half of this time was at 100
percent capacity and the other half at 75 percent capacity. The
remaining 1260 hours per year were for shutdown.
-------
IV-11
The fuel cost and the fixed charge rates from Table III-l were
used. Whenever there occurred a loss of capacity of 10 hours per
year or more at full throttle, gas turbine peaking units were used to
make up for this loss. The loss of capacity at full throttle is due
to high backpressure that may occur at peak demands. The cost of gas
turbine peaking unit was assumed at $100/KW.
Both natural and mechanical draft dry towers were considered for
all regions. The optimum tower dimensions and all cost items were
output from the program.
-------
IV-12
References
IV-1. Carey, John H., John T. Ganley, and John S. Maulbetsch. A
Survey and Economic Analysis of Alternate Methods for
Cooling Condenser Discharge Hater in Thermal Power
Plants, Task I Report: Survey of Large-Seale Heat
Rejection Equipment. Prepared for the Federal Water
Pollution Control Administration. July 21, 1969.
IV-2. Ceramic Cooling Tower Company. Personal Communication. 1970.
IV-3. Dickey, Joe Ben and Robert E. Kates. "Thermal Pollution and
the Water Cooling Tower." Presented April 2, 1970 in
San Francisco at the meeting of the National Pollution
Control Conference and Exposition.
IV-4. Edinger, Dr. John E. and Dr. John C. Geyer. Heat Exchange In
the Environment. Cooling Water Studies for Edison
Electric Institute, Research Project RP-49, The Johns
Hopkins University, Baltimore, Maryland. June 1, 1965.
IV-5. Fuller, W. D. A Survey and Economic Analysis of Alternate
Methods for Cooling Condenser Discharge Water in Thermal
Power Plants, Phase II-Task I Report: System Selection.
Design, and Optimization. Dynatech Report No. 921,
Prepared for the Federal Water Quality Administration.
July 8, 1970.
IV-6. General Electric. Heat Rates for General Electric Steam
Turbine-Generators...100.OOP KW and Larger. GET-2050B.
(No date).
IV-7. McKelvey, K. K. and Maxey Brooke. The Industrial Cooling
Tower. Elsevier Publishing Company. 1959.
IV-8. The Marley Company. Cooling Tower Fundamentals and Application
Principles. Kansas City, Missouri 64114. 1967.
IV-9. R. W. Beck & Associates. Personal Communication. 1970.
IV-10. Research-Cottrell, Inc. Personal Communication. 1970.
IV-11. Weis, Edward. Fluor Products Co., Inc. "Tower Selection."
Industrial Water Engineering. Volume 7, Number 5,
pp. 25-29. May 1970.
-------
IV-13
IV-12. Winiarski, Lawrence D., et al. A Method for Predicting the
Performance of Natural Draft Cooling Towers. U. S.
Department of the Interior, Federal Water Pollution
Control Administration, Con/all is, Oregon. January 1970.
-------
V. RESULTS
Performance data for the various alternative cooling systems
are presented in Section A below. Cooling system cost includes
the cost of condenser, pumps, piping, and controls, as well as the
specified heat dissipation device. Comparative capital and busbar
costs for the complete power plant using these alternative cooling
systems are examined in Section B.
A. Cooling Systems
Introduction
For each cooling system, engineering performance data and
capital and total system cost data are presented in tabular form.
Since most of the data are self-explanatory, only limited descriptions
of the tables are given.
Wet Cooling Towers
Performance Data
Mechanical Draft
A complete set of performance data for the mechanical
draft wet cooling tower operating under design conditions is given
in Table V-l for each case and for the four sections of the Lake
Michigan area. There appears to be little sectional variation.
All temperature values are rounded to within one
degree. For this reason, one cannot expect to exactly recalculate
the heat rejected by multiplying the range by the condenser flow.
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V-4
Natural Draft
Table V-2 presents the performance data for wet
natural draft towers operating under design conditions. Little
variation between the four geographical sections was found, so
the data are averaged over ail! sections.
System Cost
Mechanical Draft
Table V-3 presents the total capital cost and average
cooling system cost rate for the wet mechanical draft towers
described in Table V-l.
Natural Draft
Table V-4 presents the total capital cost and average
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described in Table V-2. As mentioned previously, a tower capital
cost of $6.50/KW is assumed for all cases. It should be specifically
noted again that fixing the approach on the one hand and the tower
cost on the other hand severely limits the cost optimization process.
Thus, the total cooling system operating cost given is probably not
minimal. This point is particularly stressed here for the comparison
with the smaller costs for wet mechanical tower cooling systems.
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V-8
TABLE Y-4
COST DATA FOR NATURAL DRAFT
COOLING TOWER SYSTEMS
Case*
I
II
III
IV
V
VI
VII
Condenser & Pump
Capital Cost,$/KW
5.40
5.31
5.21
5.21
5.14
5.40
5.30
Total System Capital
Cost, $/KW
11.90
11.81
11.71
11.71
11.64
11.90
11.80
Total System Cost
Mills/KWH
0.241
0.306
0.373
0.310
0.358
0.314
0.306
* See Table III-l
GPO 818-777-5
-------
V-9
Cooling Ponds
Only flow-through ponds are examined in detail. Mixed pond
sizes were not determined, however it is estimated that with
proper selection, their areas would be about two to three times
greater than the flow through ponds.
Performance Data
Flow-through cooling pond sizes and other parameters
vary little from one section of the lake to another because of
the small variations in the design ambient conditions. For example,
there is less than 4 percent variation among the sizes in the four
sections corresponding to Case I. Therefore, Table V-5 presents
the average performance data for the four geographical sections.
Optimum pond size is strongly influenced by the land cost as indicated
in Table V-5. It varies from 2030 acres for a land cost of $500
per acre in Case II to 1490 acres for a land cost of $1000 per acre
in Case VII.
System Cost
Table V-6 gives the total capital and average cooling
system cost rates for flow-through cooling ponds. Variations in the
cost of the cooling system between the four geographical sections
are also shown.
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V-13
Spray Cooling Canals
Performance Data
Performance data for spray cooling canals using Ceramic
Cooling Tower Company's Power Spray Module are given in Table V-7.
