Staff Report On
Engineering and Economic Aspects of
Wet and Dry Cooling Systems
By
Dr. Bruce A. Tichenor
and
Dr. Mostafa A. Shirazi
March 1974
Thermal Pollution Branch
Pacific Northwest Environmental Research Laboratory
200 SW 35th Street
Con/all is, Oregon
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FOREWORD
The study described herein is one of three conducted at the
request of Region VIII, Environmental Protection Agency, as a
technical contribution to the ongoing, interagency Northern Great
Plains Resources Program. In recognition that the findings and
approach have interest and application beyond the geographic
boundaries and scope of the initiating Program, this Chapter II
is made available as a Staff Report.
Other Chapters, similarly available from the Librarian,
Pacific Northwest Environmental Research Laboratory, are:
Chapter I Water Requirements for Power Plants with
Wet Cooling Towers, by Guy R. Nelson
Chapter III Water Usage in the Conversion of Coal to Pipeline
Quality Gas, by James P. Chasse
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CHAPTER II
Engineering and Economic Aspects of
Wet and Dry Cooling Systems
Introduction
This chapter presents an evaluation of the engineering and economic
aspects of cooling water systems for lOOOMWe coal fired power plants
at three sites within the Northern Great Plains study area. (Colstrip,
Montana; Gillette, Wyoming; Stanton, North Dakota) Closed-cycle
cooling systems with wet and dry mechanical draft cooling towers are
selected for analysis. In addition, once-through cooling is evaluated
for economic comparison. System design is based upon design
meteorological conditions representative of critical summer months.
Annual operating characteristics and costs are evaluated using long-
term seasonal average weather conditions.
Meteorology
The design and operation of facilities to dissipate waste heat from
thermal power plants are dependent to a large degree upon the weather.
Therefore, accurate meteorological data are required. Both design and
off-design (i.e., annual variations) data must be compiled.
The meteorological variables of significance for this study include:
Wet towers - wet and dry bulb air temperatures
Dry towers - dry bulb temperatures (frequency distribution)
Once-through - water temperatures
Data on wet and dry-bulb temperatures are contained in Table II-l.
The design data provided are for temperatures not exceeded more than
5 percent of the time during the summer months. The four seasons
consist of the following months:
Winter - December, January, February
Spring - March, April, May
Summer - June, July, August
Fall - September, October, November
The data in Table II-l were obtained from a compilation of data
supplied by Mr. James Shaw, EPA, Region VIII (Ref. II-l). Note that
average data for Colstrip and Gillette are also provided.
II-l
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Tables II-2, II-3, and II-4 contain data on the annual frequency
distribution of dry bulb temperatures for Bismarck, North Dakota
(applied to Stanton), Sheridan, Wyoming (applied to Gillette), and
Miles City, Montana (applied to Colstrip). The data in Table II-2
were obtained from Ref II-2, while Tables II-3, and II-4 were developed
from information received from Ref II-3.
Data on water temperatures to be expected at the selected sites were
not provided, so it was assumed that any surface water which would be
available to a power plant would be from a completely mixed water body
at equilibrium temperature (i.e., the temperature at which the net
exchange of energy across the air-water interface is zero). Data on
equilibrium temperatures from Ref II-4 were examined for Casper, Wyoming;
Billings, Montana; and Bismarck, North Dakota. The data for these three
locations were essentially the same for both design (summer extreme)
and average conditions. Thus, the following values of available water
temperature were used for all three sites:
Design - 79°F
Winter - 32°F
Spring - 49°F
Summer - 75°F
Fall - 49°F
Economic Considerations
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. 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 dissipation
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 any study of this type.
II-3
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II-6
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Data on plant capital costs, fuel costs, and fixed charge rates for
power plants to be constructed in the Northern Great Plains Study
were provided by EPA's Region VIII (Ref. II-l). Table II-5 gives the
low, high, and, if appropriate, medium values for these cost factors.
In the economic analysis which follows, several combinations of these
cost factors were examined.
