Environmental Assessment
of Alternative
Thermal Control Strategies
for the
Electric Power Industry
r
I
*
FINAL REPORT
for by
U.S. Environmental Protection Agency Energy Resources Co. Inc.
Office of Planning and Evaluation Cambridge, Massachusetts
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FINAL REPORT
ENVIRONMENTAL ASSESSMENT
OF ALTERNATIVE THERMAL CONTROL STRATEGIES
FOR THE ELECTRIC POWER INDUSTRY
CONTRACT # 68-01-2477
BY
ENERGY RESOURCES CO. INC.
CAMBRIDGE, MASSACHUSETTS
RICHARD H. ROSEN
VALERIE BENNETT
JOHN EDWARDS
ROBERT ELGIN
AND
MICHELE M. ZARUBICA
OFFICE OF PLANNING AND EVALUATION
ENVIRONMENTAL PROTECTION AGENCY
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PREFACE
The attached document Is a contractor's study prepared
in conjunction with the Office of Planning and Evaluation
of the U.S. Environmental Protection Agency (EPA). Its
purpose is to provide an environmental basis for evaluating
the potential economic impact of effluent limitations and
guidelines and standards of performance for thermal dis-
charges established by EPA pursuant to sections 301, 304(b)
and 306 of the Federal Water Pollution Control Act.
This study supplements the EPA technical "Development
Document" and "The Economic Analysis of Effluent Guidelines -
Steam Electric Powerplants," issued in conjunction with
the promulgation of guidelines and standards for point
sources within this industry category. The Development
Document surveys existing control methods and technologies
The economic study supplements that analysis by estimating
the broader economic effects (including increases in capital
requirements, price increases, continued viability of
affected plants, employment, industry growth and foreign
trade) of the required application of certain of these
technologies. This study attempts to measure the environ-
mental and economic trade-offs associated with alternative
levels of thermal controls.
This study has been submitted in fulfillment of
contract No. 68-01-2^71 by Energy Resources Co. Inc. Work
was completed as of December 197^.
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ACKNOWLEDGMENTS
The authors of this study would like to take this
opportunity to thank the many individuals who contributed
to this study, especially James Speyer, Walter Barber, and
Victor Kimm of the Environmental Protection Agency,
(Office of Planning and Evaluation); Howard Pifer,
James Glauthier, Michael Tennican, and John Weber, of
Temple, Barker and Sloane, Inc.; Bruce Egan of Environmental
Research and Technology, Inc.; and George Freeman,
General Counsel, Utility Water Act Group, and members of
the utility industry who furnished data for this study.
Responsibility for any errors or omissions remains
with the authors.
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This report has been reviewed by the Office of
Planning and Evaluation of the Environmental
Protection Agency and approved for publication.
Approval does not signify that the contents
necessarily reflect the views and policies of
the Environmental Protection Agency, nor does
mention of trade names or commercial products
constitute endorsement or recommendation for use.
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TABLE OF CONTENTS
PAGE
CHAPTER ONE
1.0
1.1
1.2
THERMAL POLLUTION AND THE
STEAM ELECTRIC INDUSTRY
Summary
Background - Statutory
Public Comments
1
7
10
CHAPTER TWO
2.0
2.1
2.1.1
2.1.2
2.1.3
2.1.4
2.1.5
2.1.6
2.2
2.3
2.3.1
2.3.2
2.3-3
THE STEAM ELECTRIC POWER INDUSTRY
The Changing Characteristics of 12
the Steam Electric Industry
Factors that Influence Environ- 14
mental Impact
Receiving Water Type 15
Safej.Qji.es on Rivers 19
Cooling Methods 19
Unit Size ^3
Heat Rate
Age and Capacity Factor 24
The Technology of Thermal 24
Pollution
Existing Thermal Abatement 29
Technologies and Methods of
Thermal Abatement
Sample Selection 31
Sample Description 32
Problems With F.P.C. Data 33
CHAPTER THREE ENVIRONMENTAL IMPACT OF THERMAL
POLLUTION AND POLLUTION ABATEMENT
3-1
3.2
Introduction
Effects of Waste Heat Discharges
49
49
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TABLE OF CONTENTS (Cont.)
PAGE
3.3 Ecology of Alternative Receiving 5-
Waters
3.3.1 Rivers 52
3.3.2 Lakes 55
3.3.3 Estuaries 58
3.3.4 Stability and Ecosystem Resilience 6l
3.4 Environmental Risk Attributable 62
to the Employment of Once-Through
Cooling
3.5 Air Pollution Effects 68
3.5.1 General 68
3.5.2 Drift Deposition From Evaporative 70
Cooling Systems
3.5.3 Formation of Secondary Pollutants 78
3.5.3.1 Definition of Potential Emissions 78
3.5.3.2 SO2 Oxidation Methods 80
Fogging and Visibility Changes
3.5.3.3 Characteristics of Sulfates 8l
3.5.3.4 Other Secondary Pollutants 8l
3.5.4 Fogging and Visibility Changes 82
3.5.5 Health Effects of Secondary Pol- 84
lutants Associated With the
Interaction of Evaporative Cool-
ing Systems and Combustion Plumes
3.5.5.1 Toxicity of Sulfur Decay Products 84
3.5.5.2 Epidemiology of Sulfur Decay 86
Products
3.5.5.3 Epidemiology of Nitrogen Decay 87
Products
3.5.5.4 Other Potential Toxic Substances 87
3.5.5.5 Conclusions 87
3.5.6 Regional Variations of Air Quality 87
Impact of Alternative Cooling
Syst ems
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TABLE OF CONTENTS (Cont.)
PAGE
CHAPTER FOUR
4.1
4.2
4.3
4.4
THE ECONOMICS OF THERMAL
POLLUTION ABATEMENT
Introduction
ERCO Data Analysis
Findings of Land Use and
Population Density Analysis
for 37 Power Plants
Methodology
100
102
103
104
CHAPTER FIVE
5-0
5.0.1
5.0.2
5.0.3
5-1
5-2
5.3
5.4
OPTION ANALYSIS
Introduction
Age Exemptions
Size Exemptions
Capacity Exemptions
Description of the Options,
Their Costs and Risks
Elaboration on Effect of
Final Option
Methodology of Estimating
Utility Industry
Distribution of the Units
Affected by the Option
112
112
112-
113
113
115
115
117
CHAPTER SIX
6.1
6.2
6.3
6.4
6.5
6.6
ALTERNATIVE USES FOR WASTE HEAT
Introduction
Commercial Uses of Waste Heat
and Low Temperature Heat
Agriculture
Aquaculture
Waste Treatment
Marketing Steam, Space Heating
and Air Conditioning
120
123
124
134
139
144
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TABLE OF CONTENTS (Cont.)
PAGE
6.7 Snow and Ice Melting iky
6.8 Vehicle Propulsion 151
6.9 Recreational Uses of Waste Heat 152
6.10 Total Energy Complex 151|
APPENDIX I DATA ON OPTIONS FOR TBS 1-1
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LIST OF TABLES
TABLE 1-1
TABLE 2-1
TABLE 3-1
TABLE 3-2
TABLE 3-3
TABLE 3-4
TABLE 3-5
TABLE 3-6
TABLE 3-7
TABLE 3-8
TABLE 4-1
TABLE 4-2
TABLE 4-3
TABLE 5-1
TABLE 5-2
TABLE 6-1
TABLE 6-2
Page
Option Costs and Risk 4
in Percent
ERCO Utility Sample 35
% of Safe Zone Fraction Dectile 67
Sensitivity Analysis 69
Range of Dissolved Solids 72
for Various Sources
Common Additives to Clr- 74
culating Waters
Average Annual Chromate 76
Deposition Rates Close to
Cooling Towers
Environmental Factors 77
Trace Metal Emission Factors 79
Average Fog Concentration Caused 83
by Cooling Tower Operations and
Corresponding Visibilities
Land Availability Data - 109
35 Power Plants
Land Availability for Install- 110
ment of Cooling Towers
Plants With Installed Cooling 111
Towers
Growth by Entire Industry 116
Growth by Risk Type 118
Energy Use Estimate 122
Results of Field Experiment 125
Designed to Measure the Effect
of Warming the Soil Above Its
Natural Temperature
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LIST OF TABLES (Cont.)
TABLE 6-3
TABLE 6-1
TABLE 6-5
TABLE 6-6
TABLE 6-7
TABLE 6-8
TABLE 6-9
TABLE 6-10
TABLE 6-11
TABLE 6-12
TABLE 6-13
TABLE 6-11
Comparative Cost Per Acre
Effects of Soil Heating and
Subirrigation on Vegetable
Production, Muscle Shoals,
Alabama, 1971
A Comparison of Marketable
Crop Yields
Thermal Aquaculture Land and
Waste Heat Utilization
Costs of Conventional System
With Natural Water Supply and
Primary and Secondary Treat-
ment of Sewage
Costs of Conventional Supply
and Strict Pollution Stan-
dards Requiring More Complete
Removal of Organics From Waste
Estimated Cost for Sewage
Disposal and Water Recycle
System
Average Revenue Received by
District Heating Companies
Estimates of Steam Pressures
and Pressure Distributions
Required in 1980
Types of Fuel Purchased in
1962 by the Six Industries,
Heat Values, and Total Heat
Values
Cost Estimates for a City
Sidewalk Snow-Melting System
Based on 1969 Costs
Energy Available From Typical
Sources for Automobile Propulsion
Page
126
127
130
137
111
112
113
115
117
118
150
151
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LIST OF TABLES (Cont.)
Page
TABLE 6-15 Energy Production and Loads 155
for Reference City
TABLE 6-16 Unit Heat Production Costs 156
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LIST OF FIGURES
FIGURE 1.1
FIGURE 1.2
FIGURE 2.1
FIGURE 2.2
FIGURE 2.3
FIGURE 2.4
FIGURE 2.5
FIGURE 2.6
FIGURE 2.7
FIGURE 3.1
FIGURE 3-2
FIGURE 3.3
FIGURE 3.4
FIGURE 3-5
FIGURE 3.6
FIGURE 3.7
Page
Receiving Water Type - 3
Open Cycle
Comparative Environmental 6
Risks and Costs
Receiving Water Type - 17
All Plants
Safezone on Rivers Used for 18
Once-Through Cooling
Cooling Method 21
Unit Size 22
Heat Rate 25
1978 Capacity Factor 27
Age 28
Safezone 64
Deposition Rates From Wet 71
Cooling Systems as a Function
of Downwind Distance Under
Neutral Atmospheric Conditions
Annual Prevailing Wind Direction 89
and Mean Wind Speed
Potential for Adverse Effects 92
of Fogging from Cooling Towers
Mean Annual Mixing Heights 93
in Hundreds of Meters
Mean Annual Afternoon 94
Morning Mixing Heights
in Hundreds of Meters
Average Daily January 96
Temperature
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LIST OF FIGURES (Cont.)
Page
FIGURE 3-8
FIGURE 3.9
FIGURE 6.1
FIGURE 6.2
FIGURE 6.3
FIGURE 6.4
FIGURE 6.5
FIGURE 6.6
Average Daily August 97
Temperature
Mean Annual Relative Humidity 98
Effect of Air Temperature on 131
Swine Feed Consumption and
Time to Market
Livestock Waste Recycling System 133
Generating Station - Total 133
Agricultural System
Effect of Temperature on 13^
Growth or Production of Food
Animals
Conventional Water Supply 1^1
and Sewage Disposal
Conventional Water Supply 1^2
With Tertiary Treatment of
Wastes
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CHAPTER ONE
THERMAL POLLUTION AND THE STEAM ELECTRIC INDUSTRY
lo 0 Summary
On the 4th of March, 1974, the Environmental Protec-
tion Agency promulgated proposed guidelines for steam-
electric power facilitieso These guidelines were reviewed
by a variety of public and private respondents„ The guide-
lines consisted of the proposed rules, together with a
manual for performing certain analyses to determine whether
or not heat releases at particular sites lead to a reduc-
tion in environmental quality„ The Initial guidelines as
proposed by EPA were felt by the reviewers to reflect an
extreme position, in that the costs of the guidelines were
thought to be excessive in relationship to the benefits.
In fact, the initial proposal maximized cost and minimized
environmental risks„ However, because of the uncertain-
ties associated with reducing waste heat discharges in
terms of improved biological effects on the nation's re-
ceiving waters and the high cost of the March 4th proposal,
the Environmental Protection Agency decided to examine
other bases for granting variances to thermal power plants0
The study of the implications of alternative thermal
guidelines involved both the measurement of the risk as-
sociated with the release of waste heat at particular sites,
and a careful study of the electric power industry in or-
der to see if there was a rational basis for formulating
policy to subcategorize the industry on a basis different
from the March 4th proposal.
The results of these two work efforts were related
in a comparative analysis of each proposed policy option
that permitted decision-makers to relate differences in
cost to Improvements in environmental quality as measured
by reductions in risk. Data was collected from a vari-
ety of sources, including a sample of over 200 power
plants, the Federal Power Commission, The United States
Geological Survey and the Environmental Protection Agencyo
These data were first employed to describe the industry
in terms of its production characteristics, nature of the
waters into which pollution was discharged, and other as-
pects which reflect upon its economic efficiency0
-1-
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Figure 1.1 illustrates the distribution of open-cycle
power plants by receiving water type. It shows that the
relative Importance of lakes as discharge points for open-
cycle steam-electric power plants is increasing, reflecting
the significant requirements for cooling water from nuclear
power plants built or planned in the Great Lakes Region.
Rivers have decreased in their relative importance,- reflect-
ing the lack of suitable riverine sites for discharge, but
nevertheless will represent in 1977, almost half of the
population of power plants. At the same time that the
relative importance of river sites has declined, coastal
and estuary sites have been increasing. Separate studies
of plants on lakes and estuaries were undertaken to de-
termine the likely impact of waste heat releases on these
bodies of water,, Detailed investigation of the river sites
was done employing local data and a simulation of the re-
lationship between river flow and water use by over 100
power plants was performed,. The results of this analysis
discussed below in Chapter 3 are summarized in Figure 1„2
which illustrates the relationship between the environment-
al risks and the choice of decision criteria to establish
that environmental risk.
In Table 1-1 the variety of options given serious con-
sideration in the course of this analysis is presented,,
The cost data referred to in this Table were developed
from a detailed series of reviews of power plant cost es-
timates. The risk numbers which are also observed in this
Table were derived from the aforementioned simulation
analysis and specific studies of non-river plants. Cover-
age estimates of the guidelines were based on judgments
regarding the number of plants which would become exempt
as a result of the preparation and subsequent approval of
biological demonstrations undertaken under the provisions
of section 316.*
*Section 316 is a provision in the Federal Water Pollution
Control Act as amended in 1972 (PL 92-500) which provides
that facilities which can show that their waste heat re-
leases do "no appreciable harm" to the environment can be
exempt, as long as a demonstration to that effect has been
made and approved by the Environmental Protection Agency.
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RECEIVING WATER TYPE - OPEN CYCLE
100%
Municipal
aru
Estuaries
60%
Lakes
Rivers
20%
0%
1950
I960' "
Figure 1.1
-3-
1970 1977
YEAR OF INSTALLATION
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OPTION COSTS AMD RISK IN PERCENT
Before
After
316(a)
316(a)
OPTIONS
COST1
COST
RISK2
RISK3
MARCH OPTION
Small plants or before 1950
92*
31*
3*
1*
EARLY SUMMER OPTIONS
A Small, 1956, 10$
69*
25*
23*
1*
B Small, 1961, 10*
57
23
29
5
C 300 Mw, 1956, HO*
19
17
18
8
D 300 Mw, 1961, HO?
13
17
18
8
E 1956, 10*
69
25
23
1
F 1961, H0*
57
23
29
5
a 1961, 20*
62
25
27
5
H 1972
26
11
65
11
MISCELLANEOUS OPTIONS
300 Mw, 1961
"3*
17*
18*
9
60*
53
20
33
6
150 Mw, 1961
58
23
32
6
Small, 100 Mw, 1961
60
21
29
5
Small, 100 Mw, 1956
73
27
22
1
1961
62
25
27
5
200 Mw, 1961, 10*
50
21
36
6
150 Mw, 1961, 10*
51
22
33
6
200 Mw, 1961
51
21
35
6
150 Mw, 1961
58
23
32
6
Small, 1965, 20*
50
20
10
7
Small, 1965
51
20
10
7
Small, I960
62
25
27
5
Small, 1955
80
30
11
2
SEPTEMBER 23, OPTIONS
1970
31*
13*
58*
10*
1971
17
7
75
13
1978 or 1979
0
0
100
17
Repeated from above
March (Small, 1950)
92*
31*
3*
1*
Early Summer A (Small, 1956, 10*]
69
25
23
1
Early Summer H (1972)
26
11
65
11
FINAL OPTION
26*
11*
63*
11 0*
VARIATIONS ON SIZE CUTOFF
FOR 1970 - 1973 IN FINAL
10 1*
10 8
0 Mw, (1 e , pure 1970)
30 8*
12 8*
58 0*
300 Mw
28 7
11 6
61 8
500 llw (actual option)
26 1
11.2
62 8
11 0
11 A
700 Mw
21 8
9 9
66 1
11 0
1300 Mw, (i e , pure 1971)
16 5
7 3
75 0
13 1
The options with their associated costs and risks
are given using the following shorthand
Units in plants of les3 than
25 megawatts capacity
or in private or public utilities of less
than 150
megawatts
capacity are "small".
Units with installed generating capacity less
than
100 megawatts are called "100 Mw"
Units built before i960 are called "I960" units
Units operating at less than
140 percent of full
capacity over a year are called "10*".
TABLE 1-1
Estimated baseline capital expenditures between 197
and 1933 are $179 0 billion Baseline conditions are
specified by the National Power Survey (TAC - Finance)
without pollution control equipment See EPA document
"Economic Impact of Effluent Guidelines - Electric
Utility Industry" 100* would be the cost of retro-
fitting all extant olants with cooling tower by 1983,
about $30 billion
2100* is the total production at high risk sites in 1978
^Ratio of exempted high risk production to total
production In 1983
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The March option, exempting all small plants and all plants
built before 1950, had the lowest risk and the highest cost,
while options proposed by public utilities in public comment
had the lowest cost and the highest risks. The final option
increased risk from the March option somewhat and reduced
costs more dramatically, reflecting that in the short run
cost savings are likely to produce benefits which are more
important than those to be achieved as a result of a reduction
in environmental risk. The final decision permitted trade-
offs between cost to the society and environmental benefits
measured by risk-reduction. This result is attributable
to the fact that technology is changing dramatically in the
electric power Industry and that in the future, (by 1983)
a large proportion of the present generation which is pre-
sently high risk, will be replaced by a generation thermo-
dynamically and locationally more efficient, from an environ-
mental perspective. The EPA also chose to accept higher
risk levels because high risk plants would be covered by
water quality standards.
It is clear from an observation of Table 1-1 that cost
and risk reduction are inversely related to one another.
That is to say that a reduction in risk is linked to an
increase in cost, and that these tend to be proportionate
so one cannot reduce costs a lot without increasing risk a
lot. The early options considered by EPA are based upon
subcategorization of the industry to terms of age and load
factor. EPA felt that old plants which were approaching
obsolesence could be ignored in this rule-making as they
would be replaced by newer plants. Load factor was also
taken into account as a discriminant in the early analysis.
Here it was felt that plants which were very inefficient
would soon be replaced because load could be conceived to
be a measure of their efficiency. The collection of options
labeled 'miscellaneous options' revolved around exemptions
based on size and age, while the later option considered
exempting newer, larger plants which were built more recently.
The final option reflects the high costs associated with
retrofitting old plants, but takes into account the poten-
tially serious adverse environmental affect associated
with the operation of very large units.
The methodology and the mathematical models employed
for this work effort have made it possible to perform, in
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COMPARATIVE ENVIRONMENTAL RISKS AND COSTS
+ FINAL OPTION
* SEPTEMBER 23, OPTIONS
• OTHER OPTIONS
Dominant Options
CO
H
CC
+
E-<
cn
o
o
100
lJ0
60
80
0
20
COST (% of Maximum)"''
FIGURE 1.2
¦'¦The total cost from which the proportion cost associated
with each option may be derived is thirty (30) billion dollars.
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a preliminary fashion, the necessary analysis which permits
policymakers to evaluate the trade-off between reduction
of risk and cost. Since the Environmental Protection Agency
is required to take these issues into account for the best
available control technology, this work effort represents
the first effort to formalize this analysis and provides
the bases for the performance of similar work efforts on
other environmental regulations.