The input data were selected from the cooling pond design information
given in Table V-5. As indicated in Table V-7, the PSM's are
arranged in rows of four units across the canal, with from 28 to 32
rows spread along the canal's length. Thus, water flowing down the
canal will be cooled as it passes through consecutive rows of PSM
units.
System Cost
The average total material cost for the spray cooling
canals described in Table V-7 is $1.83/KW. Further additional costs,
as described previously in Section IV - "Engineering Considerations" -
increase the total capital cost (exclusive of condenser system) to
$2.30/KW. Table V-8 presents the spray cooling canal cost data.
Dry Cooling Towers (Heller System)
Performance Data
The optimal initial temperature difference (ITD)
for all sites examined ranged from 57 to 62°F. For these ITD's,
the optimal water cooling range is on the order of 50 percent of the
corresponding ITD.
-------
V-14
TABLE V-7
SPRAY COOLING CANAL PERFORMANCE DATA AT DESIGN CONDITIONS
Section
Parameter
Approach, °F
Range, °F
Cold Water Temp., °F
Condenser Flow, cfs
Heat rejected, 109 Btu/hr
Total number of PSM-4-10-75
Number of units per row
Number of rows
Total Horsepower
Minimum channel width, ft.
Minimum channel length, ft.
NW
20
20
90
960
4.3
112
4
28
8400
160
4480
SW
16
20
90
960
4.3
128
4
32
9600
160
5120
SE
17
20
90
960
4.3
124
4
31
9300
160
4960
NE
19
20
90
960
4.3
116
4
29
8700
160
4640
-------
V-15
TABLE V-8
COST DATA FOR SPRAY CANAL COOLING SYSTEMS
Case*
I
II
III
IV
V
VI
VII
Condenser & Pump
$/KW
6.09
5.88
5.87
5.88
5.72
6.Q2
5.95
Spray Canal
$/KW
2.30
2.30
2.30
2.30
2.30
2.30
2.30
Total Capital
Cost, $/KW
8.39
8.18
8.17
8.18
8.02
8.32
8.25
Total System
Cost, Mills/KWH
0.148
0.185
0.225
0.185
0.216
0.189
0.185
* See Table III-l
-------
V-16
The land requirement for a mechanical draft tower
at ITD = 57°F is 8.7 acres and at ITD = 62°F is 7.8 acres.
The size of a natural draft tower varies with the
initial temperature difference, being smaller when the ITD is
large. The height, base diameter, and the top diameter date at
the two extreme ITD's are listed in Table V-9 below:
TABLE V-9
DIMENSIONS OF NATURAL DRAFT COOLING TOWER IN FEET
Dimension ITD = 57°F ITD = 62°F
Height
Base diameter
Top diameter
487
593
398
455
547
383
Cooling System Cost
Capital Cost
The range of capital cost for a mechanical draft dry
cooling tower system for Chicago is listed below:
ITD °F 58-59
Cost without peaking, $/KW 16.8 - 17. 1
Cost with peaking, $/KW 24.0 - 24. 1
-------
V-17
The capital cost of a natural draft dry tower depends
on the size of the tower. Additional cost for peaking units is
included whenever a substantial loss in capacity occurs. Gas turbine
peaking units were chosen at an assumed cost of $100/KW. The total
capital cost is the sum of these two items. The range of capital costs
of natural draft cooling towers for the sites examined are listed in
Table V-10 as a function of optimal ITD's.
TABLE V-10
COOLING SYSTEM CAPITAL COST ($/KW) OF NATURAL DRAFT
DRY COOLING TOWER
Site ITD °F Cost without Peaking ($/KW) Cost with Peaking ($/KW)
Chicago 57-58
Grand Rapids 57-58
Milwaukee 58
Green Bay 58-62
18.8 - 19.1
18.8 - 18.4
19.7
18.5 - 19.7
25.8
25.1
26
25.4
- 25.8
- 25.2
.8
- 25.5
System Cost
The total cost of the cooling system with mechanical
draft dry cooling towers for the four sites examined are listed in
Table V-ll.
-------
V-18
TABLE V-ll
TOTAL SYSTEM COST DATA FOR MECHANICAL
DRAFT DRY COOLING TOWER SYSTEMS (MILLS/KWH)
Case*
I
II
III
IV
V
VI
VII
Chicago
Q.57
0.72
0.87
0.72
0.85
0.74
0.72
Green Bay
0.55
0.69
0.82
0.69
0.82
0.70
0.69
Milwaukee
0.58
0.72
0.87
0.72
0.84
0.74
0.72
Grand Rapids
0.55
0.69
0.82
0.69
0.81
0.70
0.69
Average
Q.56
0.71
0.85
0.71
0.83
0.72
0.71
* See Table III-l
-------
V-19
The total costs of the cooling system with natural
draft dry cooling towers for the four sites examined are listed in
Table V-12.
TABLE V-12
TOTAL SYSTEM COST DATA FOR NATURAL
DRAFT DRY COOLING TOWER SYSTEMS (MILLS/KWH)
Case *
I
II
III
IV
V
VI
VII
Chicago
0.54
0.67
0.80
0.67
0.79
0.68
0.67
Green Bay
0.52
0.64
0.77
0.64
0.76
0.65
0.64
Milwaukee
0.54
0.68
0.82
0.68
0.81
0.69
0.68
Grand Rapids
0.51
0.64
0.77
0.64
0.76
0.65
0.64
Average
0.53
0.66
0.79
0.66
0.78
0.67
0.66
* See Table III-l
-------
V-20
B. Economics of Cooling Systems and Total Plants
Total costs are presented which account for all
components included in each cooling system. For the sake of comparing
costs of alternate cooling systems, however, the cost in excess
of the minimum requirement is most meaningful. The minimum cooling
system requirement for this analysis is the once-through cooling
system described earlier in Section III. Table V-13 shows the
cost differential in capital cost ($/KW) and busbar cost (Mills/
KWH) for the cooling systems designed for the various economic
conditions defined by Cases I through VII.
