WDRKH1G
No.
Sept. 1969
ECONOMIC ASPECTS OF
THERMAL POLLUTION CONTROL
IN THE ELECTRIC POWER INDUSTRY
FEDERAL WATER
POLLUTION CONTROL
ADMINISTRATION
NORTHWEST REGION
PACIFIC NORTHWEST
WATER LABORATORY
CORVALLIS, OREGON
-------
161300969
ECONOMIC ASPECTS
OF THERMAL POLLUTION CONTROL
IN THE ELECTRIC POWER INDUSTRY
by
Alden G. Christiansen
and
Bruce A. Tichenor
September 1969
National Thermal Pollution Research Program
Federal Water Pollution Control Administration, USDI
Pacific Northwest Water Laboratory
Corvallis, Oregon
-------
ECONOMIC ASPECTS
OF THERMAL POLLUTION CONTROL
IN THE ELECTRIC POWER INDUSTRY
I. Introduction
One of the consequences of producing electrical energy in steam-
electric plants is the production of large quantities of waste heat.
In accordance with State-Federal Water Quality Standards for water
temperature, this waste heat must be controlled. Several avenues of
waste heat treatment and disposal are available:
1. Direct discharge of heated cooling water to the aquatic
environment after circulation through the power plant condensers, i.e.,
once-through cooling.
2. Dissipation of heat to the atmosphere through the use of
cooling devices such as towers or ponds.
3. Use of the waste heat for beneficial purposes, e.g., irriga-
tion; industrial/chemical processes; aquaculture, etc. Here too, most
of the waste heat ultimately goes into either the water or air.
4. Combinations of the above.
Considering the fixed or diminishing supply of the nation's fresh-
water resources and the forecasted increase in thermal power generation,
one is led to conclude that once-through, fresh-water cooling is un-
acceptable for large, new thermal power plants. Similar conclusions
are voiced by industrial spokesmen. At the second session of the
National Symposium on Thermal Pollution in August, 1968, Shade and
Smith (8) stated: "Run of River and Bay/Lake systems for rejecting
power plant thermal discharge have a very limited future because of
government restrictions."
-------
2
In a paper presented at the American Power Conference in April,
1969, Mauser (5) concluded that by the late 1970's the fresh-water
bodies will ". . . reach a point where no further heat can be injected
into them without damage to the ecology." Therefore, "... the only
natural heat sink left will be the oceans." Hauser states that "...
approximately 31%" of the thermal power generation capacity will be
able to utilize sea water cooling. Thus, he concludes "... that
during the end of the 1970's approximately 70% of the new base load
generation to be installed in this country will utilize some form of
supplementary cooling apparatus."
Most new thermal power plants will use cooling devices. The
purpose of this paper is to discuss the economic impact of cooling --
how it affects the power industry and the consumer.
II. Cooling Systems
Cooling water systems can be divided into two major categories:
1. Once-through Systems. In a once-through system the cooling
water is taken from a water body, passed directly through the condenser
where it extracts energy from the condensing steam and is discharged
back to the receiving water at an elevated temperature. Generally, the
temperature rise between individual once-through,systems varies from
10° to 25° F and averages about 15° F. The amount of thermal energy
discharged to the receiving water is a function of plant size, thermal
efficiency and load factor.
-------
3
Single pass condensers are normally used in once-through systems.
The size, or surface area, of a single pass condenser is inversely pro-
portional to the log mean temperature difference (AT) across it (1).
"1 -
In
[Ts
[Ts
-v
-T2J
Where, AT = log mean temperature difference
T, = incoming cooling water temperature
Tp = leaving cooling water temperature
T = steam condensing temperature
The steam-condensing temperature controls the turbine back pressure
which directly affects the plant thermal efficiency. An increase in T
will increase the turbine back pressure and lower the plant efficiency-
Si nee condenser costs increase with size, requirements for small AT's
will result in higher condenser costs. Also, given a fixed condenser
size, a decrease in the desired temperature rise will require a higher
cooling water flow rate and thus increase pumping requirements.
2. Closed-cycle Systems. Closed-cycle systems use an "off-stream"
cooling device to reduce the temperature of the condenser discharge.