1.1 Background - Statutory
P.L. 92-500, the Federal Water Pollution Control Act
Amendments of 1972, provides under Section 304(b) for the
Administrator to publish regulations providing guidelines
for effluent limitations. Section 304(c) provides for the
Administrator to issue information on the processes,
procedures, or operating methods which result in the
elimination or reduction of the discharge of pollutants
to implement standards of performance. Section 301(a)
requires effluent limitations for point sources to apply
the best practicable control technology currently avail-
able as defined by the Administrator by July 1, 1977 and
to apply the best available technology economically achiev-
able not later than July 1, 1983-
On March 4, 1974, EPA published in the Federal Register
the Proposed Effluent Limitations Guidelines and Standards
for the Steam-Electric Power Generating Point Source Cate-
gory .
The two major types of pollution to be controlled
by the guidelines are thermal and chemical. Congress
had been concerned with the effects of thermal pollution
since the 1968 hearings in the subject before the Sub-
committee on Air and Water Pollution, Committee on Public
Works, U.S. Senate, 90th Congress. P.L. 92-500 Section
104(t) required that the EPA conduct studies of the effects
and methods of control of thermal discharges and to report
to the Congress within 270 days after enactment on the
results of these studies. The guidelines were developed
from the "Development Document for Effluent Limitation
Guidelines and Standards of Performance - Steam-Electric
Power Plants", EPA Contract No. 68-01-1512 by Burns and
Roe, Inc.
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The guidelines provided that both the BPCTl and BATEA2
to control thermal pollution, could only be met by one suit-
able technology: evaporative external cooling to achieve
essentially no discharge of heat into waterways except for
cold-side blowdown, in a closed, recirculating cooling sys-
tem. The mechanical draft evaporative cooling tower was
used as the basis for all the analysis of costs and bene-
fits o No discharge of heat except for cold-side blowdown
was to be permitted for all large base-load units completed
after July 1, 1977° Exemptions were to be given for units
with insufficient land available for mechanical draft tow-
erSo Under certain circumstances water drift from mechanical
draft towers would have had adverse environmental impacts„
Plants employing salt water as a coolant would also have
been exempt. The dates for achieving compliance were set
at July 1, 1978 for units whose capacity was 500mw and
greater; July 1, 1979 for capacity between 300 and 499mw;
July 1, 1980 for capacity under 299 mw; and July 1, 1983
for small plants with a capacity less than 25mw or in a
system with a capacity less than 150mw„
1 Best Practicable Control Technology currently available
for 1977 -In assessing BPCT a balancing test between
total cost and effluent reduction benefits are made,
in some instances, this test may eliminate the applica-
tion of technology which is high in cost in comparison
to the minimal reduction in pollution which might be
achieved. Page 9, The National Water Permit Program,
EPA, Office of Enforcement and General Counsel, July 1,
1973c
2 Best Available Technology Economically Achievable by
1983 is the highest degree of technology that has been
demonstrated as capable of being designed for plant
operation, so that costs for this treatment may be much
higher than for treatment by "best practicable" tech-
nology 0
-8-
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Along with the guidelines was issued a "Development
Document for Proposed Effluent Limitations Guidelines and
New Source Performance Standards for the Steam Electric
Power Generating Point Source Category", estimating the
economic impact by 1983 of the proposed thermal effluent
limitations guidelines with 316(a) exemptions as follows:
Total Capital required is $5.2 billion
whjch is 2.9 percent of the base capital
required.
Cost to consumers would be only $0„4 mills
per kwh per year, which is 1„7 percent of
the base cost to consumers.
The average incremental costs of the application of
mechanical draft evaporative cooling towers to base-load
units to achieve no discharge of heat, except for blowdown,
were estimated as follows;1
1. Production costs: lh% of base
2. Capital costs: 12$ of base
3. Fuel consumption: 2% of base
4. Capacity reduction: 2>% of base
The guidelines continued to add that Section 316(a)
of the Act allows for exemptions to the proposed limita-
tions on heat, in a case-by-case basis, based on the con-
sideration of environmental impact0
EPA estimated, based on a survey of EPA regional per-
sonnel, that approximately one-half to two-thirds of the
steam electric power plants not already achieving "no therm-
al discharge" are not now in violation of present or pro-
jected thermal environmental criteria.2
The Utilities Water Action Group survey of the indus-
try concluded that only 37% of the industry believed they
qualified for a 316(a) exemption under the "no appreciable
harm" test, while 23% expected to receive an exemption under
the "representative and important species" test with the
EPA proposed manual in effect.,
i„ The costs for the proposed effluent guidelines include
costs for chemical pollution abatement„
2o Federal Register, Vole, 39, No„ 43, p. 8300.
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The proposed rules for 316(a) exemptions, authorizing
alternative effluent limitations upon demonstration that
any such alternative effluent limitation also assures the
protection and propagation of a balanced, indigenous aquatic
population, required an applicant to produce sufficient
evidence to demonstrate that no appreciable harm has re-
sulted from the previous operation of the existing source,
or to demonstrate that the discharge will assure the pro-
tection and propagation of one or more "representative,
important species."
102 Public Comments
Public comments were extremely critical of both the
Proposed Effluent Guidelines the 316(a) exemption pro-
cedure, and the draft guidance manual. The electric
utilities issued a four volume critique of the proposed
guidelineso Their major criticisms were the following:
1. Costs for meeting the guidelines far outweighed
conceivable benefits:
a„ the EPA made no attempt to measure bene-
fits
b. costs were substantially under-estimated
because of underestimation of outage
costs, other environmental effects, new
plant capital costs, replacement capacity
operating costs, cost of capital, incre-
mental cost of closed-cycle cooling, and
over estimation of 316(a) exemptions,,
20 It was misleading to label any thermal increase
in a water body as pollution,,
3. Other environmental effects of closed-cycle
cooling had been overlooked, including:
a. increased water use for closed-cycle
cooling
b. noise effects of cooling towers
c. unclear procedures for determining land
availability for closed-cycle cooling
-10-
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d. other air pollution and meteorological ef-
fects were ignored0
40 The time schedule for implementing 1983 require-
ments was considered lnfeaslble0 There was not"
enough time permitted for 3167a) demonstrations
and meeting the July 1, 1978 dead]ine for units
over 500 mw„
The criticism o_f 316(a) and the Draft Guidance Manual
took two forms:
1. The proposed regulations did not reckon with the
severely limited time within which 316(a) de-
terminations were to be made. The compliance
dates of July 1, 1977 and July 1, 1978 for
achieving water quality standards and 'best
available technology' were in conflict with the
time required to perform a 316(a) demonstration0
20 The methods prescribed for demonstrating com-
pliance with 316(a) were infeasible0 Only
existing plants with several years operating
experience on unpolluted water bodies were
eligible for a "no appreciable harm" demonstra-
tion. Other plants that must fill out the
Thermal Tolerance Matrix would have to collect
data requiring several years of laboratory and
field investigation by hundreds of biologists0
Costs for a detailed 316(a) demonstration could
run as high as $2 million each.
Because of the intensity of the public comments, EPA
decided to undertake a re-evaluation of the proposed ef-
fluent guidelineso Before one can understand the nature
of the problem, it is necessary to accurately describe the
steam-electric power industry in all its major dimensions~
-11-
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CHAPTER TWO
THE STEAM - ELECTRIC POWER INDUSTRY
2.0 The Changing Characteristics of the Steam-Electric
Industry
Electric production capacity has grown rapidly through-
out the twentieth century. Aside from the early years of the
Great Depression, the rule of thumb that electric capacity
doubled every ten years is held to closely. But doubling
does not imply duplicating. In many respects the new plants
are very different from the old. The rapid growth promotes
rapid changes because half of the operating plants have
been built in the last ten years.
Important technological changes have taken place in
the industry as a result of advances in metallurgical science,
boiler design and combustion. These advances have acceler-
ated the replacement of small, old facilities by systems
which are thermodynamically far more efficient.
Two major technological trends have been noticeable
in the steam-electric industry in the last half century.
The period 1920-1960 was marked by major increases in ef-
ficiency with a concomitant decline in heat rejection ratio.
After i960, technological improvement in boilers led to an
increase in the average size of generators, coupled with
increased heat rejection into receiving waters. Since
nuclear units have a higher rate of heat rejection into
receiving waters than fossil fuel plants, the future picture
would be one of increasing thermal pollution problems if
this effluent had remained unregulated.
Efficiency
Until I960, the efficiency of electrical production
had been increasing rapidly over time. Between 1920 and
I960 technologically feasible pressures increased 10-fold
to 3,400 psi, temperatures doubled to over 1,000°F and
the average efficiency nearly tripled to 32£. Although
electrical consumption doubled each decade in this period,
the environmental impact was greatly reduced by the im-
provements in efficiency. While the average plant in 1920
-12-
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rejected 2 units of energy into the air and 6 units into
water for each unit converted into electricity, the I960
rejection rate was 1.5 units of energy into water for
each unit converted into electricity. As a result the
nearly 16-fold increase in electrical production increased
the heat rejected into waterways only about 4-fold; while
this heat increase is large, it amounts to less than 2% an-
nual growth per capita and is similar to the growth of the
whole economy during the period. An equally important fac-
tor in measuring environmental impact is the choice of
site, some of which suffer minor impact because of flow
characteristics on the composition of biota; while others,
because of the presence of particular species or signifi-
cant variability in flow, are susceptible to major environ-
mental impact.
Since I960, however, the improvement in efficiency has
been negligible. One unit was built with a maximum pres-
sure of 5,000 psi, temperatures up to 1,200°F and double
reheating providing an efficiency of H0%, but reliability
was a problem. Most other new fossil units have shown ef-
ficiencies of about 36$. The common light water nuclear
units have an efficiency of 32% and since there are no
stack losses, 2 units of energy must be rejected into the
cooling water for each unit turned into electricity.^
Few higher efficiency nuclear units are expected until at
least the mid 1980's. Since nuclear units will soon be
providing over one-half the capacity additions, the demand
for cooling water will grow about 6% per capita faster
than electrical demand.
Boiler Technology
As prospective savings from improved efficiency have
declined, the utilities have utilized a breakthrough in
boiler technology in the 1950's to reap economies of scale.
Maximum boiler and generator unit sizes increased 6-fold
between 1955 and 1972 to 1,150 Mw electrical with only a
doubling of employees per unit. Although many plants con-
taining several of these large units are now planned, the
1. Other technologies may have higher rates of efficiency
with less effect on the environment.
-13-
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technology is not without environmental costs since very
few streams, lakes, or bays in the United States are large
enough to cool these plants without undergoing larger tem-
perature rises. If a water body does accomodate to higher
temperatures, the problem of cold-shock is increased since
maintenance cannot be rotated among a number of small units
Return to a pattern of increasing efficiency which can
compensate for increased demand is not likely for at least
several decades, although combined gas turbine and steam-
electric systems might approach ^5% efficiency within 10
years. High temperature gas reactors are near ^0%; breeder
reactors, magnetohydrodynamic and electrogasdynamic genera-
tors, and fusion reactors are at least decades from be-
coming a major source of energy. Geotbermal generation
and solar energy create more waste heat than present gen-
erators; their great advantage lies in fossil fuel savings.
Fuel cells promise great reductions in waste heat and
may be useful for temporary storage, but appear impractical
with natural fluids. Nevertheless, all the above are
expected to account for less than 5% of the new generation
added in the next 10 years.
Thermal Discharges
The early sixties appear to have marked a watershed in
water use by electric utilities. Until that time heat dis-
charge per unit of electrical heat production had been
declining, after that date it began increasing. While
many new plants have chosen closed cycle cooling systems
because of complete depletion of water sites near the
demand centers or fuel supplies, this tendency alone is
unlikely to protect the remaining sites from severe heat
loads in the future.
2.1 The Factors That Influence Environmental Impact
The factors that directly influence the environmental
impact of the heated water discharges are (1) the location
of the discharge (2) the amount of the discharge (3) the
temperature of the discharge and (4) the frequency of the
discharge. The power plant characteristics that directly
affect these parameters are (i) the location of the power
plant (ii) whether the plant uses the water directly or
recycles it (iii) the efficiency of generation or heat
-14-
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rate and (iv) the total amount of generation. Other charac-
teristics that may correlate closely with some of the above,
or influence cost are unit size, capacity factor, age, ana
fuel type.
The following graphs show the changes that have occurred
over the last 30 years. The composition of the plants and
units added in a single year varies too erratically to make
a useful graph. Instead, these graphs show the composition
of all plants built before the year given on the horizontal
axis. The proportion of the installed generating capacity
(I.G.C.) with each characteristic is given along the verti-
cal axis. Two different types of graphs are used: for dis-
crete characteristics such as fuel type, the vertical dis-
tance between two lines gives the fraction of generating
capacity with the labeled characteristic. For continuous
characteristics such as unit size, each line gives the
fraction of the industry with values up to the values label-
ing the line.
These graphs were derived from ERCO's sample of 396
steam-electric utility generating units. The data for the
last 10 years should be accurate to about 5% of the vertical
axis. For earlier years, the data is less accurate because
a considerable number of plants in operation during the
1950's have retired and were not included in the ERCO sample.
Nonetheless the graphs are expected to indicate recent trends.
2.1.1 Receiving Water Type
Heat in the air tends to dissipate so rapidly that
there is not yet major concern about the present levels of
dry heat that radiate from the plant or go up the stack.
Thus damage from thermal pollution depends on the method by
which the heat enters and leaves the receiving water body.
On a river, most of the heat is mixed downstream into the
river flow eventually being dissipated to the atmosphere;
on a lake, most of the heat is dissipated into the air by
conduction and evaporation; on an estuary the heat is re-
moved in alternating directions by tidal flows; and in the
open ocean the heat is removed by natural currents or con-
vection. About 10% of the plants use municipal or indus-
trial sewage water, aquaducts, or other combined techniques
so that most of the heat is dissipated into the air before
entering a navigable waterway. These 10% are exempt because
they don't discharge heat into navigable waterways.
The damage from the heat clearly depends on the type
of receiving water and also on its size. If the water
-15-
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bodies are large, many animals can avoid the hottest areas
and those that are harmed may be rapidly replenished by
others nearby. If the body is small enough so that an en-
tire habitat is strongly heated, (for example, the entire
lake surface or river cross-section) then a few days damage
may take years to reverse.1
Analysis of Figure 2.1 shows that the majority of power
plants have always been on rivers and many of the remainder
have been on lakes. About 10% use wells, city water, sewage
water, or other sources not directly related to navigable
waterways. Only a very few use water from the open ocean.
The only significant trend is the increase of lake sites at
the expense of river sites. By 1978 and by 19B3, lake sites
will be approximately 28%, while river sites will decline
to 53% of the total.
p
Figure l.lc shows the receiving water type for plants
using once-through cooling. Wells and other sources are
negligible in this case. A much more pronounced trend is
shown in this case with estuary sites growing slowly, lake
sites growing rapidly, and river sites decreasing rapidly.
Much of this trend is probably due to the large size of new
plants. The Great Lakes and the ocean are very large com-
pared to the water needs of any power plants now contemplated,
whereas only the Mississippi and Columbia River basins have
much larger flows all year than the largest plants require
for plant draft.
1. MacArthur, R.H., Geographical Ecology, New York, Haroer
and Row, 1972 , pp~ 1^4-1^3.
Naylor, E., "Effects of Heated Effluents from Marine
and Estuarine Organisms". Ad. Mar. Biol. 3, pp. 63-103,
1965.
2. See page 3
-16-
-------
RECEIVING WATER TYPE - ALL PLANTS
Ocean
Wells
Municipal
Estuaries
Lakes
o
60%
Rivers
o
Q%
1980
I960
1965
1955
1970
1975
YEAR OF INSTALLATION
Figure 2.1
-17-
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SAFEZONE ON RIVERS USED FOR ONCE THROUGH
COOLING
100S
>H
Eh
M
O
<
Oh
-------
2.1.2 Safezones on Rivers
Figure 2.2 shows that a pronounced trend in safezones
(defined in Chapter 3) is not exhibited over the last 20
years, mainly because relatively few once-through river
plants are being built (up only 25% in the final decade).
Placing larger, new units at an old site necessarily reduces
the safezone, but this is counterbalanced by the increased
attention given to locating on sufficiently large rivers
and both economic and environmental constraints forcing
the largest plants to use closed cycle cooling.
2.1.3 Cooling Method
Heat may be rejected from the cooling water at three
different stages: (1) with once-through cooling, the
heated water is returned directly to the receiving water
body; (2) with helper systems, all or part of the heated
water is partially cooled all or part of the time by a
tower, pond, or ditch with spray before returning to the
receiving water body; (3) with true closed cycle cooling,
nearly all the water is cooled by a tower or pond and then
recycled through the condenser. The first method may cause
mortality to both organisms drawn through the plant and those
near the outfall; while the second greatly reduces damage
near the outfall, but may considerably increase damage to
those drawn through the plant; and the third generally
eliminates thermal damage to the water body- all organisms
drawn through the plant are killed but their number is small
since the make-up water needs are only a few percent of the
water used by either of the other methods.
An indirect but sometimes very important effect on the
rivers due to switching to closed cycle systems is the change
in the principle by which heat is transferred to the atmos-
phere and the quantity of water required. The effect varies
considerably in the different climatic regions but in general
terms it can be said that about half of the heat discharged
to a river, or well dispersed in a large lake, results in
evaporative heat transfer while the other half transfers to
the atmosphere by conduction, convection, and radiation. With
cooling towers and ponds about three-fourths of the heat
transfer occurs due to evaporation. Further, an artificial
pond built for cooling the plant heated effluent can result
in additional water requirements due to enhanced natural
evaporation of the impounded water. However, the ability
of a pond to store surplus runoff from the wet season for
-19-
-------
use in the dry season can often completely compensate for
added evaporation. Changing from once-through salt water
cooling to a fresh water tower results in an enormous per-
centage increase in fresh water consumption, but this is
unlikely to be required to meet EPA regulations. Overall,
it appears that no more than a 30% increase in evaporation
water loss could result from a massive increase in closed
cycle cooling.
The closed cycle cooling methods with significant
present use are natural and mechanical draft wet towers,
ponds, and spray ponds. In the towers, the hot water drips
over a series of slats or flows in thin sheets over parallel
sheets, and is cooled by flowing air.1 " In a mechanical draft
tower, the air is pushed or pulled through by large fans.
In a natural draft tower, the air is pulled through by the
buoyant effect of the heat and water vaoor gained from the
cooling process in a large chimney - often over 300 ft.
high. In a spray pond, the air flows under natural breezes
and the water recirculates through fountains of various de-
signs to increase evaporation.^ In a cooling pond, the
water is not broken up as in all the other cases. A large
surface area comes instead from a large pond area, generally
over an acre per megawatt of capacity. All plants using
closed cycle cooling (and coldside blowdown) are exempt from
further thermal regulation.
It is known that the industry is rapidly being forced
to go to closed cycle cooling. Figure 2.3 is surprising
in its indication of the method by which it is being ac-
complished. Cooling ponds represent approximately 4% of
the cooling capacity employed by industry (although ponds
will be 7$ by 1978). Mechanical draft cooling towers have
also been nearly constant at just over 10% of the industry
for 20 years. Practically all the net percent increase in
closed cycle cooling has been due to the rapid growth in
natural draft cooling towers during the 1970's. In many
1. A variety of tower packings are feasible which can
effect the cost-effectiveness of the facility.
2. There are three major types of spray ponds:
1. Elevated sprays
2. Floating spray nozzles
3. Rotating disks
-20-
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COOLING METHOD
100%
Pond
Spray Pond
Mechanical
Draft
elper
atural
\ Draft
Once
Through
I960
1965
1955
1980
1970
1975
YEAR OF INSTALLATION
Figure 2.3
-21-
-------
PERCENT OF INSTALLED GENERATING CAPACITY
-------
cases the decreased energy penalty, 0 & M costs, land
use, fogging, drift, and noise compensate for the larger cap-
ital cost of natural draft compared to mechanical draft towers.
2.1.4 Unit Size
The only direct effect of unit size on thermal pollution
is during breakdown and maintenance. When a single-unit plant
is shut down for maintenance, all of its thermal effluent
ceases. The temperature near the cooling water outfall may
rapidly drop 10° or 20°F. The resulting "cold shock" may be
fatal to organisms that have acclimated to the higher outfall
temperatures. If many smaller units are used, the temperature
changes on shutdown of one unit are much less.