The effect of cooling system choice on the total
cost of producing power is shown in Table V-14 which summarizes
total busbar costs for all plant-cooling system combinations studied.
The busbar costs in Table V-34 include all fixed and variable cost
components which are involved in the cost of the basic plant with
once-through cooling, Table III-3, and the differential cooling
system costs, Table V-13.
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-------
VI. ENVIRONMENTAL EFFECTS OF COOLING DEVICES
Introduction
The areas of environmental concern associated with heat dissipation
methods can be separated into four general categories:
1) Fog potential
2) Consumptive water loss by evaporation
3) Drift
4) Slowdown
A fifth category, "Effect on Local Weather," can also be con-
sidered, but this effect is closely related to number 1 above.
In terms of the alternative methods of heat dissipation discussed
in this report, the above concerns may be associated with specific
cooling devices as shown in Table VI-1.
It is apparent from Table VI-1 that dry cooling devices should have
no adverse affect on the environment. In fact, it has been suggested by
Stewart (Reference VI-23) that the heat from dry towers could be used
beneficially to dissipate fog at airports.
-------
TABLE VI-1
ENVIRONMENTAL EFFECTS OF COOLING DEVICES
VI-2
Cool ing Method
Environmental Effects
Potential Fog Evaporation Slowdown Drift
Wet Towers
Yes
Yes
Yes
Yes
Ponds
Yes
Yes
No
No
Spray Canals
Yes
Yes
Yes
Yes
Dry Towers
No
No
No
No
Fog Potential
Definition of the Problem
Essentially, fog is a cloud at ground level and can be described
as a collection of very small liquid water droplets (e.g., <50 micron
diameter) suspended in the air. Fog exists only when the air is
saturated with water vapor. Since cold air becomes saturated at a
much lower water content than warm air, cold climates present a greater
potential for fog. Thus, one need not worry about fog formation except
under climatic conditions of high humidity and low temperature.
GPO 8197776
-------
VI-3
Wet cooling devices discharge water vapor to the atmosphere as a
direct result of their primary heat exchange mechanism - evaporation.
Under normal circumstances, this discharge of moisture-laden air is
dissipated rapidly in the ambient air. However, under severe climatic
conditions (i.e., high humidity and low temperature) the moisture could
produce a fog condition if the moisture were trapped in the lower levels
of the atmosphere, such as during a period of high atmospheric stability
(i .e., an inversion).
Cooling towers do produce visible plumes. However, plumes are not
a problem unless they reach the ground, thus causing fog. In fact, only
when the fog occurs over inhabited areas would it be considered a problem.
Special concern should be directed towards a fog which may cause obstruc-
tion of vision on highways or near airports. Downwash of the plume from
an oil refinery's mechanical draft cooling tower caused such a problem
on an adjacent highway during the winter of 1959 (Reference VI-11, see
paper by Hall). The problem was solved by installing heaters in the tower
stack, thus increasing the ability of the air to hold water vapor and
prevent saturation conditions. This technique is described by Buss
(Reference VI-5). Such problems should normally be prevented by siting
a cooling tower as far from highways and airports as possible. Also, the
tower should be located so it is downwind from the point of interest
during periods of low temperature and high humidity.
Under normal conditions, cooling tower plumes rise due to their
initial velocity and buoyancy and rarely intersect the ground before they
are dissipated. The plumes also have the ability to penetrate through
-------
VI-4
an inversion. Visual observations at the Keystone Plant near Shelocta,
Pennsylvania, indicate that even under conditions of severe local ground
fog, the plumes from the plant's cooling towers penetrated through the
ground fog and were dissipated in the upper air.
Several publications are available (References VI-2-5, 11, 14, 20,
23, and 24) which deal with the fog potential of wet cooling towers.
While it is generally agreed that cooling towers are potential fog
producers, it is also generally agreed that they are not probable fog
producers. Most authorities agree that low profile mechanical draft
towers are more likely to produce a fog condition than tall, natural
draft towers. However, at least one source (Reference VI-14) indicates
that the initial height of the vapor emission is not important, but
rather the concentration of the heat and water vapor in a single point
(i.e., natural draft tower) rather than in a line source (i.e.,
mechanical draft towers) tends to provide greater opportunity for the
plume to rise.
Very little information is available on the fog potential of
cooling ponds. Decker (Reference VI-11) contends that "Pond cooling
should provide the greatest change of fog formation at the surface,"
however, experience to date (Reference VI-20) indicates that this cold
weather "steam fog" stays over the surface of the pond and does not
create local fog problems. Winter icing can occur near the edges of
the pond. Actually, one would not expect the fog conditions over a
cooling pond to differ much from those over a once-through discharge
area of a lake or river.
-------
VI-5
Environmental Studies
At least two reports (References VI-4 and 20) deal with site
visits to large U. S. power plants which utilize wet towers. One
report was prepared by a utility (Reference VI-4), the other by State
and Federal pollution control agencies (Reference VI-20). Both study
teams visited plants in the coal mining region of the Appalachian
Mountains, i.e., Keystone, Fort Martin, Big Sandy, and Clinch River.
The pollution control agency team also visited the Mt. Storm plant
which uses a cooling pond. The general conclusions of both reports
are the same -- fog from the towers (and pond) was not considered a
problem by the plant operators or by the local residents. A similar
study conducted in Europe resulted in the same conclusion (Reference
VI-11).
Of course, visits to sites and discussions with plant personnel
can only give qualitative information as to the fog potential of
cooling towers. A rigorous, scientific investigation is needed to
provide firmer evidence. Such a study is being conducted at the
Keystone plant by IIT Research Institute. The study's principal
investigator, Dr. Eric Ansley, reports in a recent issue of Electrical
World (Reference VI-2):
"There is some apprehension today that cooling-
tower emissions may produce undesirable environmental
effects. Inadvertent weather effects, including
local fogging and Icing, cloud formation, and
increased precipitation, are often cited as pos-
sibilities. Initial results from ground and
aerial studies being conducted by IIT Research
Institute of Chicago at the Keystone Generating
Station indicate that no immediate problems appear
to exist."