Cooling water is used again and again, thus the terms "recycling" and
"recirculation" are often used to describe a closed-cycle system. Evap-
orative cooling devices are most commonly used. Only relatively small
amounts of make-up water are required from an outside source. The
amount of make-up water required depends upon evaporative and blow-
down losses. Slowdown is a process of removing water from the system
-------
4
to prevent a buildup of dissolved solids in the circulating cooling
water. Slowdown rates are a function of the concentration of solids
in the source water and the rate of evaporation. Make-up water require-
ments are normally about 4% of the total cooling water flow, with evap-
oration accounting for 1 to 1-1/2% and blowdown for 2 to 3%.
Cooling devices operate more effectively when condenser discharge
water is at a high temperature. Thus, a large temperature rise across
the condenser is desirable. Temperature rises of 25°to 35° F are not
uncommon. Dual pressure, double pass condensers are required when large
temperature rise and high cooling water temperature exists. If single
pass condensers were used, the turbine back pressure would be too high
and the plant efficiency would be decreased. For 1000 MW nuclear plant,
Battelle-Northwest (1) estimates the capital cost of single pass con-
densers at 2.1 million dollars whereas a double pass unit would cost
3.4 million dollars. The higher capital cost of double pass condensers
is justified on the basis of optimizing overall plant cooling system
efficiency.
In evaluating the effect of cooling facilities on the cost of a
plant and on the cost of producing power, the cooling facilities should
not be considered independently from the power generating equipment,
but rather both must be considered as a complete package in any economic
evaluation. Therefore, rather than look at each component of a power
plant with respect to its individual effect on the total cost of pro-
ducing power, a more useful approach is to compare the total "bus bar"
costs of thermal power generation from plants employing several different
types of cooling systems.
-------
5
Five different cooling systems presently being used have been
selected for comparison here:
1. Once-through Fresh-Water. This is the most common type of
power plant cooling used at water-rich sites in the United States today,
and it is usually the most economical both from the standpoint of capital
cost and operating costs. Factors tending to influence the cost of once-
through cooling are: control structures to prevent recirculation of
heated cooling water through the system, i.e., skimmer walls , diffuser
systems, long intake and/or discharge lines, and screening. Maintenance
costs can increase because of abrasion of pipes and condensers caused
by sediment-laden water and in preventing corrosion, algal growth, etc.
2. Once-through Sea Water. This system is similar to once-
through fresh-water cooling, but its cost is increased by different
condenser design and materials and the requirement for long intake and
discharge lines. Battelle Northwest (1) reports a 19% cost increase for
salt water condensers over fresh-water condensers of the same size.
Richards (7) estimates the cost of discharge conduits at $500/ft. and
a major West Coast power company puts the cost at $820/ft. for 10 ft.
diameter conduits and $1000/ft. for those 14 ft. in diameter. Thus,
the capital cost of intake or discharge line can vary from $500,000 to
$1 million per 1000 ft.
3. Closed-cycle with Cooling Pond. Cooling ponds are large,
artificial water bodies that transfer heat to the atmosphere through
convection, radiation, and evaporation. This type of system is usually
-------
6
more expensive than once-through cooling because of the cost of land
required for the pond and the construction of the pond. In addition,
the use of dual pressure condensers would increase capital costs.
4. Closed-cycle with Wet Mechanical Draft Cooling Tower.
Evaporation, mechanical draft cooling towers transfer heat to the
atmosphere primarily by evaporative heat loss, although convective heat
exchange can account for as much as 25% of the total heat loss. Large
fans are used to provide air movement through the packing, i.e. the heat
transfer section of the tower. Capital cost of the tower structures,
power costs for the fans, and increased condenser costs make this system
more expensive than once-through cooling. Treatment of blowdown wastes
may also add to costs.
5. Closed-cycle with Wet Natural Draft Cooling Tower. Large
hyperbolic natural draft cooling towers are becoming familiar sights in
the United States. These devices use the density difference between the
incoming air and the air above the packing to promote the flow of air
through the tower, so the costs of fans and power to operate them are
not incurred. However, capital costs are greater than for mechanical
draft units of the same cooling capability. Condenser requirements and
blowdown waste treatment also add to the cost.