Engineering Considerations
The initial requirements for approximating the size and performance of
alternative cooling systems are the meteorological and economic data
given previously. 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 source of the computer programs. A computer program developed by
the Dynatech Corporation was used as a primary means for analyzing wet
cooling towers and once-through systems (Ref. II-5). Design and cost
data on mechanical draft dry (Heller) cooling systems were obtained
from the analysis provided by R. W. Beck and Associates (Ref II-2).
The Dynatech and R. W. Beck computer programs are the results of EPA
research contract efforts. Supplementary cost data on wet towers were
obtained from The Marley Company (Ref. II-6) and the literature (Ref.
II-7). Cross-referencing and spot checks among 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.
Detailed discussions of the optimization procedures used are not given
here. The interested reader is urged to consult the original source
(Refs. II-2, 5) for such details. In addition, a report on alternative
cooling systems for the Lake Michigan area (Ref. II-8) contains
information on the procedures, as well as numerical results.
The two computer programs used in this study have substantially different
input requirements. In order for the reader to properly evaluate the
final results of the analyses, the appropriate input data are provided.
It should be noted that both programs contain coefficients, constants,
etc. which can be changed by the user. Unless noted herein, the program
constants used in this study are as contained in the source references.
In addition to the meteorological and economic data given previously,
the Dynatech program requires input data on plant capacity on an annual
cycle and turbine heat rate.
II-7
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Table I1-5
Cost Factors
Plant Capital Fixed Charge Fuel.Cost
Magnitude Cost ($/KK) Rate (%) U/10 BTU)
Low 300 12 16
Medium 15
High 400 18 19
II-8
-------
An average annual plant capacity factor of 0.77 was selected, based
on information provided by Region VIII (Ref. II-l). The following
distribution of load on the 1000 MWe base plant was selected to
correspond to the 0.7 plant capacity factor:
Capacity 1.0 0.8 0.6 0.4 0
Hours/yr 4000 2000 1310 900 550
In order to evaluate the operation of the cooling system throughout
the annual cycle, the Dynatech program requires a seasonal distribution
of plant capacity; Table II-6 provides such information for this study.
Another important system cost factor is the turbine heat rate and its
variation with capacity factor and the condenser operating temperature.
Data for typical GE turbine of a 1000 MWe capacity were used with the
Dynatech program. Turbine heat rates at several capacity factors were
obtained from the manufacturer's heat rate tables (Ref. III-9). Table
II-7 provides these data. (Note that these are heat rates for a
specific turbine and should not be equated to an overall plant heat rate.)
The Dynatech program contains cost functions for all components of the
cooling system, including condenser, pumps, cooling tower, intake and
outlet structures, etc. A review of recent literature (Refs. II-6, 7, 10)
and manufacturer's data was undertaken to update these cost functions.
This review indicated that the cost functions contained in the Dynatech
program were still generally applicable. Two changes were made. Condenser
costs were increased by 50 percent to account for recent increases in
cost. The overall heat transfer coefficient for the condenser was
assumed to be 525 BTU/hr-ft2 - °F. Also, pump costs were increased from
$l/gpm to $1.70/gpm based on data in Ref. 11-10. These changes in cost
functions cause relatively minor increases in cooling system cost over
the original Dynatech values.
The R. W. Beck program was written for optimizing Heller-type mechanical
and natural draft dry tower cooling systems for steam electric power
generating plants. The dry tower system is "optimized" with respect
to four major cost items: capital cost, auxiliary power cost, plant
fuel cost, and cost of replacing lost capacity. The program does not
provide an exact cost optimization of a dry cooling tower system at
this time because of two major problems: a) unavailability of performance
and cost data for high back pressure turbines and b) the proprietary
nature of information on cost and performance of cooling coils. Reasonable
extrapolations based on the current turbine designs and order of magnitude
estimates of prepackaged cooling coil-fan modules are used in the program.
The cost information in Ref. II-2 has not been increased due to inflation
since 1969.