-------
VI-6
Thus, it appears that much of the talk about fog from cooling towers
is not based upon what actually happens with existing installations..
Of course, the fact that major problems have not yet come to light
should not make us complacent as to the potential problem. Decker
(Reference VI-11) concludes "...that except for extremely poorly-
located cooling towers, the operators should encounter very little, if
any, liability because of nuisance to neighbors." Therefore, detailed
meteorological surveys should be made at the sites of all future large
cooling tower installations where fog could be a potential problem.
Potential in Lake Michigan Area
E G & G has prepared a map, reproduced in Figure VI-1, showing
the distribution of fog potential for the United States (Reference
VI-14, page 38). According to E G & G, the "qualitative classification
for the potential for adverse cooling tower affects" was made using
the following criteria (Reference VI-14, page 36):
a) High Potential: Regions where naturally
occurring heavy fog is observed over 45
days per year, where during October through
March the maximum mixing depths are low
(400-600m), and the frequency of low-level
inversions is at least 20-30$.
b) Moderate Potential: Regions where naturally
occurring heavy fog is observed over 20 days
per year, where during October through March
the maximum mixing depths are less than 600m,
and the frequency of low-level inversions is
at least 20-30%.
-------
VI -7
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VI-8
c) Low Potential: Regions where naturally occur-
ring heavy fog is observed less than 20 days
per year, and where October through March
the maximum mixing depths are moderate to
high (generally >600m).
As shown in Figure VI-1, Lake Michigan is located in an area of
"moderate potential." Thus, some concern over potential fogging in
this area seems justified. It must be emphasized, however, that the
classifications of "high," "moderate," and "low" potential are relative
rather than absolute descriptors. Thus, a cooling tower located in an
area of "high potential" would be more likely to cause a fogging
problem than one located in an area of "moderate" or "low potential,"
but whether or not the tower ever produced a fog problem would depend
on specific site and climatic conditions. For example, the plants
visited by the study teams mentioned previously were located predominantly
in the "high potential" region of Figure VI-1 and no fogging problems
were reported.
-------
VI-9
A study conducted by Travelers Research Corporation (Reference
VI-24) to evaluate the climatic effects of a natural draft cooling
tower for the proposed Davis-Besse Nuclear Plant at Locust Point on
Lake Erie concluded that the visible plume will touch the ground only
2 percent of the time on an annual basis and that localized icing
could occur at ground level approximately 3 percent of the time. No
problems due to precipitation were anticipated. The results of this
study, while specific to the Lake Erie site, give some indication that
towers near Lake Michigan may have similar minor environmental effects
due to similar weather conditions and because both areas lie in the
same region of "moderate potential" indicated in Figure VI-1. This
study is of special interest since Toledo Edison recently announced
plans to use a natural draft wet tower at the Davis-Besse facility.
Calculations of Fog Potential
Two simplified methods are presented below for evaluating the fog
potential of cooling towers in the vicinity of Lake Michigan.
Method 1
Fog is formed when the local humidity is raised to saturation.
Thus, when cooling towers add water vapor to the atmosphere in quantities
sufficient to cause saturation of the ambient air, fog will be produced.
-------
VI-10
The criterion for fog can be expressed as (Reference VI-14):
qs - qa < Aq
where,
q = Liquid-water content at saturation, g/m3
q= = Liquid-water content of ambient air, g/m3
a
Aq = Liquid-water added by cooling towers, g/rrr
E G & G (Reference VI-14) states that Aq is normally between 0.1
and 0.5 g/m3 one or more kilometers downwind from the tower. Thus, any
time (qr - q ) is less than 0.1 to 0.5 g/m3, there is a potential for
s a
fog conditions within one or two miles of the cooling tower.
Figure VI-2 presents plots of (q. - q ) equal to 0.1 g/m3 and
S u
0.5 g/m3 for various combinations of relative humidity and air tem-
perature. Any combination of relative humidity and temperature falling
in Zone C (i.e., (q_ - qj>0.5 g/m3) indicates weather conditions very
S a
unlikely to produce a cooling tower fog. This is true simply because
the ambient air is able to assimilate more than 0.5 g/m3 of water vapor
without becoming saturated. Weather exhibiting temperatures and relative
humidities in Zone B (i.e., 0.1 g/m3 < (qr - qj < 0.5 g/m3) has a low
s a
probability of producing a cooling tower fog, while a temperature-
relative humidity combination falling in Zone A (i.e., (q_ - qa) < 0.1
S ct
g/m3) has a high probability of causing a fog condition when combined
with a cooling tower air-water vapor effluent.
-------
100
0)
-------
VI-12
In order to determine the potential for cooling tower fog in a
particular location, one should determine the total percent of time the
weather conditions shown in the three zones of Figure VI-2 occur. Two
stations in the Lake Michigan area are selected for such an analysis.
Green Bay, Wisconsin is representative of the cold northern area and
Chicago, Illinois is chosen to represent the more moderate climate of
the south end of the Lake. Appropriate data were obtained from the
U. S. Weather Bureau summaries of hourly observations (References
VI-8 and 10).
Table VI-2 gives a breakdown of the percent of time over an
annual cycle when the conditions in the three zones of Figure VI-2
occurred for four ranges of wind speed:
TABLE VI-2
PERCENTAGE OF TIME WEATHER CONDITIONS OCCURRED
FOR ZONES A, B, AND C OF FIGURE VI-2
Wind
Green Bay (North)
Zone A Zone B Zone C
Chicago (South)
Zone A Zone B Zone C
<5 mph
<15 mph
<25 mph
All winds
0.2%
0.7%
0.8%
0.9%
2.5%
9.6%
12.1%
12.3%
97.3%
89.7%
87.1%
86.8%
0.02%
0.09%
0.11%
0.11%
0.6%
3.3%
4.1%
4.2%
99.4%
96.6%
95.8%
95.7%
-------
VI-13
Further separation of meteorological conditions by wind speed is
included in Table VI-2 because high winds are more likely to provide
ventilation to sweep fog away if it does form.