A number of indirect effects of unit size may be important.
The small units tend to be older, less heavily loaded, and less
efficient. The administrative costs of monitoring them are
much higher and the conversion costs moderately higher per
unit of capacity. Typically the cost for small units would be
over twice as large for a given reduction in environmental im-
pact. Figure 2.4 shows average unit size growing continuously,
although technological breakthroughs have been required to in-
crease the size of the largest units. The total number of
steam-electric units seems likely to remain between 2000 and
3000 for the entire second half of the twentieth century.
2.1.5 Heat Rate
The heat rate measures the amount of fuel that must be
burned for a unit of electricity produced, commonly given as
British Thermal Units per killowatt hour. Units built since
I960 nearly all have heat rates within a 20% range, with
nuclear units at the top of the range.
2.1.6 Age and Capacity Factors
The capacity factor is the ratio of net generation to
generating capacity, so high capacity factors correlate with
the cost/benefit ratio because the most efficient plants will
be used more. But capacity factor, size, space, and heat
rate all correlate well with age. The main difference in
capacity factor is between fossil and nuclear plants and
the higher heat rate of nuclear plants cancels out their
advantage in high capacity factor. Because nuclear plants
reject more heat to the aquatic environment per kwhr of out-
put, their highest efficiencies frequently have little
-23-
-------
effect in terms of heat loads. As a result, no efficiency
gain from the shift in technology is realized unless the
nuclear plant is replacing a very inefficient non-nuclear
facility.
Figure 2.6 shows that the old plants rapidly decrease
in importance as new plants are built. The solid lines give
the fraction of capacity while the dashed lines give the
fraction of annual net generation.
Unlike the previous graphs, Figure 2.7 does not repre-
sent the industry composition at each year given; showing
instead the expected loading in 1978 of that fraction of
the industry built before the given year.
(1) Most of the construction of plants that are still
planning to use once-through cooling will be on lakes and
coastal areas, although a large majority of the old plants
were on rivers.
(2) Nearly all the percentage growth in closed cycle
cooling is accounted for by natural draft cooling towers.
(3) The rapid growth in generating capacity has not
required any increase in the number of units built each year;
the new units have just become larger in approximately the
same proportion with the growth.
(4) The efficiency of new units has changed negligibly
in the last decade, after half a century of rapid improve-
ment. The environmental impact of replacing a small, old
unit with a larger, new unit is therefore greater than in the
past.
2.2 The Technology of Thermal Pollution
Any power plant that generates power from heat (either
from burning fossil fuel or fissioning uranium) must have a
place to reject heat because it is impossible to change all
the heat into electricity with no waste.
In the case of gas turbines, the combustion products
are exhausted directly into the atmosphere at about 1,000°F.
In the case of steam turbines, the cost of boiler water and
the low-pressure of steam at ambient temperature have made
it impractical and inefficient since 1910 to exhaust the steam
-2k-
-------
PERCENT INSTALLED GENERATING CAPACITY
-------
directly into the atmosphere. The steam must instead be lique-
fied in a condenser and recycled. In nearly all cases the
condenser is cooled by a second stream of water.
The heat added to this second stream of water must soon
be rejected to the atmosphere and ultimately radiate to
outer space. The pathway the heat takes from the condenser
to the atmosphere determines the energy penalty, direct
costs, and environmental risks. With large costs and energy
penalty but no environmental risk (other than the indirect
but important effect of more fuel burned to compensate for
the energy penalty) the heat may be transferred directly to
the air in a dry cooling tower that operates on the same
principle as a car radiator. At the other extreme, if the
power plant is on the bank of a rapidly flowing cold river,
part of the river may be diverted to flow through the con-
denser under gravity with no energy penalty and minimal cost.
But there may be effects on biota either from flowing
through the plant or from the temperature changes. Lakes,
oceans, cooling ponds, and wet towers give various inter-
mediate solutions to the problem. Another alternative is
to utilize waste heat for such purposes as aquaculture,
agriculture and process steam. This alternative is dis-
cussed in a later part of the report.
Cooling water cannot be recycled through towers or
ponds indefinitely because chemicals collect by leaching
and from additives while nearly pure water is slowly lost
by evaporation. Some of the water is bled off and replaced
by fresh water to avoid overconcentration: the water that
is bled off is called blowdown. If the water is bled off
after passing through the tower or pond, it is called "cold-
side blowdown", as opposed to "hot-side blowdown" where the
water goes directly from the power plant condensers into the
river.
Alleviation of thermal pollution creates a potential
massive water pollution problem associated with the use of
blowdown chemicals (the organic and inorganic compounds
which are employed to poison organisms in the cooling system
and to clean parts of the system which may become fouled by
chemical reactions). These chemicals are often highly toxic
and can perform more harm than that which can be attributed
to thermal pollution.
-26-
-------
PERCENT OF INSTALLED GENERATING CAPACITY
-------
AGE
100$
El
M
O
<
ou
<
o
u
2
M
Eh
<
K
W
2
U
O
Q
W
J
J
<
Eh
CO
2
fc
O
W
u
K
W
Oh
1978
1974 (IGC)
1974 (NG)
1970 (IGC)
1970 (NG)
1962 (IGC)
1962 (NG)
195^ (IGC)
1954 (NG)
1946 (IGC)
1946 (NG)
I960
1970 1978
YEAR OF INSTALLATION
Figure 2.7
-28-
-------
2.3 Existing Thermal Abatement Technologies
Methods of Thermal Abatement
This section describes the variety of cooling alterna-
tives available to redistribute the impact of waste heat
release. It is important to understand these technologies
because each of them can themselves affect the environment
in a manner which would contradict the intent of environ-
mentalists, so that under certain circumstances the employ-
ment of cooling technologies could seriously affect environ-
mental quality. The issues discussed below in the next
section and the one which follows it, deal with air quality
implications of cooling towers.
Several procedures exist to cool or disperse heated
water. These include the operation of:
1. Cooling ponds and lagoons
2. Spray systems
3. Natural draft wet towers
4. Mechanical draft wet towers
5. Dry towers
6. Diffusers
The first four systems cool water primarily by evapora-
tion, while the fifth cools only by exchanging heat between
two fluids, hot water and cooler air. The sixth system dis-
tributes the waste heat directionally, so that the ecological
effects can be minimized by either reducing or increasing
mixing as a function of the nature of particular ecosystems.
It is important to understand that each of these systems re-
quire different amounts of energy and water to effect the
same amount of cooling, and that the operation of each of
these systems affects the environment differently.
1. Cooling ponds
Given sufficient land, cooling ponds and lagoons are
the cheapest and environmentally the most satisfactory
method to achieve reductions in thermal loads. The
heat is rejected from the pond surface by the natural
effects of conduction, convection, radiation, and
evaporation. Cooling ponds can be classified as
completely mixed, stratified, and flow-through ponds.
In a completely mixed pond, the flow between the inlet
and outlet locations of the pond combined with wind
-29-
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mixing tend to keep the pond at a nearly uniform tem-
perature. Stratified ponds are worn on the surface
near the outfall and cooler on the bottom near the
intake. In a flow-through pond the temperature de-
creases continually along the pond. The pond effluent
can either be returned to the plant intake (closed
cycle) or discharged to a natural receiving body (open
cycle). Flow-through and stratified ponds are more
common and more effective than completely mixed ponds.
2. Spray Systems and Spray Ponds
Spray ponds are available in two different configura-
tions, conventional spray ponds and powered spray sys-
tems. In conventional spray ponds, warm water is
pumped through pipes from the condenser and then out
of the spray nozzles increasing the exposure of sur-
faces to the atmosphere for cooling. Spray systems
rely on expanded surface contact to increase evapora-
tion. Spray ponds are subject to poor operation due
to climatic conditions. Powered spray systems consist
of individual units with several nozzle assemblies
and a motor, or a thermal motor module with numerous
disks spinning on a common shaft, and driven by a
single motor.
3. Natural Draft Wet Towers
Natural draft wet towers are basically a large chimney
that provides a draft to pull air over a large sur-
face of water. Among the advantages of natural draft
wet towers are long term maintenance-free operation,
smaller amounts of ground space required for multiple
towers, reduced piping costs when towers can be loca-
ted adjacent to the plant, no electricity required for
operating fans, fewer electrical controls and less
mechanical equipment. It is not possible to control
outlet temperatures as well as with mechanical draft
towers. Also, because of their large size, natural
draft towers tend to dominate the landscape.
4. Mechanical Draft Wet Towers
Mechanical draft wet towers are divided into two categor-
ies, forced air flow and induced air flow. Mechanical
-30-
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draft towers are further subdivided into counterflow and
crossflow towers. Crossflow induced draft towers can
often attain better thermal performance than counterflow
towers.
5• Natural and Mechanical Draft Dry Towers
In the natural and mechanical draft dry tower heat
rejection systems, the circulating water never comes
into direct contact with the cooling air. There are
two basic types of air-cooled condensing systems, the
indirect system and the direct system. The indirect
system uses a condenser to condense the exhaust steam.
In the direct system, steam is condensed in the tower
cooling coils without the use of a condenser or circu-
lating water. The large steam piping required might
make the direct system infeasible for large power plants.
6. Diffusers
Outfalls can be designed to distribute the flow of
waste heat in streams and other water bodies to achieve
desirable ecological goals. In rivers, heated water
may be concentrated on the surface to maximize atmos-
pheric cooling and minimize downstream effects, or con-
centrated in midstream to minimize effects on shoreline
biota, or diffused across the width of the river to
minimize the temperature effects anywhere in the river.
In salinity-stratified estuaries, it may be theoreti-
cally possible to both withdraw and return the water
from middle levels, minimizing effects on both surface
and bottom species.
2.3.1 Sample Selection
The accompanying table lists the 180 steam-electric
generating plants that were selected randomly from a total
population of 1,273 sites, located throughout the continental
United States. The procedure that was employed to select
the sample is as follows:
1. The National Coal Association's publication:
Steam-Electric Plant Factors (1973 ed.) was the source
from which the sample was drawn. Factors was designed
-31-
-TOTUT? ' "
National Environmental Research
200 3. W 35th St«w»
CorvalUa. Otoqo® OT330
-------
to list all privately and publicly owned steam-electric
utility plants in the contiguous United States (Alaska
and Hawaii are excluded), including all those scheduled
to begin operation by the year 1979- With the exception
of those installations (military, schools, municipalities,
and cooperatives) which do not file annual reports with
the Federal Power Commission, and a few companies whose
annual reports were filed too late for inclusion in the
publication, the listing in Factors can be taken as a
fairly complete list of the steam-electricity utility
plants in the United States.
A total of 1,273 plants were listed in Factors¦ Of
this number, 966 plants were in operation by 1972, with
the remaining 307 consisting of those plants scheduled to
begin operation between 1973 and 1979- Each of the 1,273
plants was assigned a number in the order in which it
appeared in Factors.
2. A table of random digits (taken from the Rand
Corporation, A Million Random Digits) was then utilized
to select the sample of 180 plants from the total popu-
lation .
The information that appears in the table was pro-
vided by the National Coal Association's publication. In
the case of the nuclear facilities projected to operate
by 1979, the precise locations of the plants were not
provided by Factors, and the Atomic Energy Commission was
contacted to obtain the necessary information.
The 180 plants chosen appear to be a fairly repre-
sentative sample of the total population. For example,
of the plants selected, 132 (73%) consisted of plants in
operation prior to 1972. This percentage compares favor-
ably with the percentage of total power plants in the
population that fall within the pre-1972 category (966 out
of 1,273, or 75%). In terms of a breakdown by fuel-type,
l'J percent of the sample of 180 were nuclear plants, com-
pared with approximately 10 percent of all plants listed
in Factors being nuclear.
2.3.2 Sample Description
The list of plants in the sample used by ERCO to repre-
sent one-seventh of the steam-electric utility industry in
-32-
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1978 follows. The blank lines divide the data into the 180
entries chosen from the National Coal Association's Steam
Electric Plant Factors (1973 ed.). Where the entry covered
an entire plant, it has been separated into units. Where
the unit will be retired by 1977 or will not be operating
before 1978, it was dropped from the sample, as shown by Ret
(Retired) or Pos (Postponed) on the far right. Plants that
were dropped or given double weight to make the sample a
better match to national totals are shown by Dup (Duplicate)
and Del (Delete). The plants are ordered alphabetically by
utility name which precedes the plant entry. Left to right,
the columns show the following:
1. Utility code derived from the -FPC form 67
2. Plant name
3. EPA region number
4. State abbreviation
5. An * ST if the plant is less than 25 Mw or the util-
ity less than 150 Mw
6. Unit number
7. Initial year of service
8. Installed generating capacity in megawatts
9. Cooling method code: 0 = once through, H = helper
cooling, C = closed cycle, M = mechanical draft
wet tower, N = natural draft wet tower, P = pond,
S = spray pond
10. Primary and secondary fuel type: P,S,C = pulverized,
stoker, or cyclone coal, 0 = oil, G = gas, N =
uranium
11. Percent of full load expected in 1978
12. Receiving water type: R = river, L = lake, E =
estuary, M = municipal and other, 0 = ocean
13- Safezone fraction at 5% low flow in tenths
2.3.3 Problems with F.P.C. Data
ERCO encountered numerous problems when using data tapes
acquired from the F.P.C. Most of them appear to derive from
an attempt to make the computer record reproduce as faith-
fully as possible the original answers as entered on the
corresponding questionnaire, resulting in numerous non-numeric
entries in what would be expected to be an all numeric field.
Unconventional entries were specially identified so it was
possible to avoid a complete program abort, but the data still
had to be analyzed by hand. Erroneous data sometimes was
left on the tape with a correction only in a footnote—again
requiring manual analysis.
-33-
-------
The data storage was in a format that identified every
line uniquely but at the cost of using half the tape merely
for identification and most of the remainder was blank since
single digit answers are allowed 40 spaces. Footnotes
were not uniquely identified on the questionnaire, which led
to some footnotes many sentences long, being repeated many
times on the tape.
Worst of all in the case of Form 67, although voluminous
data on fuel use for each boiler was included, there was no
electrical data. So simple answers which are readily avail-
able to the plant engineer, such as heat rate for an indivi-
dual unit, had to be imputed with the aid of several approxi-
mations. The questionnaire was poorly designed since anyone
interested in air and water pollution can be expected to have
more than a passing interest in the corresponding electricity
production. Some data that appeared to be plant specific was
actually based on approximate national averages even when
specific data was available. For example, consumptive use of
fresh water was calculated assuming an l8°F temperature rise
for most plants. For other plants, no value was calculated
at all, even though sufficient data was available. The na-
tional totals given for water consumption are therefore not
as reliable as would be a simple approximation based on total
net generation at fresh water sites.
_34_
-------
ERCO UTILITY SAMPLE
Utility Name
Code Plant
State Unit Year
EPA Small
Size Cool Fuel Load Water
Body
Arizona Public Service Co.
1963
70,
170 FOUR CORNERS
6 NM
1
175.
C
p
C
R
170 FOUR CORNERS
6 NM
2
1963
175.
C
p
C
70.
R
170 FOUR CORNERS
6 NM
3
1964
225.
C
p
C
53.
R
Arkansas Power & Light Co.
47.
185 LAKE CATHERINE
6 AR
1
1949
46.
O
G
0
L
185 LAKE CATHERINE
6 AR
02
1949
46.
0
G
O
44.
L
185 LAKE CATHERINE
6 AR
03
1952
113.
0
G
O
28.
L
185 LAKE CATHERINE
6 AR
04
1970
552.
O
G
59.
L
Associated Electric Coop..
Inc.
210 NEW MADRID
7 MO
2
1977
600.
O
C
70.
R
Baltimore Gas & Electric
265 CRANE
3 MD
1
1961
191.
O
C
50.
E
265 CRANE
3 MD
2
1962
209.
O
0
53.
E
265 CALVERT CLIFFS
3 MD
2
1977
845.
O
N
76.
E
Bangor Hydro-Electric
270 E M GRAHAM
1 ME
S
3
1953
13.
H
S
O
14.
R
270 E M GRAHAM
1 ME
S
4
1957
17.
H
S
O
40.
R
270 E M GRAHAM
1 ME
S
5
1964
28.
H
S
0
39.
R
Basin Electric Power
Coop.
310 W J NEAL
8 ND
1
1951
15.
C
M
C
62.
R
310 W J NEAL
8 ND
2
1951
15.
C
M
c
62.
R
Boston Edison- Co.
485 MYSTIC
1 MA
485 MYSTIC
1 MA
4
1957
125.
O
0
41.
E
485 MYSTIC
1 MA
5
1957
125.
0
0
39.
E
485 MYSTIC
1 MA
6
1961
138.
0
0
44.
E
485 NEW BOSTON
1 MA
1
1965
380.
0
0
70.
E
485 NEW BOSTON
1 MA
2
1967
380.
0
0
69.
E
485 PILGRIM
1 MA
1
1972
655.
0
N
75.
O
Brazos Electric Power
Coop.
520 NORTH TEXAS
6 TX
1
1958
19.
0
G
25.
L
520 NORTH TEXAS
6 TX
2
1958
19.
0
G
35.
L
520 NORTH TEXAS
6 TX
3
1963
38.
0
G
42.
L
520 MILLER
6 TX
1
1968
75.
0
G
72.
L
520 MILLER
6 TX
2
1971
117.
0
G
61.
L
Ret
TABLE 2-1
-35-
-------
Table 2-1 Continued
Utility Name
State
Unit
Year
Size
Cool
Fuel
Load
Water
Code Plant
EPA Small
Body
Central Illinois
Public Service Co.
785 HUTSONVILLE
5 IL
1
1940
31.
0
P
12.
R 7
785 HUTSONVILLE
5 IL
2
1941
31.
0
P
12.
R 7
785 HUTSONVILLE
5 IL
3
1953
75.
0
P
52.
R 7
785 HUTSONVILLE
5 IL
4
1954
75.
0
P
47.
R 7
785 MEREDOSIA
5 IL
4
1975
200.
0
c
67.
R 9
785 NEWTON
5 IL
1
1977
600.
c
P
C
70.
R
Central Kansas Power Co.
795 ROSS BEACH
7 KS
1
1954
12.
c
M
G
36.
N
Central Power & Light Co.
820 JOSLIN
6 TX
1
1971
261.
0
G
53.
E
820 DAVIS
6 TX
1
1974
323.
H
P
O
G
55.
E
820 DAVIS
6 TX
2
1976
323.
H
P
O
G
55.
E
Central Telephone
& Utilities Coc
P'
825 CLARK
8 CO
1
1955
17.
H
S
G
C
82.
R 6
825 CLARK
8 CO
2
1958
22.
H
M
C
G
90.
R 6
City of Lafayette
Utilities
System
940 RODEMACHER
6 LA
3
1956
12.
c
M
G
1.
N
940 RODEMACHER
6 LA
4
1960
25.
c
M
G
14.
M
Clarksdale Water & Light Dept.. City of
1015 SOUTH 4 MS S 6 1956 5. 0 G 0 11. H
1015 SOUTH 4 MS S 7 1958 8.0 G 0 29. M
Cleveland Electric Illuminating Co.
1040 PERRY 5 OH 1979 Pos
Coffeyville, City of
1045 COFFEYVILLE 7 KS 7 1973 38. CM GO 64. R
Colorado Springs Dept. of Public Utilities, City of
1080 MARTIN DRAKE 8 CO 7 1973 127. CM C G 63. M
Commonwealth Edison Co. of Indiana Inc.
1110 STATE LINE 5 IN 3 1955 225. 0 P G 52. L
1110 STATE LINE 5 IN 04 1962 389. O G P 45. L
Commonwealth Edison Co.
1115 ZION 5 IL 2 1974 1050. O N 68. L
-36-
-------
Table 2-1 Continued
Utility Name
Code Plant
State Unit Year
EPA Small
Size Cool Fuel Load Water
Body
Consolidated Edison
Co.
of
New
York,
Inc.
1130 74TH STREET
2
NY
3
1915
30.
O
O
11.
E
1130 74TH STREET
2
NY
9
1959
75.
O
O
15.
E
1130 74TH STREET
2
NY
10
1956
69.
O
O
15.
E
1130 74TH STREET
2
NY
11
1962
35.
O
O
16.
E
1130 INDIAN POINT
2
NY
1
1962
275.
O
O N
38.
E
1130 KENT AVENUE
2
NY
Consumers Power Co.
1145 KALAMAZOO
5
MI
1145 WEALTHY STREET
5
MI
1145 BIG ROCK POINT
5
MI
1
1962
75.