III. Cost Comparisons Among Cooling Systems
Table 1 presents data from several sources to compare the costs of
power produced by plants using the various cooling systems described
above. The cost of once-through fresh-water cooling is used as a base,
and the other four systems are compared to this base. The numbers
-------
7
indicate the difference in total production costs (in mills per kilo-
watt hour). The effects of both capital and operating costs are
reflected in these figures. The assumptions specified regarding plant
load factor, interest rates, amortization, etc., are uniform for each
column.
Table 1 indicates the economic influence of cooling systems but
does not account for the variability in other factors which should be
considered in minimizing power costs. Such factors as transmission
distance and bond interest rates may have more effect on power costs
than the choice of cooling systems. For example, Battelle-Northwest
(1) states that a variation in bond interest rate of 1% is equal to a
variation in unit power cost of 0.18 mills/KWH. This is the magnitude
of cost involved in adding cooling towers (Table 1). Transmission
costs vary with distance from the load center. Battelle-Northwest (1)
cites a cost of about 0.3 mills/KWH per 100 miles of transmission. This
figure is substantiated by the analysis of Mauser (5) who equates the
cost of various cooling systems to transmission distance in miles. Mauser
concludes that the additional cost of wet cooling towers, about 0.2
mills/KWH, is equivalent to a transmission distance of about 80 miles.
These factors demonstrate that an overall optimization must be performed
to minimize the unit cost of power from a new plant.
IV. Consumer Cost
The foregoing discussion has delineated the increase in production
or bus bar costs (Table 1) for plants using various cooling systems as
-------
8
TABLE 1
COST OF COOLING ABOVE THAT REQUIRED FOR
ONCE-THROUGH FRESH-WATER SYSTEMS
(Mills/KWH)
Cooling System Hauser (5) Battelle U) Converse (2) Lof & Ward (6L
Once-through 0.0336 0.023
Sea Water
Cooling Pond 0.0331 0.092
Wet Mechanical 0.1557 0.150 0.16 0.2 - 0.3
Draft Tower
Wet Natural 0.1446 0.138
Draft Tower
The figures shown in Table 1 were derived from analyses which used the
following assumptions:
Hauser (5): Based on estimated capital, operating, and maintenance
cost for a typical U.S. 1000 MW nuclear plant; 14% annual fixed charge
rate and 80% plant load factor.
Battelle (1): Costs are those determined in studies of 16 example
locations suitable for siting 1000 MW nuclear plants in the Pacific
Northwest. Analyses were performed on 18 cooling systems at the sites
as follows:
Fresh-Water (Once-through) - 6
Salt Water (Once-through) - 6
Cooling Pond - 1
Mechanical Draft Towers - 1
Natural Draft Towers - 4
Public agency financing was assumed (100% bonds . . . 4-1/2% effective
interest rate); 80% plant load factor.
Converse (2): Costs are those used by Vermont Yankee Nuclear Power
Corporation in evaluating plant and cooling costs for the proposed plant
at Vernon, Vermont. Annual fixed charge rate = 8.42%; 85% plant load
factor.
Lof and Ward (6): Analyses of costs of cooling under typical
conditions in the United States.
-------
9
compared to those using once-through cooling. Who pays for the increased
costs? Naturally, the cost increases are borne by the consumer. It is
important to note, however, that production cost variation is not the
only factor influencing consumer costs. The amount the consumer pays
for electric power is substantially higher than the actual production
costs -- transmission, administration, maintenance, advertising, etc.,
all add to the consumer costs. In some cases the production cost may
only be 20% of the consumer costs (2).
The Federal Power Commission has published information on 1966
consumer costs of electric power by all utilities. Data from several
example utilities in various regions of the United States are shown in
Table 2.
The wide variation in rates shown in Table 2 may be attributed to
differences in the following areas:
1. Capital, production and delivery costs -- land, materials,
labor, fuel, etc.
2. Finance and tax rates depend on the type of utility (public
or private) and other economic factors.