Weather data from Grand Rapids, Michigan (Reference VI-9) on the
east side of the lake were also examined. Fog probabilities were
found to be intermediate between those at Chicago and Green Bay.
Method 2
The necessity of assuming a value for Aq in the foregoing analytical
method can be overcome by computing the dilution of a cooling tower
plume with the ambient air. A simplified method of approximating the
dilution of a cooling tower plume by the ambient atmosphere can be
developed from standard methods of evaluating smoke plumes from a
point source.
Turner (Reference VI-25) gives values of vertical and horizontal
dispersion coefficients (a , a ) for plumes as a function of downwind
distance for several atmospheric stability categories. These coefficients
can be used to estimate plume spread in the two cross-sectional dimensions
of the plume, and thus the dilution of the plume with the ambient atmo-
sphere is indicated.
Assuming no dilution for the first 100 meters downwind (this should
be a very conservative assumption), one can estimate plume spread and
plume dilution for values of x greater than 100 meters by the following
equations:
-------
VI-14
az2
Vertical spread at x9 =
Horizontal spread at x9 =
i ayl
Plume Dilution
where,
gz2 °y2
azl ayl
i , a ,
Downwind distance
Dispersion coefficients at x = 100 meters
az2' av2 = Dispersion coefficients at
Tables VI-3,4 and 5 summarize the pertinent data from Reference
VI-25. Note that stability classes A-F are indicated. Class A represents
the most unstable condition where dilution and plume rise would be
maximized. Stability increases from A to F, where Class F represents
the most stable atmospheric conditions were dilution and plume rise
would be minimal .
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VI-16
TABLE VI-4
DILUTION RATIOS
X2 Stability Class
1,000 m A
B
C
D
E
F
Dilution Ratios
250
81
67
53
50
56
10,000 m* A >5,000
B >4,700
C 4,250
D 2,050
E 1,500
F 1,390
*A somewhat more accurate estimate of the dilution rates at 10,000 m
can be obtained by using the ratio of a , ^z-\/^V2 °z2' w'iere
x, = 1000 m and x^ = 10,000 m and.multiplying the ratio by the
dilution rate at x = 100 m. These are shown in Table VI-5.
-------
VI-17
TABLE VI-5
DILUTION RATIOS
X Stability
10,000 m A
B
C
D
E
F
Dilution Ratios
>8,000
>12,000
6,060
1,560
660
225
-------
VI-18
To evaluate the amount of dilution required to prevent a cooling
tower fog, one must have information on the ambient air temperature
and relative humidity as well as the initial temperature of the tower
plume which is assumed to be saturated.
Two cases are illustrated below:
Case 1 - High Fog Potential
Air Temperature = 0°F
Relative Humidity = 95%
Plume Temperature = 50°F (estimated)
Plume moisture =9.4 g/m3
Ambient air moisture = 1.21 g/m3
Moisture in saturated 0°F air = 1.27 g/m3
' Dilution (D) required:
9.4 g/m3 + 1.21 g/m3 (D) = (1 + D) 1.27 g/m3
D = 136
GPO 8197777
-------
VI-19
Therefore, one part tower effluent to more than 136 parts ambient
air will not produce saturation. From Table VI-4, it is seen that at
a downwind distance of 1000 meters insufficient dilution (i.e., D < 136)
is obtained for stability Classes B, C, D, E, and F. These classes
would produce a visible plume at that distance, and fog would be pos-
sible if the plume reached the ground, however, normally the plume would
rise. The most unstable condition (e.g., Stability Class A) would pro-
vide adequate dilution. This trend corresponds to Reference VI-14
where it is concluded that more stable conditions provide greater fog
potential. Table VI-5 indicates that at 10,000 meters dilution sufficient
to prevent fog is present for all stability categories.
Case 2 - Low Fog Potential
Air Temperature = 50°F
Relative Humidity = 95%
Plume Temperature = 80°F (estimated)
Plume moisture = 25.3 g/m3
Ambient air moisture =8.9 g/m3
Moisture in saturated 50°F air = 9.4 g/m3
.*. Dilution required:
25.3 g/m3 + 8.9 g/m3(D) = (1 + D) 9.4 g/m3
D = 32
Since Table VI-4 indicates dilution rates in excess of 32 for all
stability classes, a visible plume at 1000 meters downwind would not
exist and fog would not be possible.
-------
VI-20
It should be emphasized that the above analyses (i.e., Methods 1
and 2) are very general and unsophisticated. However, they do indicate
that weather conditions in the Lake Michigan area are seldom severe
enough to cause extensive fog conditions in the vicinity of wet cool-
ing devices.
A more sophisticated approach to analyzing the potential for
adverse weather effects due to cooling towers was developed by E G & G
under an FWQA contract (Reference VI-14). However, the mathematical
model constructed by E G & G is only useful in analyzing specific sites
with specific meteorological data. It would be impractical to generalize
the model to run cases applicable to this Lake Michigan study. It
should be emphasized, therefore, that for proposed specific power plant
sites, adequate meteorological data should be collected during the
site selection phase so that accurate predictions of the fog potential
of cooling towers at these sites can be made.
Consumptive Water'Loss by Evaporation
Heat transfer by evaporation is one of the principal mechanisms
by which wet cooling systems dissipate waste heat to the atmosphere.
Thus, transfer of mass occurs and is a factor in the Lake Michigan
water budget.
-------
VI-21
The present average water budget is approximately characterized
by precipitation of 50,000 cfs, tributary inflow of 39,000 cfs,
evaporation of 40,000 cfs, diversion at Chicago of 3,400 cfs, and
discharge at the Straits of Mackinac of 46,000 cfs (References VI-1
and 17).
Hauser and Oleson (Reference VI-15) compared the evaporation
losses of several wet cooling systems. They (Figure 2 of Reference
VI-15) estimated evaporation rates as reflected in Table VI-6 given
the following meteorological and design conditions:
Wet bulb temperature = 70°F
Relative humidity = 60%
Cloud cover = 7/10
Wind speed = 8 mph
Cooling range = 20°F
It must be emphasized that the data in Table VI-6 are representative
of specific meteorological and plant operating conditions and thus they
cannot be applied to the cooling system designs presented here for Lake
Michigan. However, the data in Table VI-6 do give order of magnitude
estimates useful in determining the relationship between the evaporation
rates for various cooling methods.