The R. W. Beck program was run with both summer and winter peaking. In
the summer peaking mode, the program provides gas turbine peaking units
II-9
-------
Table II-6
Percent of Time at Various Capacities
on a Seasonal Basis
Plant
Capacity Winter Spring Summer Fall
1.0 30 20 30 20
0.8 25 25 25 25
0.6 25 25 25 25
0.4 18 32 18 32
0 0 50 0 50
11-10
-------
Table I1-7
Turbine Heat Rates* (BTU/KWH)
Back Pressure (In. Hg)
Capacity
1.0
0.8
0.6
0.4
1.0
7415
7483
7674
8045
2.0
7532
7659
7947
8434
3.0
7716
7855
8181
8728
3.5
7805
7941
8283
8847
*For a 1000 MWe turbine, cross-compound, 3600/1800 RPM, 3500
PSI6, 1000/1000F, 6 flow, 38 inch last stage blades.
11-11
-------
($100/KW, 40<£/106 BTU fuel cost, 15,000 BTU/KWH heat rate, and $1.20/KW
O&M cost) to make up lost capacity during the summer when excessively
high air temperatures occur more than ten hours per year. Since most of
the power to be generated in the Northern Great Plains will be exported,
summer peaking capacity could be provided by the end user (e.g., a
Chicago utility) instead of at the site (e.g., Colstrip). Thus, a
winter peaking season, where the advantages of cool temperatures provide
low power plant heat rates, was also analyzed. For winter peaking, gas
turbines are not required.
For annual operation emphasizing either summer or winter peaking, the
plant provides an annual output of 6.56 x 106 MWH of electric power.
This is based on an average annual plant capacity of 0.75 with the
following distribution:
Capacity 1.0 0.75 0
Hours/yr 3750 3750 1260
In order to obtain equivalent power output under both summer and winter
peaks, the cost data provided are not truly "optimal," because the data
were selected at the specific ITD which gave the desired plant output
rather than the "optimal" ITD.
Results
Economic data for the three cooling systems analyzed (i.e., once-through,
closed-cycle wet mechanical draft cooling towers, and Heller type dry
towers) are presented in tabular form. For once-through and wet towers,
the Gillette and Colstrip sites were run as one site, since the relevant
meteorological parameters were essentially equal. As stated previously,
the Dynatech and R. W. Beck programs were run for several combinations
of the economic factors contained in Table II-5.
Only minor variations in wet cooling system design characteristics
occurred between the various cases analyzed. For once-through cooling
systems, the condenser A T varied from a low of 26°F to a high of 31°F
with an average of 28°F. For the wet MD tower, the range averaged 26°F
and the approach was 19°F.
The cost data for once-through and closed-cycle wet towers are contained
in Table II-8. The data for all three sites were averaged, since the
slight variation in meteorology did not cause significant differences
in cost. The last column in this table shows the overall economic
impact of the cooling system on the total busbar cost. It includes
fixed charges, O&M costs, and fuel penalties.
Table II-9 provides cost data for dry (Heller type) towers for the
three sites. Note that the capital cost of the tower at each site was
constant. The three columns in Table II-9 for each site provide the
following information:
11-12
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Total plant fuel cost - The average annual plant fuel cost
including the cost of fuel to run the auxiliary equipment for the
cooling systems, but excluding the fuel used in gas turbine peaking
units. For the conditions examined in this report, the auxiliary
energy required is 1 to 2 percent of the total plant energy generated.
This information is reflected in the annual plant fuel cost.
Total system cost - The average annual cost for the cooling
system, including fixed charges, O&M, and peaking costs, plus the
total plant fuel cost.
Cooling system penalty - The difference between the first two
columns; this column provides the total cost attributable to the cooling
system, exclusive of fuel penalties for auxiliaries. As is noted below,
this column cannot be directly compared with the last column in Table II-8.
The ITD values used in the dry tower analyses are: Colstrip, 61.3°F;
Gillette, 63.5°F; Stanton, 64.5°F.