O
N
61.
L
1145 KARN
5
MI
1
1959
265.
O
C
78.
R
1145 KARN
5
MI
2
1961
265.
O
C
78.
R
fairyland Power Coop.
260 LACROSSBWR
Dallas Power & Light
1265 LAKE HUBBARD
1265 LAKE HUBBARD
4 Ll9ht3 DE
Denton Municipal Utj
1320 DENTON
1320 DENTON
1320 DENTON
1320 DENTON
1320 DENTON
Duke Power Co.
Duguesne Light Co.
1400 COLFAX 3 PA
1400 SHIPPINGPORT 3 PA
Ret
Ret
Ret
5 WI
1
1964
.
o
in
0
N
71.
R
6 TX
1
1970
397.
C
P
G
15.
R
6 TX
2
1973
531.
0
G O
55.
L
3 DE
1979
ties
1955
13.
6 TX
1
C
M
G
9.
M
6 TX
2
1955
13.
C
M
G
9.
M
6 TX
3
1962
32.
C
M
G
14.
M
6 TX
4
1966
67.
C
M
G
22.
M
6 TX
5
1973
65.
C
M
G
64.
M
Pos
1395
DAN RIVER
4
NC
1
1949
70.
0
C
33.
R
2
1395
DAN RIVER
4
NC
2
1950
70.
0
C
33.
R
2
1395
DAN RIVER
4
NC
3
1955
150.
O
C
46.
R
2
1395
MCGUIRE
4
NC
1
1976
1180.
0
N
72.
L
Del
Ret
1956 100.
N
12. R 9
-37-
-------
Table 2-1 Continued
Utility Name
Code Plant
Florida Power Corp.
1655 BAYBORO
1655 INGLIS
State Unit Year
EPA Small
4 FL
4 PL
Size Cool Fuel Load Water
Body
Ret
Ret
Fort Wayne Light & Power
1670 LAWTON PARK 5
: Works
IN S 2
1936
15.
0
S
14.
R
3
1670 LAWTON PARK
5
IN S
3
1940
15.
O
S
14.
R
3
Fremont DeDt. of Public
1675 FREMONT 7
Utilities
N3 1 1924
2.
H
P
G
S
11.
M
1675 FREMONT
7
NB
2
1928
1.
B
P
G
S
11.
M
1675 FREMONT
7
NB
3
1932
3.
H
P
G
S
15.
M
1675 FREMONT
7
NB
4
1945
5.
H
P
G
S
14.
M
1675 FREMONT
7
NB
5
1950
10.
H
P
G
S
18.
M
Garland Power £ Light
1775 OLINGER
, City of
6 TX 3
1975
150.
O
G
O
67.
L
Georgia Power Co.
1790 HARLLEE BRANCH
4
GA
1
1965
299.
O
C
61.
L
Dup
1790 HARLLEE BRANCH
4
GA
2
1967
359.
O
C
54.
L
1790 HARLLEE BRANCH
4
GA
3
1968
544.
O
C
52.
L
1790 HARLLEE BRANCH
4
GA
4
1969
544.
O
C
55.
L
1790 MCDONOUGH
4
GA
1
1963
245.
O
C
G
72.
R
4
1790 MCDONOUGH
4
GA
2
1964
245.
O
C
G
72.
R
4
1790 BOWEN
4
GA
3
1974
952.
C
N
P
54.
R
1790 BOWEN
4
GA
4
1975
952.
C
N
P
54.
R
1790 VOGTLE
4
GA
1979
Pos
Greenwood utilities
1890 HENDERSON
4
MS
1
1961
13.
0
G
C
47.
M
1890 HENDERSON
4
MS
3
1969
20.
C
M
G
C
50.
M
Gulf Power Co.
1950 SMITH
4
FL
1
1965
150.
O
C
52.
E
1950 SMITH
4
FL
2
1967
190.
O
C
44.
E
Gulf States Utilities
1955 LEWIS CREEK
Co
6
>.
TX
1
1970
271.
C
P
G
82.
R
1955 LEWIS CREEK
6
TX
2
1970
271.
C
P
G
82.
R
1955 RIVERBEND
6 LA
1979
Pos
-38-
-------
Table 2-1 Continued
Utility Name
Code Plant
State Unit Year Size
EPA Small
Cool Fuel Load Water
Body
Hastings Utilities
1980 HASTINGS
7
NB
2
1948
6.
C
S
G
O
19.
M
1980 HASTINGS
7
NB
3
1948
6.
C
S
G
O
19.
M
1980 HASTINGS
7
NB
4
1957
16.
O
G
O
43.
K
1980 HASTINGS
7
NB
5
1967
23.
C
N
G
O
65.
M
1 MA S
6
1955
10.
0
O
G
45.
R
1 MA S
8
1951
10.
0
0
G
45.
R
1 MA S
9
1941
5.
C
M
0
G
41.
R
Power Co.
6 TX
3
1950
75.
C
M
G
0.
M
6 TX
4
1951
75.
C
M
G
3.
M
2135 HOLYOKE 1 MA S 6 1955 10. 0 0 G 45. R 8
2135 HOLYOKE 1 MA S 8 1951 10. 0 0 G 45. R 8
2135 HOLYOKE
Houston Lighting
2185 CLARKE
2185 CLARKE
Huntinqsburq Municipal Lig"ht & Power Plant
2190 HCJNTINGSBURG 5 IN Ret
Independence, City Power & Light of
2235 BLUE VALLEY 7 MO P°s
Indiana & Michigan Electric Co.
2250 D C COOK 5 MI 1 1974 1060. 0 N 83. L
2250 D C COOK 5 MI 2 1975 1060. O N 83. L
IndianaDolis Power &
Light
Co.
2260 STOUT
5 IN
1
1931
37.
O
P
1.
R
0
2260 STOUT
5 IN
2
1931
37.
O
P
1.
R
0
2260 STOUT
5 IN
3
1942
37.
H
M
P
4.
R
0
2260 STOUT
5 IN
4
1947
38.
H
M
P
4.
R
0
2260 STOUT
5 IN
5
1958
114.
H
M
P
26.
R
0
2260 STOUT
5 IN
6
1961
114.
H
M
P
26.
R
0
Iowa Electric Liqht &
Power
Co.
2285 PRAIRE CREEK #1
3 IA
S 1
1950
23.
O
G
C
37.
R
7
2285 PRAIRE CREEK #1
3 IA
2
1950
23.
O
G
C
42.
R
7
2285 PRAIRE CREEK #1
3 IA
3
1958
50.
0
C
G
47.
R
7
Iowa-Illinois Gas & Electric
2290 RIVERSIDE 7 IA
93
1949
5.
O
G
C
41.
R
2290
RIVERSIDE 7
IA
4
1949
43.
O
G
C
44.
R
2290
RIVERSIDE 7
IA
5
1961
125.
0
C
G
54.
R
Iowa
2295
Public Service Co.
BIG SIOUX 7
IA
Iowa-
2305
-Southern Utilities
BRIDGEPORT 7
Co.
IA
1
1953
23.
c
M
S
0
7.
R
2305
BRIDGEPORT 7
IA
2
1955
23.
c
M
S
0
7.
R
2305
BRIDGEPORT 7
IA
3
1957
25.
c
M
S
O
7.
R
-39-
-------
Table 2-1 Continued
Utility Name
Code Plant
State Unit Year
EPA Small
Size Cool Fuel Load Water
Body
Jacksonville Electric
Authority
2345 KENNEDY
4
FL
8
1955
50.
O
O
64.
E
2345 KENNEDY
4
FL
9
1957
50.
O
O
48.
E
2345 KENNEDY
4
FL
10
1961
150.
0
O
74.
E
2345 NORTHSIDE
4
PL
1
1966
280.
0
O
74.
E
2345 NORTHSIDE
4
FL
2
1971
315.
0
O
58.
E
Jamestown. City of
2350 S A CARLSON
2
NY
2
1930
5.
C
M
P
0.
R
2350 S A CARLSON
2
NY
3
1938
15.
c
M
P
3.
R
2350 S A CARLSON
2
NY
4
1930
13.
C
M
P
0.
R
2350 S A CARLSON
2
NY
5
1951
20.
c
M
P
38.
R
2350 S A CARLSON
2
NY
6
1968
25.
c
M
P
39.
R
i
?rsey Central Power & Light
370 UNION BEACH 2 NJ
Pos
2420 QUINDARO 42
2420 QUINDARO #2
2420 QUINDARO #2
2420 QUINDARO #3
2420 QUINDARO #3
Public
Utilities
7 KS
7
1938
32.
O
G
P
0.
R
6
7 KS
8
1948
32.
O
G
P
1.
R
6
7 KS
9
1952
28.
0
G
P
3.
R
6
7 KS
1
1965
82.
O
G
c
56.
R
8
7 KS
2
1970
158.
O
G
60.
R
8
Kansas G££v& Electric Co.
2425 LA CYGNE 7 KS 1 1973 840. C P C 64. R
2425 LA CYGNE 7 KS 2 1977 630. C P C 53. R
Lake Suoerior District Power Co,
2460 BAY FRONT
2460 BAY FRONT
2460 BAY PRONT
24 60 BAY FRONT
2460 BAY FRONT
2460 BAY FRONT
5
5
5
5
5
5
WI
WI
WI
WI
WI
WI
1
2
3
4
5
6
1917
1922
1925
1949
1952
1957
5.
5.
5.
20.
20.
25.
O
O
0
0
0
0
S
S
S
S
S
S
2.
2.
2.
26.
41.
47.
L
L
L
L
L
L
Lake Worth Utilities Authorit
2565 LAKE WORTH
2565 LAKE WORTH
2565 LAKE WORTH
J
4 FL
4 FL 3
4 FL 4
1963
1967
1971
7.
27.
33.
C M
C M
C M
G O
G O
G O
5.
37.
42.
M
M
M
Lamar, Utilities Board of the City of
2580 LAMAR 8 CO S 6 1972
25. HP GO 42. M
Lansing Board of Water & Light
2605 OTTAWA 5 MI 1 1938 25. 0 P 3. R 0
2605 OTTAWA 5 MI 2 1940 25. O P 3. R 0
2605 OTTAWA 5 MI 3 1947 25. O P 3. R 0
2605 ERTCKSON
5 MI
1 )97* ] 60 CMC
68 R
-4 0-
-------
Table 2-1 Continued
Utility Name
Code Plant
State Unit Year
EPA Small
Size Cool Fuel Load Water
Body
Larned Water & Electric Dept
2610 LARNED 7 KS
•
2
1948
3.
C
M
G
11.
M
2610 LARNED
7 KS
3
1961
8.
C
M
G
41.
M
Los Angeles Dept.
274 5 VALLEY
of Water &
9 CA
Power
1 1954
100.
C
M
G
O
32.
11
274 5 VALLEY
9 CA
2
1954
100.
C
M
G
O
35.
M
274 5 VALLEY
9 CA
3
1955
173.
C
M
G
O
41.
M
274 5 VALLEY
9 CA
4
1956
173.
C
M
G
0
40.
M
Louisiana Power &
2750 STERLINGTON
Light Co.
6 LA
•5
1943
44.
O
G
23.
R
4
2750 STERLINGTON
6 LA
6
1958
248.
0
G
64.
R
4
Louisville Gas & Electric Co.
2755
CANE
RUN
4
KY
1
1954
113.
O
c
G
40.
R
2755
CANE
RUN
4
KY
02
1956
113.
O
c
G
40.
R
2755
CANE>
RUN
4
KY
03
1958
147.
0
c
G
40.
R
2755
CANE
RUN
4
KY
04
1962
163.
0
c
46.
R
2755
CANE
RUN
4
KY
05
1966
209.
0
c
40.
R
2755
CANE
RUN
4
KY
06
1969
272.
0
c
40.
R
8Dup
8
8
8
8
8
Macon Municipal Utilities
2785 MACON 7 MO
Ret
Madison Gas & Electric Co.
2835
BLOUNT
5
WI
1
1924
12.
O
G
1.
L
2835
BLOUNT
5
WI
2
1922
6.
O
G
2.
L
2835
BLOUNT
5
WI
3
1953
30.
O
G
P
49.
L
2835
BLOUNT
5
WI
4
1938
20.
O
G
P
9.
L
2835
BLOUNT
5
WI
5
1948
20.-
O
G
P
23.
L
2835
BLOUNT
5
WI
6
1957
44.
O
G
P
37.
L
2835
BLOUNT
5
WI
7
1961
44.
O
G
P
37.
L
284 0 MARSHALL
2840 MARSHALL
2840 MARSHALL
2840 MARSHALL
2840 MARSHALL
McPherson. Board of
2845 MCPHERSON f ONE
2845 MCPHERSON #ONE
2845 MCPHERSON #ONE
2845 MCPHERSON #TWO
3035 EYLER
Utilities
7 MO
1
1936
2.
C
M
S
0.
M
7 MO
2
1942
2.
C
M
S
0.
M
7 MO
3
1948
4.
C
M
G
O
3.
M
7 MO
4
1957
6.
C
M
G
S
29.
M
7 MO
5
1967
17.
C
M
G
S
25.
M
Public Utilities
7 KS 3 1957
10.
C
M
G
O
15.
M
7 KS
1
1940
5.
C
M
G
5.
M
7 KS
2
1952
8.
c
M
G
O
10.
M
i 7 KS
1
1963
26.
c
M
G
O
68.
M
Co.
3 PA
6
1923
35.
O
O
C
2.
R
-ill-
-------
Table 2-1 Continued
Utility Name
Code Plant
State Unit Year Size
EPA Small
3075 YOUNG
Mississippi Power Co.
3080 SWEATT
3080 SWEATT
Mississippi
308 5 DELTA
3085 DELTA
3085 NATCHEZ
Power &
8 ND
2
1977
400
4 MS
1
1951
46
4 MS
2
1953
49
qht Co
•
4 MS
1
1953
110
4 MS
2
1953
110
4 MS
1
1951
66
Montana Dakota Utilities Co.
3130
LEWIS & CLARK
8
MT
1
1958
50
3130
MOBRIDGE
8
SD
3
1950
9
3130
GLENDIVE
8
MT
1
1926
2
3130
GLENDIVE
8
MT
2
1941
5
3145 MOUNT CARMEL
3145 MOUNT CARMEL
3145 MOUNT CARMEL
Co.
5
IL
S
2
1939
4
5
IL
S
3
1949
8
5
IL
S
4
1954
8
Muscatine Power & Water
3150
MUSCATINE
7
IA
S
5
1941
8
3150
MUSCATINE
7
IA
S
6
1949
13
3150
MUSCATINE
7
IA
S
7
1959
23
3150
MUSCATINE
7
IA
s
8
1969
66
New York State Electric & Gas Corp, _
3J90 JENNISON 2 KY 1 1945 30.
3390 JENNISON 2 NY 2 1950 30.
Northern Indiana Public
3455 MICHIGAN CITY 5
3455 MICHIGAN CITY 5
3455 MICHIGAN CITY 5
Service
IN 1
IN 2
IN 3
C?«31
1950
1951
75
70
70
3455
MICHIGAN CITY
5
IN 12
1973
521
3455
R M SCHAHFER
5
IN 14
1976
521
Cool Fuel Load Water
Body
C
p
P
70.
R
C
M
G
O
24.
M
c
M
G
0
22.
M
c
P
G
O
37.
R
c
P
G
0
44.
R
c
M
G
0
16.
M
O
C
74.
R
c
M
S
0.
R
O
G
0.
R
0
G
0
0.
R
0
S
29.
R
0
S
30.
R
0
0
G
30.
R
0
S
21.
R
0
S
22.
R
O
s
G
50.
R
O
s
G
72.
R
O
s
56.
R
0
s
58.
R
0
G
1.
L
0
P
G
57.
L
0
P
G
57.
L
c
N
P
68.
L
c
M
C
68.
R
-42-
-------
Table 2-1 Continued
Utility Name
Code Plant
State Unit Year
EPA Small
Size Cool Fuel Load Water
Body
UQtfchern States Power
3470 LAWRENCE
Co.
8 SD
1
1948
16.
C
M
G
c
4.
R
3470 LAWRENCE
8 SD
2
1950
16.
C
M
G
c
4.
R
3470 LAWRENCE
8 SD
3
1951
16.
C
M
G
c
4.
R
3470 WILMARTH
5 MN S
1
1948
12.
O
G
S
10.
R
7
3470 WILMARTH
5 MN S
2
1951
13.
O
G
S
n.
R
7
3470 MONTICELLO
5 MN
1
1971
569.
C
M
N
77.
R
3470 PATHFINDER
8 SD
1
1962
75.
C
N
O
G
5.
R
3470 PRAIRIE ISLAND
5 MN
1
1973
530.
c
N
N
78.
R
3470 PRAIRIE ISLAND
5 MN
1978
3470 SHERBOURNE
5 MN
1
1976
720.
c
M
C
68.
R
3470 SHERBOURNE
5 MN
2
1977
720.
c
M
C
70.
R
Ohio Edison Co.
3545 NORWALK
5 OH
9
Ohio Power Co.
3550 TIDD
5 OH
1
1945
111.
O
P
O
38.
R
8
3550 TIDD
5 OH
2
1948
111.
0
P
O
46.
R
8
3550 MITCHELL
3 WV
1
1971
816.
c
N
P
69.
R
3550 MITCHELL
3 WV
2
1971
816.
c
N
P
69.
R
Oklahoma Gas & Electric Co.
3565 MUSKOGEE 6 OK
4
1977
550.
c
M
c
•
63.
R
Onaha Public Power District
3570 FORT CALHOUN 7 NB
1
1973
457.
0
N
75.
R
9
Pacific Power & Light
3705 JOHNSTON
Co.
8 WY
1
1959
114.
0
c
83.
R
0
3705 JOHNSTON
8 WY
2
1961
114.
0
c
83.
R
0
3705 JOHNSTON
8 WY
3
1964
230.
0
c
65.
R
0
3705 JOHNSTON
8 WY
4
1971
293.
O
c
77.
R
0
Pasadena Water & Power
3745 GLENARM
• Dept.
9 CA
8
1948
40.
c
M
G
7.
M
3745 GLENARM
9 CA
9
1948
25.
c
M
G
0.
M
Pennsylvania Electric
3795 HOMER CITY
Co.
3 PA
3
1976
640.
c
N
P
68.
R
Pos
, Ret
Dup
3795 CONEMAUGH
3 PA
1975
640. C N C
67.
-43-
-------
Table 2-1 Continued
Utility Name
Code Plant
State Unit Year
EPA Small
Size Cool Fuel Load Water
Body
Pennsylvania Power & Light
3800 MARTINS CREEK 3 PA
Co.
1
1954
156.
0
C
61.
R
3800 MARTINS CREEK 3 PA
2
1956
156.
0
C
61.
R
3800 MONTOUR 3 PA
2
1973
806.
C
N
P
69.
R
3800 SUSQUEHANNA 3 PA
1979
Potomac Electric Power Co.
3945 'CHALK POINT 3 MD
3945 CHALK POINT 3 MD
3
4
1974
1975
630.
630.
C
C
N
N
O
O
46.
41.
R
R
Public Service Co. of New Mexico
4035 REEVES 6 NM 1
1959
50.
C
M
G
0
46.
M
4035 REEVES 6 NM
2
1960
50.
C
M
G
O
57.
M
4035 REEVES 6 NM
3
1962
75.
C
M
G
O
53.
M
7
7
Pos
Public Service Co. of Indiana Inc.
4045
EDWARDSPORT
5
IN
6
1943
35.
O
O
10.
R
3
4045
EDWARDSPORT
5
IN
7
1948
35.
O
P
10.
R
3
4045
EDWARDSPORT
5
IN
8
1951
60.
O
P
10.
R
3
4045
NOBLESVILLE
5
IN
1
1950
50.
O
P
7.
R
0
4045
NOBLESVILLE
5
IN
2
1950
50.
O
P
7.
R
0
Public Service Electric
& Gas
CO
•
4055
BURLINGTON
2
NJ
5
1940
125.
O
O
18.
R
7
4055
BURLINGTON
2
NJ
6
1943
125.
0
O
18.
R
7
4055
BURLINGTON
2
NJ
7
1955
193.
O
O
49.
R
7
4055
SEWAREN
2
NJ
1
1948
103.
O
O
G
11.
E
4055
SEWAREN
2
NJ
2
1948
107.
O
O
G
21.
E
4055
SEWAREN
2
NJ
3
1949
103.
O
0
G
26.
E
4055
SEWAREN
2
NJ
4
1951
119.