-------
VI-22
TABLE VI-6
BASED ON DATA FROM MAUSER AND OLESON (REFERENCE VI-15)
Cooling System Evaporation
cfs1
Cooling Pond (2 acres/MW) 20.0
Cooling Pond (1 acre/MW) 16.0
Mechanical Draft Tower 13.0
Spray Pond 12.7
Natural Draft Tower 12.0
Natural Lake or River 9.4
a 1000 MWe fossil fueled plant at 82 percent capacity factor
average annual evaporation (assume constant meteorological
conditions).
-------
VI-23
Data on rates of evaporation loss for the various wet cooling
devices at summertime design meteorological conditions are presented
in Section V, "Results," in Tables V-l, V-2, and V-5. To obtain data
meaningful in terms of the annual water budget, one must adjust these
values to reflect 1) lower evaporation rates during the off-design
conditions, and 2) plant operation at less than 100 percent capacity.
The average annual evaporation rate for the wet towers and spray
canals are approximated by multiplying the rate under design conditions
by the plant capacity factor (0.82) and by 0.8 to reflect an average
decrease in evaporation rate of 20 percent during the off-design period.
Cooling ponds experience a much more pronounced drop in evaporation
during the off-design period (i.e., annual cycle) because of a large
decrease in the incoming long and short wave radiation. For example,
the design incoming radiation equals 5580 Btu/ft2 day, while for the
normal annual cycle it averages 3070 Btu/ft2 day. Thus, during off-
design conditions averaged over the year the pond dissipates approximately
2500 Btu/ft2 day less energy. In terms of evaporative loss this is
equivalent to 10 cfs per 1000 acres of pond surface. This factor along
with the plant capacity factor (0.82) is used to calculate annual
evaporation rates from design condition evaporation rates.
-------
VI-24
Table VI-7 presents the evaporation rates for both the design
case and average annual conditions for the appropriate cooling devices.
The data given in Table VI-7 represent the evaporation rates averaged
over the four geographic sections since little variation was found
between these sections. The average evaporation rates for all seven
cases is also given.
In evaluating the consumptive water loss for cooling ponds, the
natural evapo-transpiration losses of the area should be considered.
The Lake Michigan region has an average annual precipitation rate of
30-inches per year (Reference VI-7) and an average annual runoff rate
of 10-inches per year (Reference VI-18), giving an average annual natural
evapo-transpiration rate of 20-inches per year. For land areas corre-
sponding to cooling pond sizes, the average evapo-transpiration rates
in cfs are given as:
Land Area Evapo-transpiration
1500 acres 3.5 cfs
1750 acres 4.0 cfs
2000 acres 4.6 cfs
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-------
VI-26
These natural evapo-transpiration rates should be subtracted from the
pond evaporation rates to give the net consumptive water loss due to
the cooling ponds. When this is done, the consumptive water loss for
the cooling ponds is less than one cfs greater than the evaporation
losses from wet cooling towers.
Any discussion of the consumptive water loss due to wet cooling
devices must also consider the increase in natural levels of evaporation
caused by once-through cooling. For example, Asbury (Reference VI-1)
estimates the increase of evaporation in Lake Michigan due to thermal
discharges from power plants with once-through cooling to be 9 cfs for
each 1000 MW, (thermal) of waste heat discharged. A 1000 MWe fossil
fueled plant wastes about 3800 Btu/KWH to the cooling water as compared
to an electrical output of 3413 Btu/KWH. Thus, a 1000 MWe fossil plant
with once-through cooling will increase natural lake evaporation by
about (3800/3413)(9) = 10 cfs.
By using the plant capacity factor of 0.82 to adjust the 10 cfs
figure, an average annual evaporation rate of 8.2 cfs is obtained for
the once-through system. The relationship between this value and those
given in Table VI-7 for the various cooling systems corresponds to the
relationship proposed by Hauser and Oleson (Reference VI-15) and pre-
sented in Table VI-6. Therefore, when one compares the evaporation
rates for wet towers and spray canals with the evaporation rate for
once-through cooling, a difference of only (10.6 cfs minus 8.2 cfs =)
2.4 cfs exists. For cooling ponds, the difference is less than 3.4
cfs, when natural levels of evapo-transpiration are considered.
-------
VI-27
Drift
Drift is entrained water that is carried out of the top of a wet
cooling tower or from a spray canal in liquid droplets rather than
vapor. Drift can produce undesirable effects.
Waselkow (Reference VI-26) points out that "flash-over" of
transmission lines was caused by excessive drift. This problem was
solved by relocating the transmission lines. Waselkow recommends a
500-foot separation between cooling towers and transmission lines.
Recent surveys of existing power plant facilities (References
VI-4, 6, 20, and 22) have uncovered only minor problems involving
drift from freshwater towers. Drift is more likely to result from
mechanical draft than from natural draft towers. However, in situations
where drift has been noted, the area affected was limited to the
immediate vicinity of the tower installation.
The typical drift guarantee of 0.2 percent of the circulating
water flow is far in excess of current engineering capability and
practicality for large towers. Drift can be almost completely eliminated
by control of air velocity and design of drift eliminators. Mechanical
draft towers can be purchased today with certification of drift elimination
to the 0.02 percent level. Current developmental work by cooling tower
manufacturers is expected to enable further reduction of drift.
-------
VI-28
B1 owdown
As water is lost by evaporation from the cooling water supply of
wet cooling devices, non-evaporating substances are concentrated in
the remaining cooling water. There is a practical limit of concentration
of the substances if scale corrosion and general deterioration of the
cooling structures are to be prevented. To avoid such problems, a
certain amount of the cooling water customarily is drained off the
system for disposal. This water, termed blowdown, is replaced by fresh
makeup water.
Blowdown, as it comes from the tower, contains concentrated solids
and dissolved salts and minerals present in the original makeup water;
it may contain special chemicals used to prevent scale and corrosion of
condenser tubes and deterioration of wood structures; it may contain
special algicides and fungicides; and, it is generally at a higher
temperature than ambient lake or stream water. Hence, blowdown is an
industrial waste in every sense of the word, subject to control under
water quality standards.