3. Regulations -- State and/or Federal.
To demonstrate the impact of thermal pollution control on the con-
sumer, one can compute the percent increase in consumer costs due to the
increase in production cost. If one assumes that other charges are not
affected by the type of cooling system, the data from Table 1 can be used
with the data from Table 2 to make this calculation. For specific
-------
10
TABLE 2
1966 CONSUMER COST OF ELECTRIC POWER (3,4)
(mills/KWH)
Utility
Commonweal th
Industrial
9.91
Commercial
21.87
Residential
26.84
Edison of
Illinois
Georgia Power
Company
Los Angeles
Department of
Water and Power
San Antonio City
Public Service
Board
Southern
California
Edison Company
8.46
8.60
10.01
8.74
19.48
12.92
21.24
17.87
17.01
20.12
21.03
23.88
Texas Electric
Service Company
Portland General
Electric Company1
U.S. Average
1 Hydro Base
9.78
4.42
9.78
18.83
12.54
21.29
23.55
11.25
23.40
-------
11
utilities not listed in Table 2, data from the Federal Power Commission
reports (3,4) can be used. Table 3 shows the effect of cooling system
type on the electric power cost for the average United States consumer
(based on 1966 prices). As in Table 1, once-through fresh-water cooling
was used as the base. The consumer costs associated with the different
cooling systems are compared to this base.
TABLE 3
PERCENT COST INCREASE FOR AVERAGE U.S. CONSUMER
Cooling System
Once-through
Sea Water
Cooling Pond
Wet Mechanical
Draft Cooling
Tower
Wet Natural Draft
Cooling Tower
Industrial
0.34%
0.94%
3.17%
1.48%
Commercial
0.16%
0.43%
1.41%
0.68%
Residential
0.14%
0.39%
1.28%
0.62%
These data were computed using the maximum figures from Table 1 and assume
that the cost increase, in mills/KWH, is applied equally to industrial,
commercial and residential consumer rates. These figures further assume
that the cost of all the power purchased by the consumer will be increased
in the same proportion as that produced by a single plant using the speci-
fied cooling system. Thus, the effect of merging a single plant into an
existing power system is not accounted for. These assumptions tend to
make the data in Table 3 conservative, i.e., the values are probably too
high.
-------
12
V. Conclusions
The foregoing data and analyses show that the cost of providing
thermal pollution control is not a restrictive factor in the production
of electricity. Incremental increases in the production cost of elec-
tricity from plants with closed-cycle cooling over those with once-
through fresh»water cooling are not excessive. More importantly, the
impact of thermal pollution control on the consumer cost of electricity
is minimal.
Opinions which support these conclusions include:
Shade and Smith (8)
"Cooling by means of closed systems such as cooling towers and
captive cooling ponds is not prohibitive either in initial capital
costs or operating costs, but these costs are not so low they can
be ignored."
Lof and Ward (6)
"... the additional on-site costs incurred by the power plant (and
passed along, in turn, to the power users), due to recirculation
cooling are only a small percent of total cost of electricity
generation and distribution."
and Hauser (5)
"The economic penalties associated with alternative cooling systems
will not deter the electrical generation growth in this country."
-------
13
REFERENCES
1) BatteHe-Northwest. 1967. Nuclear Power Plant Siting in the
Pacific Northwest, for the Bonneville Power Administration.
Contract No. 14-03-67868.
2) Converse, A. 0. 1967. Thermal Energy Disposal Methods for the
Proposed Nuclear Plant at Vernon. Dartmouth College, Hanover,
New Hampshire.
3) Federal Power Commission. 1967. Statistics of Privately Owned
Electric Utilities in the United States. S-186, Government
Printing Office.
4) Federal Power Commission. 1967. Statistics of Publicly Owned
Electric Utilities in the United States. S-188, Government
Printing Office.
5) Hauser, L. G. 1969. Cooling Water Requirements for the Growing
Thermal Generation Additions of the Electric Utility Industry.
American Power Conference, April 22-24, Chicago, Illinois.
6) Lof, 0. G. and J. C. Ward. 1968. Economic Considerations in
Thermal Discharge to Streams. National Symposium on Thermal
Pollution (II) August 14-16, Vanderbilt University, Nashville,
Tennessee.
7) Richards, R. T. 1967. Water Resources Planning: Its Influence on
Thermal Station Design. Annual Meeting of American Society of
Civil Engineers, October, New York.
8) Shade, W. R. and A. F. Smith. 1968. Discussion of Economic
Considerations in Thermal Discharge to Streams. National Symposium
on Thermal Pollution (II), August 14-16, Vanderbilt University,
Nashville, Tennessee.
9) Thon, J. G. 1967. Power Generation: Its Status and Outlook. Civil
Engineering, September, pp. 36-39.
-------
------- |