O
0
G
28.
E
4055
SEWAREN
2
NJ
5
1962
388.
0
0
48.
E
4055
SALEM
2
NJ
2
1976
1115.
O
N
69.
R
Public Service Co.
of Oklahoma
4063
NORTHEASTERN
6
OK
1
1961
170.
C
M
G
34.
L
4063
NORTHEASTERN
6
OK
2
1969
473.
C
M
G
82.
L
4063
RIVERSIDE
6
OK
1
1974
472.
O
G
72.
R
4063
RIVERSIDE
6
OK
2
1976
473.
O
G
75.
R
Del
SSS5eRS8HEiTiR&#ENINtr£CNY°rP99 1945 3. 0 0 G 34. M
SSSS°ftu3*6fcitie8 Syste2 LA 3 1974 42. CM 0 G 54. M
-HH-
-------
Table 2-1 Continued
Utility Name State Unit Year Size Cool Fuel Load Water
Code Plant EPA Small Body
Saint Marys Municipal
4230 SAINT MARYS
Liqht
5 OH
S* rw!r96?ept
*10.
O
C
0
30.
L
Sewerage & Water Board
4375 POWER HOUSE
of New Orleans
6 LA S 1 1913
6.
O
G
2.
M
4375 POWER HOUSE
6 LA
S 3
1928
15.
0
G
14.
M
4375 POWER HOUSE
6 LA
S 4
1954
20.
0
G
34.
M
5$ilbMB*cipal utili
cijy
??67
12.
c
M
P
56.
M
4380 SHELBY
5 OH
3
1945
5.
c
M
P
9.
M
4380 SHELBY
5 OH
4
1954
8.
c
M
P
13.
M
Sierra Pacific Power Co.
4435 TRACY 9 NV
1
1965
53.
0
G
0
5.
R
1
4435 TRACY
9 NV
2
1963
80.
0
G
0
26.
R
1
4435 TRACY
9 NV
3
1974
110.
c
M
O
G
62.
R
South<3earolina Electric & Gas Co.
4475 CANADYS 4 SC 1
1962
136.
H
S
C
G
63.
R
3
4475 CANADYS
4 SC
2
1964
136.
H
s
C
G
63.
R
3
4475 CANADYS
4 SC
3
1967
218.
H
s
C
G
30.
R
3
S38ShMBii£tisippi Elec*rite
Powejr
200.
c
M
0
70.
R
saiifornia Ed
ra
Co ^
1953
122.
C
M
O
G
5.
M
4505 ETIWANDA
9 CA
2
1953
123.
C
M
O
G
8.
M
4505 ETIWANDA-
9 CA
3
1963
333.
C
M
O
G
70.
M
4505 ETIWANDA
9 CA
4
1963
333.
C
M
0
G
60.
M
Southern Indiana Gas &
4520 WARRICK
Electric Co.
5 IN 4 1970
300.
O
p
62.
R
9
Southwestern Electric
4540 ARSENAL HILL
Power
6 LA
C|.
1960
125.
C
s
G
30.
M
Springfield Water, Light, &
4570 LAKESIDE ^5 fL
Power
1
iSir-
10.
O
0
0.
L
4570 LAKESIDE
5 IL
2
1938
15.
0
0
0.
L
4570 LAKESIDE
5 IL
3
1939
15.
0
0
0.
L
4570 LAKESIDE
5 IL
4
1947
20.
O
P
O
7.
L
4570 LAKESIDE
5 IL
5
1951
20.
O
P
O
7.
L
4570 LAKESIDE
5 IL
6
1961
37.
0
P
24.
L
4570 LAKESIDE
5 IL
7
1965
38.
0
P
21.
L
5-
-------
Table 2-1 Continued
Utility Name
State
Unit
: Year
Siz(
Code Plant
EPA
Small
Taunton Municipal :
4 750 TAUNTON
Light
Commission
MA 4 1950
6
4750
TAUNTON
1
HA
5
1950
6
4750
TAUNTON
1
MA
6
1952
8
4750
TAUNTON
1
MA
7
1958
16
Tennessee Valley Authority
4770 ALLEN 4 Tn
1
1958
330
4770
ALLEN
4
TN
2
1959
330
4770
ALLEN
4
TN
3
1959
330
4770
COLBERT B
4
AL
5
1962
550
4770
SHAWNEE
4
KY
1
1953
175
4770
SHAWNEE
4
KY
2
1953
175
4770
SHAWNEE
4
KY
3
1953
175
4770
SHAWNEE
4
KY
4
1954
175
4770
SHAWNEE
4
KY
5
1954
175
4770
SHAWNEE
4
KY
6
1954
175
4770
SHAWNEE
4
KY
7
1954
175
4770
SHAWNEE
4
KY
8
1955
175
4770
SHAWNEE
4
KY
9
1955
175
4770
SHAWNEE
4
KY
10
1956
175
4770
WATTS BAR
4
TN
1
1977
1189
4770
WIDDOWS CREEK
A
4
AL
1
1952
142
4770
WIDDOWS CREEK
A
4
AL
2
1952
142
4770
WIDDOWS CREEK
A
4
AL
3
1953
142
4770
WIDDOWS CREEK
A
4
AL
4
1953
142
4770
WIDDOWS CREEK
A
4
AL
5
1954
142
4770
WIDDOWS CREEK
A
4
AL
6
1954
142
4770
CUMBERLAND
4
TN
2
1973
1300
4770
BROWNS FERRY
4
AL
3
1974
1065
The 1
4815
Dayton Power &
TAIT
Light Co.
5 OH
1
1944
30
4815
TAIT
5
OH
2
1942
30
4815
TAIT
5
OH
3
1951
30
4815
TAIT
5
OH
4
1958
147
4815
4815
TAIT
TAIT
5
5
OH
OH
5
7
1959
1951
147
30
4815
TAIT
5
OH
8
1951
30
Cool Fuel Load Water
Body
O
O
30.
E
O
O
25.
E
O
O
14.
E
O
0
47.
E
O
C
G
52.
R
9Dup
O
c
G
48.
R
9
O
c
G
48.
R
9
O
c
66.
R
9
O
c
72.
R
6Dup
0
c
72.
R
6
0
c
72.
R
6
0
c
72.
R
6
0
c
72.
R
6
0
c
72.
R
6
0
c
72.
R
6
0
c
72.
R
6
0
c
72.
R
6
0
c
72.
R
6
C N
N
70.
R
Del
0
P
62.
R
8
0
p
62.
R
8
0
p
62.
R
8
0
p
62.
R
8
0
p
62.
R
8
0
p
62.
R
8
0
p
68.
L
C N
N
69.
R
0
p
4.
R
0
0
p
4.
R
0
0
p
4.
R
0
0
p
39.
R
0
0
p
39.
R
0
0
p
4.
R
0
0
p
4.
R
0
-J4 6-
-------
Table 2-1 Continued
Utility Name
State
Unit
Year
Size
Cool
Fuel
Load
Water
Code
Plant EPA
Small
Body
The Detroit Esison Co
• _
46.
4820
WYANDOTTE SOUTH
5
MI
S
1
1935
4 •
O
S
R
9
4820
WYANDOTTE SOUTH
5
MI
s
2
1935
4 •
O
S
46.
R
9
4820
WYANDOTTE SOUTH
5
MI
s
3
1935
4 •
0
s
46.
R
9
4820
WYANDOTTE SOUTH
5
MI
s
4
1935
4 •
0
s
46.
R
9
4820
WYANDOTTE SOUTH
5
MI
s
5
1935
4 •
0
s
46.
R
9
4820
FERMI
5
MI
1
1966
158.
0
0
34.
L
4820
MARYSVILLE
5
MI
6
1930
50.
0
c
14.
R
9
4820
MARYSVILLE
5
MI
7
1943
75.
0
c
41.
R
9
4820
MARYSVILLE
5
MI
8
1947
75..
0
c
41'
R
9
4820
FERMI
5
MI
2
1976
1123.
C
N
N
69.
L
Del
4820
RIVER ROUGE
5
MI
1
1956
283.
0
C
G
62.
R
9
4820
RIVER ROUGE
5
MI
2
1957
292.
0
C
G
56.
R
9
4820
RIVER ROUGE
•
5
MI
3
1958
358.
0
C
G
54.
R
9
4820
TRENTON CHANNEL
5
MI
7
1949
120.
0
P
71.
R
9Dup
4820
TRENTON CHANNEL
5
MI
8
1950
120.
0
P
71.
R
9
4820
TRENTON CHANNEL
5
MI
9
1968
536.
0
P
67.
R
9
The Potomac Edison Co
•
4865
SMITH
3
MD
3
1947
35.
0
P
46.
R
0
4865
SMITH
3
MD
4
1957
75.
0
P
76.
R
0
The Tucson Gas & Electric Co
•
4885
DEMOSS PETRIE
9
AZ
1
1949
13.
c
M
G
0.
M
4885
DEMOSS PETRIE
9
AZ
2
1949
12.
c
M
G
1.
M
4885
DEMOSS PETRIE
9
AZ
3
1953
23.
c
M
G
O
19.
M
4885
DEMOSS PETRIE
9
AZ
4
1954
58.
c
M
G
O
29.
M
Trinidad Municipal Power
&
Liaht
Dept.
4890
TRINIDAD
8
CO
1
1951
4.
c
M
G
S
29.
M
4890
TRINIDAD
8
CO
2
1951
4.
c
M
G
S
26.
M
Bt
ited Power Association
35 STANTON 8 ND
1966 172
64,
R 9
UPPer_Penmnsula Generating Co.
5160 PRESQUE ISLE
5160 PRESQUE ISLE
5 MI
5
6
1974
1974
85. 0
85. 0
C
C
72. L
72. L
Utah Power & Light Co.
5170 NAUGHTON 8 HY
1971
330. CM C 6 79. R
-47-
-------
Table 2-1 Continued
Utility Name
State
Unit Year
Size
Cool
Fuel
Load
Water
Code Plant EPA Small
Body
Vineland, City of
5175 VINELAND
2 NJ
4
1920
4.
C
M
S
3 -
M
5175 VINELAND
2 NJ
5
1920
4.
C
M
S
6.
N
5175 VINELAND
2 NJ
6
1948
5.
C
M
S
37.
H
5175 VINELAND
2 NJ
7
1951
8.
C
M
S
34.
M
5175 VINELAND
2 NJ
8
1955
12.
c
M
s
34.
M
5175 VINELAND
2 NJ
9
1960
17.
c
M
S
35.
M
5175 VINELAND
2 NJ
10
1970
25.
c
M
S
59.
M
Virginia Electric & Power Co
5250 REEVES AVENUE 3 VA
•
Ret
5250 12TH STREET
3 VA
Ret
5250 SURRY
3 VA
1
1972
847.
O
N
74.
R
5250 NO. ANNA
3 VA
3
1977
907.
H
P
N
76.
R
Wallinqford Dept. of
5255 PIERCE
Public
1 CT
Utilities
1 1954
7.
C
M
S
0.
M
5255 PIERCE
1 CT
2
1954
8.
C
M
S
0.
M
5255 PIERCE
1 CT
3
1954
8.
C
M
S
0.
M
Washington Public Power Supply !
5315 HANFORD ' 0 WA 2
System
1977
1103.
C
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N
70.
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West Texas Utilities
5430 OAK CREEK
Co.
6 TX
1
1962
62.
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47.
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Wiscoasin Electric Power Co.
5530 COMMERCE 5 WI
15
1941
35.
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41.
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5530 PORT WASHINGTON
5 WI
1
1935
80.
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5530 PORT WASHINGTON
5 WI
2
1943
80.
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35.
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5530 PORT WASHINGTON
5 WI
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1948
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5530 PORT WASHINGTON
5 WI
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1949
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5530 PORT WASHINGTON
5 WI
5
1950
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5530 E WELLS STREET
5 WI
2
1954
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$HS0EB4fiwftg8r ' Li9hl SS-
4
1969
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Wisconsin Public Service Corp.
5545 WESTON
5-/WI
1
1954
60.
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5545 WESTON
5 WI
2 1960
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Worthington Municipal Water & Light Dept., City of
5550
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-48-
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CHAPTER THREE
ENVIRONMENTAL IMPACT OF
THERMAL POLLUTION AND POLLUTION ABATEMENT
3o1 Introduction
The environmental implications of thermal pollution
have to be considered in two separate dimensions: the
environmental effects of the thermal effluent itself, and
the environmental effects of the control technology cho-
sen to abate the thermal pollution. This chapter deals
first with the effects of thermal pollution on biota in
three alternative receiving waters, and then analyzes
the risk inherent in not controlling thermal pollution
The chapter concludes with a discussion of the various
environmental impacts of the control technologies avail-
able to abate heat discharges.
3o2 Effects of Waste Heat Discharges
Waste heat discharges have two major effects on a-
quatic environments: The first is heat death, and
the second, forced migration of species„ Heat death is
more important in warmer environments than it is in cool-
er environments since species in warmer waters often are
living close to their thermal death points„ Forced mi-
grations are important in any environments where migra-
tion occurs readilyo This is particularly true in riv-
er environments, In lakes In which fish can easily move
longitudinally from the lake and for estuarine species
which are not restricted to an estuarine habitat» The
tolerance of different species living in different niches
varies to a significant extent„ According to work done
by Naylor1, inter-tidal organisms usually have a greater
tolerance in high temperatures than sublitoral organisms
in estuaries, A study by Heinle^ shows that metabolic
1. Naylor, E„ (1965) Advanced Marine Biology 3:63.
2. Heinle, Donald R» (1969) Temperature & Zooplankton,
Chesapeake Science 10 (3 & 4): 186-209-
-H 9-
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rates of plankton are dependent on temperature, and
that acclimation was of little effect in raising the
upper limit of thermal tolerance. For many species
studied in the Chesapeake Bay the upper limit of thermal
tolerance was near the normal summertime temperature in
this habitat during the study period. Thus it appears
that the critical period of aquatic environments from a
standpoint of thermal pollution is during the hottest
times of the year, when small thermal augmentation can
have lethal effects„
Thermal pollution is often discussed in the con-
text of migration, and breeding of fish species. Fish
are often most sensitive to temperature during breeding
timeso Often the range for successful breeding of a
particular fish species will be only a few degrees. In-
nate behavior patterns have established particular spawn-
ing routes and migration routes for fish species; thus
particular rivers may be the sole or primary spawn-
ing grounds for a species inhabiting a large coastal line
area or inhabiting many rivers. Or, for example, one lake
may be the spawning ground for an entire river0 Thus,
thermal plumes which disturb fish enroute to spawning
grounds or effectively cut off normal migration routes
will have important effects on fish species using these
particular waterways as permanent and primary routes. It
is not well understood exactly under which circumstances
the fish will establish new spawning routes; however, in
several cases fish species have declined in importance
when their traditional spawning routes have been tam-
pered with. These include salmon, sturgeon, and certain
trout species.
Generally it can be said that species such as plank-
ton, algae, and bacteria are much more resistant to tem-
perature change than higher trophic level species such as
large fish and large invertebrates. Also effective
to a large degree are large primary producers such
as certain angiosperms0 Areas are generally consid-
ered high risk if discharges to these areas have impor-
tant effects on major migratory routes, important spawn-
ing grounds, or if mortality limits will be exceeded for
a significant portion of the upper trophic level species
of an aquatic community„ Mortality data for many fish
species is conveniently tabluated in the EPA manual Pro-
posed Criteria for Water Quality, Volume 1, printed in
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October 1973» It becomes clear from a perusal of this
data that the upper threshold for many fish has not been well
determined,, Clearly, further research in this field will
be important if the EPA is to make intelligent and quan-
titative decisions on ecological risks of waste heat dis-
charges o
Detailed information concerned with the effects of
thermal discharges on ecosystem stability is based on
qualitative judgment of biologists., The only quantitative
work which has been done is theoretical. In general, how-
ever, a given aquatic ecosystem exists at its optimum
temperature. Thermal discharges raise the temperature
above the optimum, decreasing productivity, and in-
creasing population levels. This in turn weakens some
of the trophic links reducing the complexity and bal-
ance of the food webo This weakening of the stable com-
plexity results in overall loss in ecosystem stability
and robustness. If thermal effluents are raised to de-
grees which kill off large populations of particular spe-
cies, then links in the trophic web are broken. At that
time species diversity decreases and stability is de-
stroyed. A loss in ecosystem stability means that popula-
tions of remaining species which are resistant to lethal-
ity of temperature increases will show characteristic
oscillations in population. That is, stable limit cycles
will prevail over stable equilibrium populations. Popula-
tions will oscillate rapidly from very high populations
to very low populations. In some years many fish will be
found; in some years few fish will be found. There will
be widescale plankton and algaeblooms causing nuisance to
observers and commercial users. The critical level to be
avoided in regulation of thermal discharges is the partic-
ular point at which stability decreases to a point at
which stable limit cycles become dominant. The determi-
nation of this point requires further study and such study
should be funded. At the present analytical level, our
ecological risk analysis represents the state-of-the-art
in waste heat discharge risk analysis.
3.3 Ecology of Alternative Receiving Waters
In the previous section, the environmental hazards
attributable to the employment of cooling systems were
discussed. In this section the fundamental environmental
problems attributable to the disposal of waste heat are
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described for the three predominant biomes: rivers, lakes
and estuaries, into which electric power plants discharge
waste heat. This project focused almost exclusively on
the Impact of waste heat on aquatic communities0 The
issue of entrainment (the termination, killing, or dam-
aging of organisms dragged through the cooling system),
was not dealt with in detail but the method of analysis
employed to examine biological risk attributable to dis-
charges of heat through these habitats is suitable for
entrainment, as well. As a result the lack of a specific
investigation of the entrainment issue should not miti-
gate the usefulness of these findings.
It is important to cite the specific features that
distinguish rivers, lakes and estuaries from one another„
Physically, chemically, and of course, biologically, these
habitats differ significantly from each other and tend
to be affected by power plant discharges in different
fashions. As a result they should be considered in an
administratively distinct manner by environmental policy
makers.
3.3ol Rivers
Rivers are subject to wide fluctuations of flow„
Considerable research^ has shown that flow in an unreg-
ulated river is a random variable. For the sample of
plants studied by ERCO, maximum flows (daily) exceeded
minimum flows (dally) sometimes by a factor of over 100.
Significant variability in time has also been observed.
Because of the fluctuations that occur in river communi-
ties, the organisms that adapted to these 'communities
differ significantly from those which survive in lakes
and estuaries in one Important respect: namely, the dis-
tribution of biomasso The proportion of biomass by basic
organism group is considerably different in rivers. The
biomass in rivers largely consists of organisms capable
of swimming, the pelagic fishes and organisms adapted to
live on the bottom and on the shore, and the benthos.
Although plankton are present, and at times may be highly
I. Some of the significant work has been done by M.B0
Fiering and Barbara Jackson of Harvard University,,
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productive, they are controlled by predatlon and the im-
pact of turbulence In fast moving systems.
Waters of different temperatures are of different
density, therefore warmer water when added to the surface
of a body of colder water will remain on the surface.
Warmer water which is added will only be dispersed equally
throughout a receiving water body if mixing of the differ-
ent density waters is forced. This will occur if the
water is injected below the water body surface or if there
are areas of turbulence where currents force vertical
mixingo Therefore, waste heat releases are usually pres-
ent in the receiving water as a surface layer,1
Because waste heat releases predominantly remain in
surface layers, their effect on aquatic communities can
be considered roughly proportionate to the amount of water
in the system employed for cooling purposes. This vari-
able is dependent upon flow and, as stated above, is ran-
dom in nature,, As a result it is possible to reasure the
risk attributable to heat releases in rivers as a function
of two variables: the amount of water employed for cool-
ing purposes in a plant over time, and the amount of water
available in the river which could be employed for cool-
ing purposes.
The justification for the selection of this tech-
nique is as follows:
(1) This risk analysis model is a "macro" technique;
it is based on evaluation of overall trends. The data
available are on the same order of detail as the model;
therefore this model makes most effective use of the
data. Such a model works. Microstructure models dealing
with detailed interactions of components rarely give
sensible results. For example, thermal plume stimulation
models incorporate many of the complexities of fluid
dynamics but have nevergiven sensible results^kecause
the mlcrocomp±cxltie-S"~Sre not exactly understood and the
1 Davis, The Marine and Fresh Water Plankton, Michigan
State University Press, 1955. PP» 12-15,
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V
, data are not good enoughc Use of a microstructure model
Kjwith macrostructure data is misleading..