The relationship between concentration of non-volatile, "conservative"
constituents and design and operation of the cooling devices is:
r - E + D + B
L ~ D + B
where,
C = The multiple of concentrations of makeup water
E = Evaporative loss
D = Drift
B = Blowdown
-------
VI-29
Evaporation, drift, and blowdown are conventionally expressed as per-
cent of circulating flow rate.
The volume of blowdown discharged to a receiving water is strongly
influenced by the concentration multiple, but the temperature of the
blowdown is independent of this factor. Therefore, the thermal pollution
of Lake Michigan can be minimized practically to the point of extinction
by increasing the concentration multiple.
The effect of concentration multiples on volume of blowdown from
wet towers and spray canals for our typical 1000 MWe plant is demonstrated
in Table VI-8. In these example computations evaporative losses are
established from Table VI-7 and a figure of 0.05 percent is used for
drift. With this figure for drift and assuming no leakage, the maximum
concentration multiple that could be reached with no blowdown is 35:1.
If drift is taken as 0.2 percent, the maximum concentration multiple
is 9.5:1.
The concentration of dissolved solids in the Lake Michigan is very
low. Hence, even with no blowdown the salt concentration of the
circulating flow would not be at all unique to power plant operation
in the United States.
-------
VI-30
TABLE VI-8
SLOWDOWN FROM WET TOWERS AND SPRAY CANALS
Concentration
Multiple
(C)
Evaporation
Losses
(E)
Slowdown
(B)
cfs
1:1
5:1
10:1
25:1
35:1*
1.7%
1.7%
1.7%
1.7%
1.7%
1.75
0.38
0.14
0.02
0
17
4
1
0.2
0
*Maximum concentration multiple.
-------
VI-31
A 5:1 concentration multiple is frequently used as a generaliza-
tion (Reference VI-13), but a survey of several power plants by FWQA
reveals a very wide range in actual practice. DeFlon (Reference VI-12)
and Southern Nuclear Engineering (Reference VI-22) cite concentrations
of circulating flow in cooling towers up to 100,000 ppm total dissolved
solids. The mechanical draft towers at the Mohave power plant in the
arid southwest are designed for zero blowdown to receiving waters.
Table VI-9 shows average chemical concentrations found on two
transects of Lake Michigan in 1962-63 (Reference VI-21). The southern-
most transect (41030'-41°45') is in the Chicago area and could be
expected to have the most pollutants. The other transect (43°30'-43045')
runs from Pentwater, Michigan to Sheboygan, Wisconsin and was chosen
because there are few streams or major waste inputs in the area.
Included are potential concentrations in blowdown water, calculated at
a ratio of 5:1. These concentrations compared to those permissible for
public water supplies, do not appear to be high enough to cause concern.
It also is obvious from Table VI-9 that treatment of blowdown to reduce
hardness (Ca and Mg alkalinity) and heavy metal concentrations would
allow much higher concentration multiples than 5:1.
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VI-34
Table VI-10 shows the relationships of temperature of blowdown from
wet cooling devices at design meteorological conditions and design
summer lake temperature. Although these relationships would vary
seasonally and with operating practices, the increase above ambient
would be appreciable in all cases. However, the effects of blowdown
temperatures on Lake Michigan cannot be projected out of context
from the volumes of blowdown discharged. See Table VI-8.
If makeup water is taken from Lake Michigan (or similarly dilute
sources) blowdown can be reduced to almost any level without hazard
from salt discharged to the atmosphere by drift. As shown in Table VI-9
Lake Michigan water is non-corrosive and the chloride concentration is
very low.
Blowdown may also contain chemicals which are added to the cooling
water for special control purposes (See Table VI-11). Many of these
are toxic and may have to be treated to comply with water quality
standards, a task which Donahue (Reference VI-13) claims can be
accomplished economically.
Toxicants in blowdown can be controlled by careful choice of treat-
ment chemicals to ensure use of those which will do the job with the
least effect on the environment. For example, chlorine used for pre-
vention of fouling is lost in the tower through evaporation and residual
chlorine in blowdown can be very low. But, other anti-foul ing agents,
such as mercuric compounds,are very toxic and should be avoided.
GPO B19777B
-------
VI-35
TABLE VI-10
TEMPERATURE OF BLOWDOWN AT DESIGN CONDITIONS
Slowdown Lake Temperature
Temperature Temperature Difference
Wet Cooling Device (°F) (°F) (°F)
Mechanical Draft
Tower 88 68 20
Natural Draft
Tower 84 68 16
Spray Canal 90 68 22
-------
VI-36
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VI-38
If high concentrations of toxicants are necessary in the cooling
system, they require treatment before release. For example, toxicant
hexavalent chromates can be reduced by reaction with sulfides and the
excess sulfides removed by aeration; chromium and copper salts may be
reduced by contact with lime and copper ash (Reference VI-19).
In summary, blowdown composition will vary with plant design and
operation and with intake water quality. Adverse effects can be
minimized by trade-offs in plant and tower design or by chemical treat-
ment of outlet water.
Summary
While cooling devices do have the potential for producing undesirable
environmental effects, such effects do not seem to be a problem for the
Lake Michigan area. Careful pre-site selection surveys should eliminate
sites which have a high potential for fog or drift problems, and blow-
down treatment can be provided, if necessary. Site by site evaluation
of the potential for consumptive water loss by evaporation may be
necessary.
Lake Michigan temperature standards can be met by (1) design and
operation of wet cooling systems with no, or essentially no, blowdown,
(2) dilution of any residual blowdown with Lake Michigan water, (3)
dry cooling towers, or (4) construction of closed cycle systems at sites
independent of Lake Michigan as source af water supply or sump for
blowdown.
-------
VI-39
References
VI-1. Asbury, J. G. "Effects of Thermal Discharges on the Mass/
Energy Balance of lake Michigan," Argonne National
Laboratory, Argonne, Illinois, (unpublished). June,
1970.