Summary and Conclusions
The different methods of optimization used by the two programs makes
it difficult to make a direct comparison between the two outputs. For
example, the Dynatech program directly provides the total cost penalty
associated with the cooling system (i.e., the last column in Table II-8),
while the R. W. Beck program computes cooling system cost including
plant fuel cost. In order to provide a direct comparison of costs
between wet and dry tower systems, it was necessary to determine the
total plant fuel cost for the wet systems and add it to the cooling system
cost, thus providing a total system cost comparable to total system cost
column in Table II-9 for dry towers. Using a nominal plants-heat rate of
9000 BTU/KWH, plant fuel costs of 1.44 Mills/KWH for 16<£/10b BTU coal and
1.71 Mills/KWH for 19
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f
Table 11-11 provides several comparisons; for the Gillette site using
data obtained from Table 11-10. It is important to recognize that
the data in Table 11-11 represent the economic consequence (expressed
in additional busbar cost) of selecting one type of cooling system
over another.
This chapter admittedly contains a large amount of data, some of it in
a form not amenable to simple evaluation. Hopefully, the data contained
in the tables, especially Tables 11-10 and 11-11, are described with
enough clarity to allow the reader to make a reasoned judgment concerning
the costs of power plant cooling systems in the Northern Great Plains
Study Area. With that hope in mind, no attempt will be made here to
list all of the conclusions which can be extracted from the data. However,
three general conclusions do bear mentioning:
1. For both wet and dry systems, the variation in fixed charge
rate has a much greater effect on cooling system cost than the variations
in either fuel cost or plant capital cost.
2. Providing for winter peaking rather than summer peaking
substantially reduces the cost of dry towers.
3. A direct comparison of wet MD vs dry MD costs requires the cost
of water (if significant) to be evaluated. Chapter I indicates that 1.97
NP/MWH of make-up water is required for a wet MD system using base level
water conservation control. Using this value along with a range of water
costs of $100 to $300 /ac-ft., water cost of 0.16 to 0.48 Mills/KWH are
obtained. Adding these values to the cost of wet MD systems (Table 11-10)
shows that at the higher water costs and for winter peaking, dry MD
systems become economically attractive and indeed may be less expensive
than wet MD systems.
B. Tichenor and M. Shirazi
3/74
11-18
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Date Due
REFERENCES
II-l Shaw, J., Unpublished communication on meteorology, water
quality, and power plant economic and operating data. EPA,
Region VIII, January, 1974.
II-2 R. W. Beck and Associates, Research on dry-type cooling
towers for thermal electric generation, Part I, U.S. EPA,
Water Pollution Control Research Series No. 16130 EES11/70,
November, 1970.
II-3 Young, R., Personal communication (unpublished), R. W. Beck
Associates, February, 1974.
II-4 Vanderbilt University, Effect of geographical location on
cooling pond requirements and performance, U.S. EPA Water
Pollution Control Research Series No. 16130 FDQ3/71, March, 1971
II-5 Dynatech R/D Company, A survey of alternate methods for
cooling condenser discharge water-System selection, design,
and optimization, U.S. EPA, Water Pollution Control Research
Series No. 16130 DHS01/71, January, 1971.
II-6 Dickey, J. B., Jr. and R. E. Cates, Managing waste heat
with the water cooling tower, 2nd Edition, The Marley
Company, Mission, Kansas, April, 1973.
II-7 Kolflat, T. D., Cooling tower practices, Power Engineering,
January, 1974, pp. 32-39.
II-8 FWPCA, Feasibility of alternative means of cooling for
thermal power plants near Lake Michigan, National Thermal
Pollution Research Program, Corvallis, Oregon and Great
Lakes Regional Office, Chicago, Illinois, September, 1970.
II-9 General Electric, Heat rates for General Electric steam
turbine-generators...100,OOOKW and larger, GET-2050B,
(no date).
11-10 Jedlicka, C. L., Nomographs for thermal pollution control
systems, U.S. EPA, Environmental Protection Technology
Series, EPA-660/2-73-004, September, 1973.
11-19
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