N/ , x
J (2) Because warmer water remains surface water,
addition of a particular volume of water will affect the
surface volume of a river's water significantly rather than
affecting the entire river» Assuming that the volume
of water heated will have deleterious effects on the
aquatic community, the total risk can be expressed as a
y proportional volume, relationship,,
(3) Ecosystems are robust due to trophic structure
and diversity., Thus, chronic effects of changed river
temperatures are minimal,, Migration and selection reduce
effects on the rest of the river strata,, Such effects
would add other terms to the model., Because of ecosystem
resilience, the deletion of those terms gives a realistic
prediction of long-term effects„
(4) Pulse discharges were not important in the
sample, as compared with flow variance„
(5) Spawning grounds and migration routes will be
affected if the bottom waters are warmed or if a large
enough portion of the river is heated to act as a migra-
tory barrier,, For cases in which those affects will
occur the model will categorize the discharge as high
risk.
(6) Swiftly flowing rivers and streams are much
poorer in plankton than larger, slower rivers,1 Thus,
rivers which do not display stratification are also less
productive. Thus environments for which the model may
be questionable^ are the ".unproductive" environments "which
a-re-less'important ecologically0 — ^JVo.
To the extent that a power plant uses all of the I
flow available for cooling purposes, total biological
destruction is possible, in that all of the organisms
would be taken through the plant and subjected to a
significant, instantaneous rise in temperature, then
hurled out into the stream,, If a large percentage of
the available flow is heated, a large percentage of the
<¦£
1. Davis, The Marine and Fresh Water Plankton, Michi-
gan State University Press, p„ 16, 1955=
_5H_
-------
river volume will be heated and all portions of the
aquatic community will be subjected to deleterious heat-
ing,, Refuges will not exist„ On the other hand, if the
power plant uses a very small proportion of the flow in
the system, then a very small percentage of the biomass
can be affected by the discharge„ That is, a small per-
centage of the river volume will be heated© The eco-
system will be resilient to this reasonable stress, which
can be likened to a hot spell which warms surface waters
excessively,, Refuges will be present for all mobile
species, while immobile species are adapted to withstand
reasonable stress. This is particularly true because
rivers witn enough volume to support electric power fa-
cilities are likely to be stratified, with organisms well
adapted to avoid heated zones of the river,, For example,
surface heating on the Mississippi does not affect the
general thermal profile of the river.1 Benthic organ-
isms would, of course, not be affected directly by
stratified heat releases. Another factor which mitigates
the impact of waste heat releases is that on many streams
it is observed that the plume is confined to one bank of
the river, leaving a zone of passage for migratory organ-
isms. The last factor which reduced the impact of par-
ticular extreme environmental Insults on rivers is that
rivers have the capacity to restore themselves more easily
than do other aquatic environments, because organisms can
migrate from unaffected tributaries, from source lakes
or from ocean areas to repopulate and restock riverine
communitieso The environmental analysis has taken into
account the basic risks associated with the employment
of river waters for cooling purposes. This is described
in section 3o4.
3„3o2 LaKes
Lakes differ from rivers in their response to
thermal changes in the environment. A lake's hydro-
logical system has a restorative capacity which con-
strains it to respond to stresses less effectively than
rivers.
1. See extensive data and analysis by Middle South
Utilities.
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Lakes are stable physical systems„ The water level
In lakes varies only slowly and this variation is not such
as to change the overall structures of aquatic niches„
Lakes generally accept inflow from three sources: rivers,
springs, and watershed runoff0 Lakes are natural im-
poundments and water has a long residence time within a
lake, outflowing with a restricted rate into one river.
Because of the long residence time of water in a lake
environment, any physical characteristic of the Inflow
from rivers, springs, and watersheds will have a non-
temporary affect on the lake's aquatic systemu Similarly,
any artificial change in a lake's environment such as
thermal effluent, will have a long-term affect
A lake is a much less stressful environment than a
rapidly moving river or a partly saline estuarine environ-
ment o Therefore, a greater diversity is found in this
more deterministic environment. The benthos is less
important in a lake than in a river or estaary because
the water is quiet and therefore all of the depth layers
of the lake can be occupied by organisms0 Organisms
tend to move away from the bottom layer. In a lake, the
surface plant species and small aninals can float or move
about free from current and turbulence. The optimal depth
for growth of phytoplankton is significantly below the
surface because of the too high light intensity at the
surface. This contrasts with a river environment where the
rapid river flow, rapids, cross-currents, ripples and
eddies all contribute to the instabilities of the sur-
face layer. Therefore, on a lake, discharge from a power
plant will affect the aquatic environment when it forms
a surface thermal plume,. For example, slight rises in
temperature will provide optimal conditions for heavy
growth of surface algae, plankton, duckweed, and other sur-
face vegetation. High temperature discharges will kill a
variety of surface organisms such as Insects, surface
feeding fish, and surface floating plants„2 The plank-
ton layer below the surface will not be affected by sur-
face heating. Also, plankton migrate away from areas
which are adverse.
1. Macan, T.T», Ponds & Lakes, Crane Russak & Co.,
N.Y., 1973.
2. Davis, The Marine and Fresh Water Plankton,, Michi-
gan State University Press, 1955. pp. 10-16, 62-68.
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Some large lakes such as Lake Ontario and Lake Erie
are characterized by substantial circulatory currents,
but In general lakes show clear stratification into several
temperature and life-zone layers„ Thus, discharge of a
thermal plume to the surface layer of a lake will have a
minimal direct affect on intermediate (thermocline) and
bottom layers (hypolimnion) at least in late spring to
early fallo1
Lakes vary from being oligotrophic and not diverse
to productive and highly diverse to highly eutrophic and
not diverse„ Generally, a more complex and diverse system
will be more resistant to stresses such as thermal changes
in the environment„ Highly eutrophic lakes are usually
in a senescent stage of metamorphosis and therefore the
effect of thermal discharges will be minimal0 Oligo-
trophic lakes which are not particularly diverse will be
affected by any thermal discharges.
Lakes have little restorative capacity because they
are Impounded systems and water has a long residence time
within them„ They also have little flow or capacity to
quickly reaerate the entire system. When temperature
increases this decreases the dissolved oxygen saturation
level and reaeration can only take place gradually.
Water inflows which form a significant fraction of the
total water inflow and which are at significantly dif-
ferent temperature from the ambient temperature will
tend to change the overall ambient temperature. Thus,
thermal discharges from power plants on lakes, can, over
a time period, slowly raise the overall temperature of
a lake until the biological community present is com-
pletely different from that which existed before the
thermal discharges began,, Whether a new stable ecosystem
will replace the one displaced by temperature rises will
depend on random colonization processes of biological
systems and also on migratory patterns.
Migration is not a dominating factor in lakes as
it is in riverso Many species of fish spend their
1. Davis, The Marine and Fresh Water Plankton, Michi-
gan State University Press, 1955. PPo 10-16, 62-68„
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entire life span within one lake.* Plankton are resi-
dential within a particular lake system, A percentage of
the produced plankton are washed downriver continually
but the plankton community cannot migrate to another pond
or lake» Within a lake, however, plankton migrate to
avoid stress.2 The response of plankton to adverse con-
ditions is to enter a resting stage rather than to migrate
Thus, in general, members of lake ecosystems have little
opportunity to find refuge from adverse conditions which
affect the entire lake. Because of the usual separation
of lakes by stretches of rivers, lake species residing in
another lake do not quickly move into the lake when con-
ditions within the lake become optimal for their particu-
lar niche requirements. Thus, stress imposed on an entire
lake can degrade the community diversity more easily than
stress imposed on rivers0
The response of lakes to thermal discharges then is
quite different from the response of rivers. The response
of lakes is dominated by the long residence time of water,
stratification of water levels, and characteristic eco-
system organization of lakes. Lakes which will be most
sensitive to thermal discharges are oligotrophic lakes
(with low diversity), small lakes (with less layers un-
affected by discharges) and quiet lakes which display
few mixing currents to dissipate waste heat.
3»3°3 Estuaries
Estuary environments are evaluated on a site-specific
basis in the thermal analysis. Estuary environments have
unique characteristics which require that their sensi-
tivity to thermal pollution be assessed separately from
ocean, lake, and river environments.
1. Eddy, How to Know the Freshwater Fishes, 1969,
Brown Co., Dubuque, Iowa, and
Macan, T.T.Ponds and Lakes. Crane Russak & Co.,
N.Y., 1973.
20 Davis, The Marine and Fresh Water Plankton, pp„ 110-
118.
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Estuary environments show daily oscillations of
salinity content„ Thus, certain species will be limited
by the daily maximum or minimum of salinity concentration.
The salinity wedge is a dominant feature in an estuary
environment. Water coursing into the estuary environ-
ment from the river will meet waters of ocean origin,,
The salt water is denser and therefore will form an
underlying wedge extending upstream underneath the sur-
face fresh water,, Stratification of the less dense fresh
water and more dense salt water occurs. Several power
plant sites have been able to make use of these strati-
fication characteristics for advising schemes for
minimizing the effects of thermal pollution: since
warm water is less dense than cold water it can form
stratification in addition to the salinity wedge layers,
and so waste heat can be differentially ejected into
the least biologically inhabited layers0 (For example,
the Northside #1 plant of Jacksonville Electric Co0)
Estuary environments are characterized by nutrient
upwellings and so are highly productive,, However, the
unique nature of the environment as an aquatic system
with varying salt concentrations makes it an adverse en-
vironment for many species. The number of species which
have become particularly adapted to estuary conditions
is quite small, but these small numbers of species are
often highly productive. Because of the stresses put
on the estuary environment those species which are
adapted to living in its confines are able to withstand
frequent fluctuations in the environment0
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The low diversity! of the estuary environment and
the degree of specialization of its species make this an
environment which is particularly susceptable to un-
natural stresses, although the species are well adapted
to deal with the particular variations in stress which
are naturally imposed on the community. Unnatural vari-
ations such as added thermal augmentation by power plants
can have considerable affect on the structure of the
community.
1. Diversity is related to the extent to which an en-
vironment provides a predictable, resource-rich, un-
hostile environmento The richer and more conducive
to continual growth an environment is, the more
specialization will take place and the more diverse
the ecosystem will become0 This is because the or-
ganisms do not need to reserve much energy for sur-
vival in adverse conditions or for coping with fluc-
tuating constraintso
In an estuary, daily tidal fluctuations occur. These
cause daily fluctuations in water depth, temperature
rise due to insulation (greater in shallow water)
and changes in salinity. Thus, the environment is
hostile: species adapting to life in estuaries
must reserve energy for surviving stress. Energy
is not available for extensive colonization of
species experiments in specialization,.
However, during periods of low stress (late spring,
summer, calm weather), because nutrients are readily
available, populations will be maintained at high
levelo
The hostility and stresses of estuarine environments
have made it unprofitable for most species to ex-
pend the evolutionary energy to become perfected
for life in estuary niches„ Therefore, there are
only a small number of species living in estuaries.
However, many nutrients are available from time to
time in estuaries. For the few species which have
become adapted to the estuarine environment, pro-
ductivity is consequently high. Estuaries support
little of the diversity but much of the productivity
of the aquatic ecosystems.
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Therefore, in assessing the impact of an estuarine
power plant on the estuarine environment, several key
considerations are taken into account„ First, the key
area which will be affected by the thermal plume can be
evaluated. The salinity wedge will often limit this to
a surface area and the tidal ebbs and flows will distrib-
ute the thermal plume in characteristic fashions„ In
an estuarine environment the benthic fauna and flora are
a particularly significant segment of the ecosystem,,
Therefore, surface thermal plumes will not affect a large
segment of the trophic structure„
The particular sensitivity of the estuarine commun-
ity to the particular thermal augmentation can be evalu-
ated. Unlike a river or lake environment, if the ambient
community is displaced because of the specialized nature
of the estuarine community, there will often be no other
organisms with adjoining ranges which can move into the
niche structure at a higher temperature. In a river,
simple migrations may take place,, In an estuary, dis-
placed organisms may not find suitable adjoining habi-
tats with suitable salinity, topographic structure and
temperature ranges. Estuarine species which can tolerate
higher temperature levels may not be able to easily migrate
into the area.
Generally, an estuary can tolerate a moderate level
of thermal discharges if all discharges remain in surface
layers where the temperature differential can be equal-
ized by contact with colder water and with the air. When
thermal discharges reach a level which forces warmer water
down into subsurface layers, the members of the estuarine
benthic community will be disturbed. Because of the low
diversity and specialized trophic structure the balance
of the estuarine ecosystem can be easily disturbed under
those conditions even though productivity is high,, Es-
tuarine analysis of power plant discharges is undertaken
on a site-to-site basis following these criteria,,
3.3„4 Stability and Ecosystem Resilience
The risk analysis tends to overexaggerate the
effects of waste heat discharges,, Effects on aquatic
populations will tend to be less than predicted because
of the resilience of ecosystem to stress.^ The follow-
1. See, for example, Gibbons & Sharite,"Thermal Alter-
ations of Aquatic Ecosystems", American Scientist.
62: 660-670, (1974).
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ing characteristics of aquatic systems contribute to the
stability and robustness of the ecosystem:
(1) Trophic interactions: That is, a variety of
predators feed on a variety of prey and can "switch" prey„
(2) Migration: That is, species which are mobile
can move to avoid local stress„
(3) Refuges: That is, there are usually at least
small refuges from stress„
(4) Adaptive Potential: Certain form will be best
adapted to heated environments„ Most populations will
be genetically varied enough to Include those forms.
While an environment is heated, those forms will flourish
and will dominate species populations,,
3.4 Environmental Risk Attributable to the Employment
of Once-Through Cooling
In order to ascertain the impact of once-
through cooling, it is first necessary to understand
which factors influence environmental risk, and which of
these could be modified by technology or management to
reduce the environmental hazard attributable to once-
through cooling. Prom the point of view of the receiving
water body, once-through cooling is a euphemism for no
cooling at all. Water is taken into the steam-electric
power plant, employed to exchange heat from steam and
discharged at a higher temperature into the receiving
water, either treated or untreated by mechanical or en-
gineering systemso The amount of water employed at a
particular site is a function of the average capacity
factor at which it operates. The amount of heat dis-
charged is a function of the average capacity factor
and of the type of power generation,. Steam-electric
power plants are typically base-load or cyclic,. Base-
load plants tend to run at nearly constant levels when
in operation, while cyclic plants are used periodically
to provide additional power production during day-time
hourSc As a result, water requirements may be either
invariant for base-load plants or somewhat variant over
time for cyclic facilities0 The conservative assumption
of full loading was employed in the analysis which is
described in greater detail below.
Variability in river flow is far more important in
terms of ecological implications than variability in
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plant draft (outside of certain cold water situations)„
Energy Resources' sample of 180 power plants involves
sites with enormous flow variability, the extent of which
was alluded to above in the discussion of ecological im-
plication in rivers. It is safe to say from a review of
the hydrological data that rarely did flow in a system
fail to vary at least by an order of magnitude„ This
means that if the draft of cooling water for once-through
purposes tended to be constant, the proportion of the
system affected by this draft would vary as a function of
the flow. Employing this observation, the concept of
safezones was developed,, A safezone is said to be the
portion of the discharge body which has its temperature
unchanged,, Since heated discharges stratify in all but
the most turbulent of power plant site locations, the
safezone concept proves empirically to be a valuable one0
Safezones exist because of the stratification discussed
in 3o3. ERCO employed a model developed by Richard
Rosen-'-, which recognizes two important pollutant charac-
teristics of cooling intake water - the thermal effects
and entrainmento The thermal effect is directly propor-
tionate to the volume of the river, which is employed for
condensing purposes because stratification limits temper-
ature change to a proportion of the river volume. When
small volumes of water relative to total flow are required,
the extent of the impact of the heated water surface is
minimized,, When the entire stream is required, the
effects are maximized,,
The safezone analysis assumes that the portion of
the river which is heated will be deleteriously affected.
This is an assumption which makes the analysis overstate
risk. The only possible understatement of risk is due
to the heterogeneity of population distributions„ Bio-
logical effects of heating include:
(1) Blocking of the movement of anadramous fishes,
(2) Acute effects on adults,
(3) Impact on the macrobenthos,
(4) Effects on juveniles.
1 Research related to Ph0D» thesis at Harvard Univer-
sity .
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Strategies employed by organisms for avoiding thermal
damage include:
(1) "Migration" or range shifting,
(2) Entering a resting stage,
(3) Alterations of biochemical systems to raise thermal
tolerances,
(4) Dying back of vegetative portion of plants„
Figure 3.1 displays the habitat of the benthos, the
optimal phytoplankton layer, and the cross-sectional
dimensions of both the heated and the unaffected river
segmentso For purposes of this analysis, the vertical
dimensions of the unheated zone will be called the safe-
zone because of the ability of heat avoiding pelagic or-
ganisms to find safe areas in heated effluents,, That is,
mobile organisms can move to the unheated zoneD Clearly,
when the upper limit of the unheated zone is deep, the
refuge provided will be limited by available light. If
this variable approaches 0 and the temperature in the
stream rises to levels which are fatal to anadramous
fish, then upstream migration will be prevented and
reproduction inhibited,, Under similar conditions, heat-
sensitive species may also be exterminated,, Several
studies of the affect of heat releases on aquatic com-
munities are alluded to elsewhere, but it is useful to
reconsider the effect on both benthic plants and animals
of their loss of habitat. It is also useful to allude
once again to the effects on juveniles which are mini-
mized to the extent that thermal involvement of the
stream is also minimized,,
Downstream
Safe
Affected
SAFE ZONE
FIGURE 3-1
-64-
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Employing flow data from the geological survey and
information available from Form 671 on the drafts of 11?
river plants, an analysis was performed with the assis-
tance of this model. Let equal the draft of the ith
plant, Fj_, the flow of the river for the ith plant, and
Si3 the vertical dimension of the proportion of the river
safe for the i plant. Then:
This model was used to generate (for these plants) a dis-
tribution of safezones. The analysis was performed on
both summertime and wintertime flows. Of interest are
the statistics which were derived from these data, which
related the cost attributable to particular pollution con-
trol policies designed to inhibit waste-heat releases and
the environmental risk associated with these policies.
Table 1-1 identifies the variety of policy options which
were considered, their costs and the environmental risk
associated with each of these options. The environmental
risk attributable to a waste-heat release in a particular
river was estimated using the 10-year summertime flow data
provided by the United States Geological Survey. The en-
vironmental risk number was developed in the following
way — the model discussed above was used to generate site
zone numbers, which were distributed in accordance with
Table 3-1. It was necessary in order to assess whether
or not plants were safe, unsafe, or required further re-
search activities, such as those contemplated under Sec-
tion 316, to establish a decision rule which could be em-
ployed to identify which plants belonged in the afore-
mentioned category. As a result of consultation with
numerous biological "scienfTsts employed""by universities, (
Dirivart1'l:ne.S-ear.ch oxgani zatlxms-^and government age.nc ies11
a number reflecting environmental—hazar.cL.associated with
~a~fr'a'C't'1ran—oif—river water employed, for, cogling purpose
was ae'trfe'rlffined" "This Jnumher. was 70% of r-i.v.&r—v.o 1ume... .
Similarly, ft was determined that plants which use less
1. FPC Form No. 67, Federal Power Commission.
2. See page 4.
-65-
-------
than 30$ of river volume presented little or no hazard;
while plants which use between 30 and f0% of flow for
cooling purposes presented a risk, which could not be as-
certained without a detailed biological demonstration such
as that contemplated under Section 316(a)„ In order to
develop the environmental risk numbers, ERCO first es-
tablished the net generation for each plant and then de-
termined the total fraction of high risk net generation,
which would be exempted if that option were to become the
basis for coverage by the federal thermal control regula-
tions for steam-electric power plants. Column two shows
what the risk would be after 316(a) exemptions. This
cost column shows that 316 reduces costs by an average of
63% using the assumption that half of the plants in the
indeterminate category would be exempted after a 316(a)
analysiso Of course, one must understand that the en-
vironmental risk numbers developed for theno scenarios
assume the distribution of cooling equipment which will
exist in 1978 without national regulation,, 1
It was necessary to determine the advisability of
the particular decision rule employed to divide power
plants into the three relevant categories,. As a result,
a sensitivity analysis was done where the upper and lower
safesone parameters were varied for the population under
study.
lo It is estimated by TBS that ^5% of the capacity and
49% of the net generation would be closed cycle in 1978
without national regulation,,
-66-
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% OF SAFE ZONE FRACTION BY SAFE ZONE DECTILE
RANGE OF S
% OF OBSERVATIONS
.9 < S < 1.0
47.63
.8 < S < .9
12.68
.7 < S < .8
7-31
.6 < S < .7
5.23
.5 < S < .6
3.64
< S < .5
2.33
.3 < S < .4
1.62
.2 < S < .3
1.47
CM
V
CO
v|
r—1
1.15
i—1
V
CO
16.79
TABLE 3-1
This table shows what % of the power plant
sample fell Into each of the ten safezone
fractionso Thus, on .8-.9 Safezone rivers
there were 12<>68$ of the power plants.