VI-2. Aynsley, Eric. "Cooling-Tower Effects: Studies Abound."
Electrical World. 173 (19): pp. 42-43. May, 1970.
VI-3. Baker, K. G. "Water Cooling Tower Plumes." Chemical and
Process Engineering, pp. 56-58. January, 1967.
VI-4. Broehl, G. J. "Field Investigation of Environmental Effects
of Cooling Towers for Large Steam Electric Plants."
Portland General Electric Company, (unpublished).
April 1, 1970.
VI-5. Buss, J. R. "How to Control Fog from Cooling Towers."
Power, pp 72-73. January, 1968.
VI-6. Christensen, S. R. "Cooling Tower Plume Effects." Portland
General Electric Company, (unpublished). March 4, 1968.
VI-7. Commerce, U. S. Department of. "Climatic Atlas of the United
States," Environmental Science Services Administration,
Environmental Data Service, June 1968.
VI-8. Commerce, U. S. Department of. Weather Bureau. "Summary of
Hourly Observations." Chicago, Illinois. Climatography
of The United States No. 82-11.
VI-9. Commerce, U. S. Department of. Weather Bureau. "Summary of
Hourly Observations." Grand Rapids, Michigan. Climatography
of The United States No. 82-20.
VI-10. Commerce, U. S. Department of. Weather Bureau. "Summary of
Hourly Observations." Green Bay, Wisconsin. Climatography
of The United States No. 82-47. 1963.
VI-11. Decker, Fred W. "Cooling Towers and Weather." Department
of Physics. Oregon State University. February, 1969.
VI-12. DeFlon, James G. "Design of Cooling Towers Circulating Brackish
Waters." The Marley Co. 1968-69.
VI-13. Donahue, John M. "Chemical Treatment." Industrial Waste
Engineering. 7 (5): 35-38. 1970.
-------
VI-40
VI-14. EG&G. "Potential Environmental Modifications Produced
By Large Evaporative Cooling Towers." EG&G, Inc.
April, 1970.
VI-15. Mauser, L. G. & K. A. Oleson. "Comparison of Evaporative
Losses in Various Condenser Cooling Water Systems."
American Power Conference. Chicago, Illinois. April,
1970.
VI-16. Interior, U. S. Department of. Water Quality Criteria.
FWPCA. Report of the National Technical Advisory
Committee to the Secretary of the Interior.
1968.
VI-17. Interior, U. S. Department of. Water Quality Investigations-
Lake Michigan Basin, Lake Currents, FWQA, Chicago, Illinois,
T967:
VI-18. Langbein, W. B., et al. "Annual Runoff in The United States."
Geological Survey Circular 52. June 1949.
VI-19. McKelvey, K. K. & Maxey Brooke. "The Industrial Cooling
Tower," Elsevier Publishing Company, 1959.
VI-20. Pollution Control Council. Pacific Northwest Area. "A
Survey of Thermal Power Plant Cooling Facilities."
1969.
VI-21. Risley, Clifford Jr. & Frederick D. Fuller. "Chemical
Characteristics of Lake Michigan." Proceedings of
Eighth Conference on Great Lakes Research. Great Lakes
Research Division. Institute of Science & Technology,
University of Michigan. Publication #13, 168-174.
1965.
VI-22. Southern Nuclear Engineering, Inc. "An Evaluation of The
Feasibility of Salt Water Cooling Towers for Turkey
Point -- for Florida Power and Light Company. Dunedin,
Florida and Washington, D. C. 1970.
VI-23. Stewart R. "Thermal Discharge From Nuclear Plants And
Related Weather Modification." Proc. 12th Conference
Great Lakes Res. 488-491. Intemat. Assoc. Great Lakes
Res. 1969.
VI-24. Travelers Research Corporation. "Climatic Effects of a
Natural Draft Cooling Tower Davis-Besse Nuclear Plant."
Prepared for Toledo Edison Company. October, 1969.
-------
VI-41
VI-25. Turner, Bruce D. "Workbook of Atmospheric Dispersion
Estimates." U. S. Department of Health, Education,
and Welfare. Environmental Health Series. 1969.
VI-26. Waselkow, Charles. "Design and Operation of Cooling Towers."
Engineering Aspects of Thermal Pollution, pp 249-281.
1969.
-------
VII. CONCLUSIONS
Based on the results presented in this report, it is concluded
that any of the six cooling systems evaluated are feasible alternatives
to once-through cooling for thermal power plants around Lake Michigan.
The absolute magnitude of the numbers derived in the analysis cannot
be applied to specific plants because of unique site differences, but
the numbers do indicate feasibility.
Meteorologic conditions throughout the study area do not impose
restraints that are beyond present-day capabilities in terms of
engineering design and continuous operation of the alternative cooling
systems.
The impact of alternative cooling systems on the environment
appears to be minor. Potential problems can be avoided or alleviated
through proper site selection and engineering design.
The maximum economic penalty for each type of cooling system in
terms of the approximate percent increase in power generation (busbar)
cost above that involving a once-through system is:
Wet mechanical draft tower
Wet natural draft tower 3%
Cooling pond <1%
Spray canals 1%
Dry mechanical draft tower 10%
Dry natural draft tower 9%
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VII-2
As indicated, the maximum economic penalty among all wet cooling
systems is about 3 percent. The magnitude of this penalty (about
0.2 Mills/KWH) is roughly equivalent to any one of the following:
a) A $10/KW difference in plant capital cost,
b) A 1 percent difference in fixed charge rate,
c) A 2tf/106 Btu difference in fuel cost, or
d) An 80-mile difference in power transmission distance.
When a closed-cycle cooling system is chosen for a new plant,
more latitude in plant siting is gained because large volumes of
cooling water are no longer a site prerequisite. According to the
Geological Survey Water-Supply Paper 1800, the area around Lake
Michigan is generally one of moderate to high surface water runoff
and groundwater availability. Therefore, make-up water acquisition
should not pose problems at selected inland plant sites.
U.S GOVERNMENT PRINTING OFFICE Q 1 9708 f 9532
819-777-1
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