A similar observation is made when one examines the
maximum percent safezone considered high risk, which was
-67-
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varied up to 50$, showing that once again only slight
changes in the total net generation at risk are observed.
Empirically, a calculation of standard deviation for each
of the rows shown in Table 3-2 (sensitivity analysis) is
helpful to fortify one's intuitive perception about these
results. It can be seen that the final decision made by
EPA has a coefficient of variation of almost 8%. This re-
flects a high level of invariance in the number, which in-
creases one's confidence in the stability of the final re-
sults.
These same results can be employed to develop sys-
tematic measures of losses in diversity which would occur
as a result of entrainmento This work was not done as a
part of this project, but could be performed if more time
were available for analysis.
3.5 Air Pollution Effects
3 o 5.1 General
The impact on air quality of alternative cooling
systems for power plants involves many processes which
are not well understood. Any cooling system will have
an energy penalty associated with it, which represents
the additional energy required to operate it above that
of a once-through cooling system. This additional energy
requirement from the power plant will directly Increase
the emission of air pollutants from fossil fuel plants.
Emissions from evaporative cooling systems consist of
water vapor and droplets of the circulating cooling waters.
These droplets, normally called drift, eventually fall
out of the plume under the Influence of gravity and are
deposited on the ground. These effects are associated
with nuclear as well as fossil fuel power plants.
The interaction of fossil fuel power plant plumes and
evaporative cooling system plumes can accelerate the pro-
duction of various secondary pollutants. Primary among
these is the production of sulfates.
Visibility changes associated with fogging from
evaporative emissions and the production of sub-micron
aerosols by the secondary pollutant processes are dis-
cussed briefly and the health and vegetation effects of
drift deposition and secondary pollutant production are
reviewed.
-68-
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SENSITIVITY ANALYSIS
OPTION
MINIMUM
PERCENT SAFEZONE
CONSIDERED
LOW RISK
40%
60%
70%
80%
90%
1979
100
100
100
100
100
197^
70
71
75
76
78
1972
57
59
65
66
69
1970
49
51
58
59
62
Small, 40$,
1956
12
12
23
25
29
Small, 1950
3
3
3
3
3
FINAL
55
57
63
64
67
OPTION
MAXIMUM
PERCENT SAFEZONE CONSIDERED
HIGH RISK
10%
302
50%
1979
100
100
100
1974
75
75
76
1972
64
65
66
1970
58
58
60
Small, 40%,
1956
3
3
3
Small, 1950
3
3
3
PINAL
63
63
64
Effect of varying upper and lower safezone limits on the
percent of high risk net generation exempted.
Describes the relevant results of the sensitivity analysis.
It can be seen that when the minimum percent safezone con-
sidered low risk is reduced from 30% to 10%, the environ-
mental risk rises only slightly. This, of course, reflects
the biomodality of the distribution of safezones which was
described in Table 3-1-
TABLE 3-2
-69-
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3.5*2 Drift Deposition From Evaporative Cooling
Systems
Drift deposition poses a potentially adverse environ-
mental impact on areas surrounding cooling towers and spray
pondso The drift consists of liquid droplets carried out
of the cooling tower or away from spray ponds which are
eventually deposited on the ground. In general they are
mechanically produced by the spraying and/or splashing of
the circulating water onto a packing contained in the base
of the tower. Breaking up the coolant into droplets in-
creases the surface to volume ratio facilitating the evap-
orative heat transfer. As the air moves upward through
the packing, unevaporated droplets can become entrained,
carried aloft out of the tower and eventually deposited
on the ground.
The behavior and environmental consequences of drift
are still somewhat speculative,, Numerous numerical models
have been proposed to describe drift deposition, but the
relative merits of each are for the most part yet to be
determined. Cooling towers and other evaporative cooling
systems have been little studied, making measurements of
actual drift rates to compare with model calculations
scarce. Although evaporative cooling systems have been
used in Great Britain for several decades, there are few
measurements of drift deposition in the literature. Al-
though this situation should improve in the next few years,
it means that we must rely on unvalidated model calcula-
tions for guidance.
The drift from an evaporative cooling system (see
Figure 3° 2) is usually characterized by the percentage of
circulating cooling water flow. Estimates of up to 0a5%
are common for uncontrolled systems. The experience in
Great Britain, however, where approximately 300 natural
draft cooling towers are in operation, is that actual drift
rates are always less than that. In fact, with the addi-
tion of proper drift eliminators, drift is estimated to be
less than 0.05/&» Values on the order of 0o005% are typical
for mechanical draft towers while natural draft towers
are currently being designed with drift rates of 0.002
to 0.003$« There is some speculation that actual drift
rates in these towers once they are in operation will be
as low as 0.001?. Proper eliminators reduce the total
amount of drift by removing the larger droplets altering
the mass distribution of the drift. While this implies
-70-
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SENSITIVITY ANALYSIS
OPTION
MINIMUM PERCENT
SAFEZONE CONSIDERED
LOW
RISK
40% 60%
70%
80%
90%
1979
100 100
100
100
100
1974
70 71
75
76
78
1972
57 59
65
66
69
1970
49 51
58
59
62
Small, ^40%, 1956
12 12
23
25
29
Small, 1950
3 3
3
3
3
FINAL
55 57
63
64
67
OPTION
MAXIMUM PERCENT
SAFEZONE CONSIDERED
HIGH RISK
10%
30%
50%
1979
100
100
100
1974
75
75
76
1972
64
65
66
1970
58
58
60
Small, 40%, 1956
3
3
3
Small, 1950
3
3
3
FINAL
63
63
64
Effect of varying
upper and lower safezone
limits
on the
percent of high risk net generation
exempted.
Describes the relevant results of the sensitivity analysis.
It can be seen that when the minimum percent safezone con-
sidered low risk is reduced from 30% to 10%, the environ-
mental risk rises only slightly. This, of course, reflects
the biomodality of the distribution of safezones which was
described in Table 3-1-
TABLE 3-2
-69-
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3.5.2 Drift Deposition From Evaporative Cooling
Systems
Drift deposition poses a potentially adverse environ-
mental impact on areas surrounding cooling towers and spray
pondso The drift consists of liquid droplets carried out
of the cooling tower or away from spray ponds which are
eventually deposited on the ground. In general they are
mechanically produced by the spraying and/or splashing of
the circulating water onto a packing contained in the base
of the tower. Breaking up the coolant into droplets in-
creases the surface to volume ratio facilitating the evap-
orative heat transfero As the air moves upward through
the packing, unevaporated droplets can become entrained,
carried aloft out of the tower and eventually deposited
on the ground.
The behavior and environmental consequences of drift
are still somewhat speculative„ Numerous numerical models
have been proposed to describe drift deposition, but the
relative merits of each are for the most part yet to be
determined,. Cooling towers and other evaporative cooling
systems have been little studied, making measurements of
actual drift rates to compare with model calculations
scarce. Although evaporative cooling systems have been
used in Great Britain for several decades, there are few
measurements of drift deposition in the literature. Al-
though this situation should improve in the next few years,
it means that we must rely on unvalidated model calcula-
tions for guidance.
The drift from an evaporative cooling system (see
Figure 3«2) is usually characterized by the percentage of
circulating cooling water flow. Estimates of up to 0o5%
are common for uncontrolled systems„ The experience in
Great Britain, however, where approximately 300 natural
draft cooling towers are in operation, is that actual drift
rates are always less than that. In fact, with the addi-
tion of proper drift eliminators, drift is estimated to be
less than 0e05%o Values on the order of 0,003% are typical
for mechanical draft towers while natural draft towers
are currently being designed with drift rates of 0,002
to 0.003$, There is some speculation that actual drift
rates in these towers once they are in operation will be
as low as 0.001%. Proper eliminators reduce the total
amount of drift by removing the larger droplets altering
the mass distribution of the drift. While this implies
-70-
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SPRAY CANAL
MECHANICAL
DRAFT
VCOOLING
\ TOWER
\
2
O
£ 10
H
00
o
Ol,
w
Q
10
10
.01
.1
1
10
DISTANCE DOWNWIND, km
Shows deposition rates from wet cooling systems as a function
of downwind distance under neutral atmospheric conditions.
FIGURE 3-2
After A. Roffman & R.E.Grimble "Drift Deposition Rate
from Wet Cooling Systems. Presented at Symposium on Cooling
Towers Environments, University of Maryland. March, 197*1-
-71-
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RANGE OF DISSOLVED SOLIDS FOR VARIOUS SOURCES
DISSOLVED SOLIDS
SEAWATER1
[mg/l]
A RIVER2
[mg/1]
A LAKE3
[mg/1]
Chloride
18,980
9-18
8.7
Sodium
10,560
7.6 - 12.0
5
Sulfate
2,560
19 - 37
20.7
Magnesium
1,272
4.3 - 11.0
12
Calcium
400
22 - 46
36
Potassium
380
1.0 - 2.2
1.1
Bicarbonate
142
62 - 140
Bromide
65
0.10
Strontium
13
Boron
4.6
Fluoride
1.4
Silicate as Si02
0.4 - 8.6
2.1 - 6.5
Iron
0.002 - 0.02
0.030 - 0.140
0.24
Maganese
0.001 - 0.01
0 - 0.020
0.0062
Alkalinity as
CaCO-^
51 - 192
110
Zinc
0.005 - 0.014
Total Dissolved
Solids
104 - 200
174
1-U.S. Geological Survey
p
U.S. Geological, Hudson River near Poughkeepsie for
year October 1971 to September 1972.
^Lake Michigan in the area of Zion Generating Plant of
Commonwealth-Edison Co. [Lee G.F. & C. Stratton, 1972.
"The Case for Thermal Pollution, Industrial Water Engineer-
ing, Oct/Nov., pp. 12-16].
TABLE 3-3
-72-
-------
that the drift will be deposited further away from the
cooling system, it also means that the drift will be dis-
persed more efficiently by the turbulent motions of the
atmosphere.
Consistent with these drift rates, rain caused by
drift alone has generally not been a major problem,, Af-
ter frequent occurrences of drizzle at two British power
plants utilizing natural draft cooling towers, the elimin-
ators were found to be inadequate and replaced,, Measure-
ments were taken before and after the eliminator modifica-
tions. Prior to the installation of new eliminators,
drizzle was detected when the relative humidity was above
85%, and road-wetting was observed at relative humidities
greater than 90%. The peak drizzle occurred 200-600 meters
downwind of the tower. At the higher humidity levels,
drizzle was observed as far as five kilometers from the
cooling tower0 With improved eliminators, drift has been
reduced to 10-14$ of what had been previously measured,, 1
Eliminating possible rainout problems removes only
a small portion of drift potential environmental impact„
With smaller droplet sizes, a large portion of the drift
evaporates before hitting the ground under most conditions.
While condensation products such as cooling tower fog are
reasonably pure water, drift drops have the composition
of the circulating coolant. Through evaporation and the
addition of makeup water, concentrations higher than those
found in the source are reached in the cooling water after
a few cycles through the heat exchangers. Chemicals pres-
ent in the cooling water can therefore be deposited on the
countryside by the drlfto
"Salt" particles are the most common drift particle
considered, where "salt" Includes all solids dissolved
in the cooling water,, Impact is greatest from towers
using ocean or brackish water,, Although not generally
considered in respect to drift, so-called fresh water
contains a wide range of compounds with potential environ-
mental impact. Table 3-3 shows some representative values
for river, lake and ocean sources. In addition to the
natural constituents, various compounds are introduced
to retard algae growth and corrosion,, A number of these
additives are discussed in Table 3-4.
I. Ongoing research at Environmental Research Technology,
Lexington, Massachusetts.
-73-
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COMMON ADDITIVES TO CIRCULATING WATERS
PURPOSE
ADDITIVE
REMARKS
Bacteria
& Algae
Control
Chlorine
Often only added periodically
(3 times/day) for shock treatment
Deteriorates wood compounds
Organic Blocldes
Often contain arsenic, mercury,
lead, and tin
Seldom used today
Corrosion
Control
Organic Corro-
sion Inhibitors
Amount depends on relative cost
Polyphosphate compounds most
common
Other
Sodium Silicates, silicate-
condensed phosphate", "chromate
condensed phosphate", "organic
zinc", "chromate zinc", chromate-
zinc-organic", "nitrate-borate-
organic", "organic zinc-condensed
phosphate", "buffered chromate".
Scale
Control
Sodium
Hexametaphosphate
&
Sodium Silicates
Complex with scale, forming
elements
Ethylenediamine-
tetraacedic Acid
(EDTA)
Similar action but expensive
Sulfuric Acid &
Sodium Hydroxide
pH maintained at 6.5 - 8.0 by
the addition of sodium hydroxide
and sulfuric acid to decompose
carbonate ions
After Marshall(1971)
TABLE 3-4
-7^-
-------
Unfortunately, measurements of actual drift deposi-
tion rates are not available at this time. Measurements
are underway at existing installations in this country,
but these are few in number as previously described.1
Therefore, mathematical models must be used to flstimate
drift deposition using actual data whenever possible.
While validation has not been completed these models pro-
vide some information on what to expect.
Classical models for the estimation of dispersion
assume a conservative contaminant with no deposition.
In the case of the drift from an evaporative cooling
system, the contaminant, water droplets, are constantly
changing their character as well as being deposited on
the ground. The physical processes involved require
some discussion.
The plume, consisting of the drift water, its dis-
solved solids, and water vapor, is assumed to be saturated
with water vapor as it leaves the cooling system. The heat
and water vapor in the plume gives it buoyancy and lifts
the plume. Mechanical draft towers add vertical momentum
by fans for higher plume rise. The drift is carried aloft
in the plume as long as the upward motion of the plume is
greater than the settling velocity of the droplet. Set-
tling velocity is primarily a function of drop diameter.
The plume Itself is interacting with the ambient air by
mixing (entrainment); as environmental air is mixed, the
upward velocity of the plume decreases. The drift drop-
lets fall out of the saturated plume and begin to evapo-
rate 0
Evaporation implies that the diameter of the drops
is decreasing and that therefore they fall less rapidly,also
that the concentration of dissolved solids in the drift
is increasing. As the drops fall out of the plume they
are dispersed by the turbulent motions of the atmosphere.
The smaller particles with their lower inertia are dis-
persed most efficiently.
Hanna has described a drift deposition model account-
ing for plume rise, entrainment of ambient air, and varia-
tions in drop sizes. Applying this model to data from
the mechanical draft cooling towers at Oak Ridge, has
obtained estimates for the chromate deposition in the
1. Ongoing research atCEnvironmental Research Technology,
Lexington, Massachusetts.
-75-
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vicinity of the towers0 (The sodium dichromate is present
in concentrations on the order of 20ppm„) Table 3-5^below
gives the results„
AVERAGE ANNUAL CHROMATE DEPOSITION RATES
CLOSE TO COOLING TOWERS (Hanna. 1974)
X (meters)
East Sector
West Sector
5
23o2 ug/m2s
26,7 ug/m^S
10
40 6
5.3
20
1.3
1.5
50
.23
0 27
100
„08
.09
TABLE 3-5
2
Table 3-6 summarizes the various factors used in
modeling drift deposition and their possible effects.
Two types of factors are considered: those associated
with the environment and those determined by the cooling
towero
Despite variations in modeling techniques and input
parameters, a pattern does emerge with respect to the
type of cooling system employed,, The greatest potential
drift problems exist with spray ponds and the least with
natural draft cooling towers«
Roffman and Grimble present results from a cooling
down model in which they compare drift deposition from
three typical cooling systems„ A natural draft cooling
tower, a bank of fifteen mechanical draft cooling towers
and a spray canal, each with the same coolant circulation
rates (12.6m3/sec) and concentration of dissolved solids
(10,000 ppm)0
The spray canal, with its high drift rate (0„1%) and
low (ground level) emission height, has the highest depo-
sition rate with the peak occurring within one hundred
meters from the source.
1. S.R. Hanna. "Fog and Drift Deposition from Evaporative
Cooling Towers." Nuclear Safety, 15: 190-196. 1974.
2. S.M. Laskowski. "A Mathmatical Transport Model for Salt
Deposition from a Salt Water Natural Draft Cooling Tower
Part II." Preprint AMS, Santa Barbara Symposium. 1974.
-76-
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ENVIRONMENTAL FACTORS
PARAMETER
REASON
WIND SPEED
Important input to plume rise determination
High wind speeds can cause downwash of the
plume accompanied by high ground-level
concentrations
Low wind speeds allow for higher plume rise
giving drops longer path to ground
WIND DIRECTION
Especially important in dealing with the
poor aerodynamic configurations of munti-
cell mechanical draft towers
ATMOSPHERIC
STABILITY
Important input to plume rise determination
and dispersion
RELATIVE HUMIDITY
& AMBIENT AIR
TEMPERATURE
Have some effect on droplet evaporation
(relatively small effect on deposition
rates)
TERRAIN
Geographical formations can trap the plume
causing higher concentrations at some point
TOWER CHARACTERISTICS
VOLUME OF CIRCU-
LATING WATER AND
DRIFT RATE
Determine total amount of drift produced
"SALT" CONCENTRA-
TION IN DRIFT
Determines total amount of deposition
possible
Affects evaporation rates
SIZE DISTRIBUTION
OF DRIFT DROPS
Drop size determines terminal fall
velocity
Surface/volume affects evaporation
Laskowskl found peak deposition rate
proportional to mass drift rate of drops
300p in diameter
EXIT VELOCITY &
TEMPERATURE
Inputs to plume rise
TOWER HEIGHT
Along with plume rise determines fall distance
TABLE 3-61
J-See page 76, footnote 2.
-77-
-------
The mechanical draft towers, with a drift rate of Qo0Q5%,
show lower deposition rates with peak, values between 0ol and
1.0 kilometer downwind. With the same lower drift rate, the
taller natural draft tower has a smaller peak farther down-
wind than that of the mechanical draft towers„ The natural
draft tower exhibited the lowest overall deposition rates
for the three systems. Note that the two types of towers
have smaller total drift because of collection by drift
eliminators.
3o5«3 Formation of Secondary Pollutants
When evaluating alternative heat disposal techniques
for fossil-fueled power plants under the 30^ variance
procedure, particular attention should be given to the
formation of secondary pollutants from the interaction of
the plant's emission plume(s) and its (proposed) evapora-
tive cooling system plume(s)0 Of particular concern is
the accelerated oxidation of SO2 to sulfate in the plant's
plume(s) due to the influence of cooling tower emissions„
The following discussion concerns the Identification and
relative importance of SC>2 oxidation mechanisms as they
relate to power plant cooling tower plume interactions.
3.5°3.1 Definition of Potential Emissions
Fossil-Fueled Power Plant
The principal emissions of fossil-fuel power plants
are SO2, NOx and particulates„ SO2 emissions from both
coal-fired and oil-fired power plants are similar in quan-
tity since percent sulfur contents of both fuels are
regulated on a BTU basis„ The character of the particu-
lates emitted from burning of the two fuels, however, is
very different„ Coal-fired power plant plumes are approxi-
mately an order of magnitude dustier than oil-fired plant
plumes. The emissions from fuels contain metal sulfates
and metal oxides, but in different relative proportions„
The dust of oil-fired plants contains sodium and vanadyl
sulfates, but relatively little iron sulfate when compared
to dust from coal-fired plants„ Table 3-7 is a compila-
tion of emission factors for various trace metals for coal
and oil taken from the EPA report, Emissions Factors for
Trace Substances (Anderson, 1973)» The importance of the
differing ash contents in terms of sulfate formation will
be discussed in Section 3.5.3®20
-78-
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Cooling Tower Emissions
Emissions from (wet) cooling towers can be classified
into two categories: the evaporate-condensate plume and
drift. Since the evaporative plume is formed by conden-
sation, it consists of relatively pure water. Since drift
is formed by airstream removal of splashed droplets within
the cooling towers, it roughly contains the same concen-
trations of impurities as the cooling tower recycling water.
Chlorination and pH control are the most frequent cooling
water treatments for most power plants. Sulfuric acid is
commonly used to maintain pH in the 6.0 to 7-0 range. For
those site locations where the makeup water has a signifi-
cant amount of impurities, additional chemicals such as
chromates and phosphates are added for scale and corrosion
control, etc. For those site locations utilizing salt water
as makeup water, significant quantities of salt will be
TRACE METALS EMISSION FACTORSi
COAL (Kg/10^Kg)
RESIDUAL OIL (Kg/106 L)
RANGE
AVERAGE
RANGE
AVERAGE
Arsenic
2a
0.09 - 0.5
0.1
Beryllium
0.01a - 4.6a
1. 9a
0 . 02a - p.09
0. 08
Cadmium
0.1a - 0.5b
o. n°
0.5 - 5-0
3-0
Manganese
0.2a - 40.c
0. 3a
0.01 - 1.0
0.2
Mercury
0.02 - 0.41
0.2
0.0009 - 0.3
0.04
Nickel
0.2 - 0.5
0.3
-.0 - 60
10
Vanadium
0.2a - 15c
0. 3a
0.1 - 300
30
aExit from Electrostatic Precipitator
bExit from Limestone Wet Scrubber
Uncontrolled
TABLE 3-7
1. D. Anderson: Emission Factors for Trace Substances, U.S.
EPA, Document No. EPA-450/2-73-001. 1973-
-79-
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concentrated in the drift. The environmental effects of
drift deposition are discussed in a separate section. Drift
losses account for approximately 0,001$ - 0.005$ of recir-
culating flow for contemporary cooling tower units, and
thus contribute insignificant amounts of moisture to the
local air mass when compared to the cooling tower's evapora-
tive plume. This increase in relative humidity in the power
plant vicinity is the most important aspect of cooling
tower/plant plume interaction as concerns SO2 oxidation.,
3.5.3.2 SO2 Oxidation Mechanics
The primary removal process for SO2 in the atmosphere
is oxidation to sulfuric acid (H2SO4) or other sulfate
salt and removal by precipitation processes or sedimentation,,
There are three primary processes through which SO2 is
oxidized: photo-oxidation, chemical and catalytic.
Photo-oxidation is characterized by direct oxidation
of excited SO2 molecules. SO2 is photonically excited
by sunlight in the 2400-3400 mu wavelengths. Chemical
reactions are characterized by oxidation of unexcited
SO2 by another chemical species. This can be an important
reaction in the presence of active oxidizing agents, as in
photochemical smog. Reactions between SO2 and ozone
(O3) have been shown to be slow in the gas phase but to
proceed very rapidly in the presence of water droplets,
Catalytic reactions are characterized by oxidation
of SO2 on or in solid or liquid aerosols. The reaction
is catalyzed by various metal ions. The amount of sul-
fate produced is dependent on aerosol composition, phase,
surface area, and concentration. The rate of reaction
is dependent on characteristics of the aerosols and the
environment. One of the Important controlling parameters
can be the diffusion of SO2 to the surface of the aerosol.
In the case of plumes interacting close to the stack,
this should not be a limiting parameter because of the
high concentrations of SO2 and water. In these inter-
actions we expect reactions with liquid aerosols to be
the most important.
Observations of SO2 Oxidation in Power Plant Plumes
A study of SO2 oxidation in TVA coal-fired power
plant plumes, using helicopter traverses, yielded very high
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oxidation rates: OolO to 2#/minutej concluding that the
oxidation rate was a function of the moisture within the
plume, both as an effluent component and as entrained
from the ambient air„l
Evidence from a recent investigation indicates that
SO2 transformation in an oil-fired plant plume is of a
second order, while a first-order reaction in coal-fired
plant plumes was observed,, This is probably due to the
much greater number of catalytic surface junctures in the
coal-fired plant plume with its higher particulate concen-
trations .
3o5«3.3 Characteristics of Sulfates
The sulfate compounds resulting from SO2 oxidation
in power plant plumes are primarily H2SO4, (NHii^SOjj,
and metal sulphates. The size range for anthropogenic
sulfates is predominantly in the sub-micron category, that
is 0.2 to 1 micron. Sulfate particle sizes generally increased
with increasing relative humidity. This size range indi-
cates that the suspended sulfates are largely in the re-
spirable fraction of particulate matter. The major sinks
of sulfates are through the processes of rainout and dry
deposition,,
3.5.3.4 Other Secondary Pollutants
Nitric oxide and nitrogen dioxide are produced by com-
bustion in which temperatures are high enough to fix nitro-
gen. Nitric oxide is usually converted to NO2 by reaction
with O3 in the atmosphere rather than reacting with any
other chemical species. NO2 is scavenged from the atmos-
phere by hydrolyzation in liquid aerosols to form HNO30
All the HNO3 eventually becomes nitrate salt aerosol,,
These reactions can be expected to be accelerated during
the interaction of power plant plumes with high concen-
trations of nitric oxides and evaporative cooling system
plumes with high concentration of liquid aerosols0
1 Paradise, Kentucky. Plant Study by TVA„
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As we have seen, plumes from evaporative cooling systems
provide large quantities of liquid aerosols and also large
surface areas for absorption and reaction in addition to
providing many potentially reactive compounds„ The accel-
erated formation of many other decay products should be ex-
pected from the Interaction of these plumes, Based upon
emissions, however, we expect sulfates, and to a less extent
nitrates to be the most important secondary pollutants0
3.5o4 Fogging and Visibility Changes
For the same meteorological conditions, natural draft
and mechanical draft towers possess very different fogging
potentials0 Under most conditions, fog due to a natural
draft cooling tower is insignificant if any„ The height
of the tower as well as the added buoyancy due to the re-
lease of latent heat upon condensation, produces such a
substantial plume height that the chances of it being
brought down to ground level are smallo The only fogging
problems expected with natural draft towers are if the
tower is located in a valley with a closed circulation
or the terrain extends into the plume„
With their low emission height and poor aerodynamic
shape, mechanical draft cooling towers do pose fogging
problems 0
Hanna1 has calculated the average fog concentrations
for the mechanical draft towers at Oak Ridge« The model
he used assumes the diffusion of the water to be comparable
to that of an inert substance,, Neglecting the effect of
latent heat produces results higher than would normally
be expectedo His results follow in Table 3-8»
lo Hanna, S.R. (197^): Meteorological Effects of the
Cooling Towers at the Oak Ridge Gaseous Diffusion Plant
II. Prediction of Fog Occurrence and Drift Deposition,
Environmental Research Laboratories, Oak Ridge, Tennessee„
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AVERAGE FOG CONCENTRATION CAUSED BY COOLING TOWER
OPERATIONS AND CORRESPONDING VISIBILITIES1
DOWNWIND DISTANCE
LIQUID WATER CONTENT
VISIBILITY
(m)
(g/m3)
(m)
100
5.1
200
2.9
7
500
2.0
10
1000
1.1
15
2000
.61
33
5000
• 35
57
Visibilities were determined from a relationship
proposed by Trabert^.
Visibilities (m) = 2(g/m2ym) Diameter (ym) liquid
water content (g/m3)
A value of lOym was assumed for the fog droplets
TABLE 3-8
The model gives a conservative estimate; it does
not include the fact that a certain amount of liquid
water rains out, decreasing the fog density„
Besides restricting visibility by itself, water vapor
can add to the problem caused by SOp« SO? and its re-
sulting products in the atmosphere [SO/j=, tNH/j^SOh]
can be the primary cause of reduced visibility,. Direct
relationships between SO2 and visibility have not been
completely determined. The aerosols resulting from SO2
conversion are the actual causes of visibility reduction
and their formation processes are not completely under-
stood and quantified.
1. See page 82, footnote 1.
2. Trabert, W. . "Die Extinction Des Lichtes in Einem Truben
Medium (Schweite in Wolken), Meteorology 2, 18:518-520. 1901.
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When water vapor enters the problem, the situation
becomes more complex„ At high relative humidities the
potential for visibility degradation by a certain amount
of hygroscopic aerosol is increased. It is the smaller
particles causing the most problems due to the large
surface/volume ratio. At high humidities, however, it be-
comes increasingly more difficult to separate the visual
reduction due to S04= from that caused directly by the H2O0
Hygrophobic compounds also exhibit increased abscuration
capabilities in the presence of elevated relative humidities.
3.5.5 Health Effects of Secondary Pollutants
Associated With the Interaction of Evapo-
rative Cooling Systems and Combustion
Plumes
The interaction of wet plumes from evaporative cooling
systems and plumes containing combustion products from a
power plant can potentially accelerate the production of
various decay products. These include sulfuric acid,
sulfates, nitric acid, and nitrates,, There is evidence
that these decay products, for which National Air Quality
Standards have not been promulgated, may have greater ad-
verse biologic effects than the directly emitted pollutants.
Consideration should also be given to potential health haz-
ards of chemicals present in cooling tower drift.
3.5.5.1 Toxicity of Sulfur Decay Products
Toxicological studies, in which the response of animals
and humans to exposure to various sulfur compounds and
aerosols under laboratory conditions is measured, have
shown that sulfuric acid and sulfates have a much greater
adverse effect than sulfur dioxide alone.
Sulfur dioxide by itself has shown to produce con-
striction in the bronchial tubes of many animals and of man„
This response is most readily measured as a change in flow
resistance in the lungs. Studies with guinea pigs exposed
to sulfur dioxide and various aerosols have shown:
0 While aerosols given alone produce no increase
in flow resistance, several different aerosols
potentiated the response to sulfur dioxide.
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0 The degree of potentiation is related to the
solubility of sulfur dioxide in the aerosol salt
solution.
0 The mechanism appears to be sulfuric acid produc-
tion in aerosol water droplets.
0 Potentiation is further enhanced by soluble
metallic salts such as manganese, iron and
vanadium which catalyze the production of
sulfuric acid.
0 For aerosols between 0.3 and 2.5 M in Mass
Median Diameter (MMD), the smaller the par-
ticle, the greater its irritant potential.
From these animal studies, a model for the action of
SCb and particulates emerges„ The particulate aerosol
first acts as a condensation nuclei. As water vapor con-
denses out, SO2, which is highly soluble, dissolves,
SO2 normally dissolves in the moist upper airways and
does not reach the lower lungs. Associated with sub-micron
particles, however, SO2 can be transported to the peri-
pheral areas of the lungs. In these moist areas, the
aerosols grow by condensation preventing their transport
out of the lungs.
The second action of aerosols is to assist in the
conversion of SC>2 to sulfuric acid. Sub-micron par-
ticles provide a large surface area for absorption and
chemical reaction. Dissolved salts such as NaCl Increase
the solubility of SO2 in the droplets. Solubility also
increases with decreased temperature. Dissolved metal
ions catalyze the conversion to sulfuric acid. Overall,
the aerosols act to transport SO2 and sulfuric acid deep
into the lungs, and to accelerate the conversion from
SO2 to sulfuric acid. It is debatable whether potentiated
effects have been shown in humans as a result of labora-
tory exposure to SO2 and soluble aerosols.
There are several problems associated with extrapol-
ating toxicological evidence to evaluate health effects
on the public. First, extrapolating animal response to
human beings is very tenuous. Moreover, laboratory ani-
mals are generally very homogeneous in health, diet, etc.
Similarly, human beings exposed in toxicological studies
are generally young healthy males. These subjects do not
represent the general public well. In addition, the ex-
posure of the general public is not to a single pollutant,
but to a variety of environmental stresses including tem-
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perature, absolute humidity (.that is, total water content
of the air) and other pollutants0 We must, therefore, turn
to statistical studies of the general population, i,e0, epi-
demiology o
3.5.5.2 Epidemiology of Sulfur Decay Products
In order to assess the health effects of sulfates,
we must first be able to estimate the dose received by
the population exposed and secondly to separate this
effect from that of other environmental stresses. Ambient
sulfate measurements are subject to serious and as yet
unresolved sampling and analysis errors, while epidemio-
logical studies have relied upon sulfate measurement by
lead candles of analysis of filters from hl-volume samplers,
Hi-volume samplers collect all particles with a
diameter less than approximately 10 um on a glass fiber
filter. Thus, there is little information on the propor-
tion of particles in the mass respirable range.
Finally, it would again be noted that absolute humid-
ity and temperature have a major Influence on irritant po-
tential of sulfates. These factors should all be kept in
mind when reviewing epidemiological studies with regard to
sulfates.
It has been noted that respiratory morbidity, i.e.,
respiratory infection, influenza, and bronchitis, in hourly
employees in five cities was highly correlated to ambient
sulfate levels. However, no correction was made for known
confounding variables including smoking, age, socio-economic
class and occupational exposure.
In comparison to the sulfur decay products, there
is almost no information on nitrates (NCK) as respira-
tory irritants. The primary sources of nitrates in man
are vegetables and water. In quantities normally found
in food and water, nitrates are rapidly excreted from the
body and are not toxic. If consumed in sufficient quan-
tities, however, the nitrates can be reduced to nitrites
by bacteria normally found in the intestines. These ni-
trites have a much greater toxicity.
Nitrites have significant effects on the circulatory
system. First, they transform oxygen carrying hemoglobin
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In the blood to methemoglobin,, This reduces the capacity
of the blood to carry oxygen to the cells0 Nitrites also
cause dilation of capillary blood vessels. This Interferes
with the proper circulation of the bloodo
There Is also a suggestion that nitrates and nitrites
may be precursors to potential carcinogenic agents produced
in the digestive system.
3o5.5»3 Epidemiology of Nitrogen Decay Products
There Is a severe lack of epidemiological data on the
health effects of nitrogen oxides and its decay products.
As with the sulfur compounds, there are significant and as
yet unresolved errors In the sampling and analysis tech-
niques o
3c5.5o4 Other Potential Toxic Substances
The transport of chemicals present in the circulating
waters of evaporative cooling systems downwind, is poten-
tially damaging to health and should be considered. Un-
fortunately the toxicity of many of the chemicals used as
additives is not known.
3o5.5o5 Conclusions ^/ '
The presence of evaporative^cooling systems adjacent
to a fossil fuel power plant ^can produce aggravated adverse
health effects within a few Icilometers of the plant through
the direct emissions of various contaminants in the drift,
and in the acceleration of the production of secondary pol-
lutants. Although there is evidence that these pollutants
have significant health effects, there is not sufficient
data to determine acceptable ambient air quality levels.
3.5.6 Regional Variations of Air Quality Impact
of Alternative Cooling Syste"ms
As described in previously supplied documents, the
air quality impact of alternative cooling systems can be
classified into three major categories: drift, fogging,
and the formation of secondary pollutants. The magnitude
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of these effects depends, at least in part, on regional
characteristics—topography, climatology, and the compo-
sition of the make-up water. Following is a discussion
of these effects.
Drift consists of mechanically produced droplets of
the circulating water in an evaporative cooling system
which are carried out of the system and deposited on the
ground. The only meteorological parameters significantly
affecting drift deposition rates are wind speed and the
relative frequency of wind direction. Deposition rates
at any location will be inversely proportional to wind
speed. Regions with high winds will distribute the drift
over a larger area. Figure 3»3 shows prevailing annual
wind direction and mean speed for the United States [En-
vironmental Data Service, 1968]. Persistence of wind di-
rection is equally important in determining the amount of
time drift material is being deposited on a given receptor.
Regions with well defined mesoscale circulation patterns
can have relatively large drift deposition rates in the
prevailing wind directions. Examples of such circulations
Include coastal sites with their tendency for on-shore flow
during the day, and valley sites with their channeling and
nocturnal drainage flows.
The chemical composition of the drift droplets will
also vary regionally. Composition of the drift droplet is
determined primarily by that of the make-up water used in
the cooling system. In as much as there are regional dif-
ferences in the composition of make-up waters available
for cooling systems, there will be differences in the de-
position of solids for equivalent cooling systems. Depo-
sition rates are proportional to the amount of dissolved
solids in the make-up water.
Thus, coastal sites using salt or brackish make-up
water will have significantly higher rates of salt deposi-
tion than inland sites using "fresh" make-up water,, Salt
is naturally distributed inland along ocean coasts espec-
ially in areas of continuous wave action. World-wide data
indicates that deposition rates of 12-35 pounds of chloride
per acre per year are normal, and deposits of 100 pounds or
more along coast lines are not uncommon.!
1. Eaton, F.M. (1969): Diagnostic Criteria for Plants
and Soils. MacMillan Co., p. 653»
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FIGURE 3-3
ANNUAL PREVAILING WIND DIRECTION AND MEAN WIND SPEED
(ENVIRONMENTAL DATA SERVICE , 1968)
-------
To be significant, salt loads from drift deposition must
be of the same order of magnitude as that from natural
sourceso Although field experience has not shown environ-
mental effects associated with cooling towers using salt
or brackish water,-'- the cumulative effect of low level
salt loads may produce a slow but progressive decline of
vegetation,,2
Fogging is the result of water vapor in the evapora-
tive system plume condensing into droplets„ Because of this
the fog droplets are relatively pure water when compared
with the drift droplets„ The potential for fogging is de-
termined by the local climatic conditions„ EG & Gj
has defined a "qualitative classification for the potential
for adverse cooling tower effectsThree levels of fogging
potential were defined:
a. High Potential: Regions where heavy fog is ob-
served over 45 days per year, where October
through March, the maximum mixing depths are
low (400-600m) and the frequency of low-level
inversions is at least 20-30$.
bo Moderate Potential: Regions where heavy fog
is observed over 20 days per year, where Oc-
tober through March, the maximum mixing depths
are less than 600m, and the frequency of low-
level inversions is at least 20-305?.
Co Low Potential: Regions where heavy fog is
observed less than 20 days per year, and
where October through March, the maximum
mixing depths are moderate to high (gener-
ally greater than 600m).
10 Winstrom, G0K» and J„ C0 Ovard (1973): Cooling Tower
Drift, its measurement Control, and Environmental Ef-
fects o Presented at the Annual Meeting of the Cool-
ing Tower Institute, Houston, Texas, pp„ 32.
2. Bretton, Eo F. (1964); "Preliminary Discussion of the
Effect of Sodium Chloride and Calcium Chloride upon
Soils and Vegetation," State Highway Department,
Report 1„
3o EG & G, Inco (1971): Potential Environmental Modifica-
tions Produced by Large Evaporative Cooling Towers„ UoS0
EPA Report No. 16130 DNH 01/71o U0S0 Government Print-
ing Office, Washington, D„C.
-90-
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Using these criteria, EG & G developed the map shown
in Figure 3.4 indicating fogging potential throughout the
United States.
The processes which might accelerate the formation
of decay products such as sulfates during the interaction
of the plumes from power plants and evaporative cooling
systems are not well known. Therefore, a discussion of
regional effects must be somewhat speculative. The pri-
mary mechanism for the decay of sulfur oxide to sulfates
appears to be oxidation of SC>2 to SOo on the surface
of water droplets catalyzed by dissolving metal ions. The
reaction, therefore, is limited by the concentration of
SO2, the surface area of the liquid water aerosol in the
evaporative cooling system plume, the solubility of SO2
in the aerosol, the presence of the necessary catalyst,
and the reaction times. These parameters are at least in
part a function of climatic variables„
Consider, first of all, wind speed. As rioted earlier,
concentrations of pollutants are inversely proportional to
wind speed. Since SO2 must diffuse to the surface of a
droplet before it decays, lower concentrations imply re-
duced reaction rates. Plume rise is also inversely propor-
tional to wind speed. Wind speed and direction are there-
fore important in determining plume interactions. However,
since the mechanics are so site dependent, generalizations
based upon climatology are impossible.
The other parameter which determines the dilution of
the pollutant is the mixing depth. Low mixing depths imply
that plumes will be restricted in their vertical rise. In-
teraction of the plumes under these conditions would be in-
creased, especially for the case of mechanical draft cooling
towers and spray ponds. Natural draft cooling towers, how-
ever, are able to penetrate these inversions in many cases.
Enhanced interactions can be expected in regions of low
mixing depth for mechanical draft cooling towers and spray
pondso Figures 3«5 and 3»6 show estimates of annual average
morning and afternoon mixing depths for the United States.
Morning mixing depths are generally considered to be mini-
mum values. The values shown may not be representative of
1. Holzworth, G. C. (1972): Mixing Heights. Wind Speeds,
and Potential for Urban Air Pollution Throughout the
Contiguous United States. U.S. EPA Report No. AP -101,
p. 118.
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£1^13 HIGH POTENTIAL
MODERATE POTENTIAL
LZTD SLIGHT POTENTIAL
POTENTIAL FOR ADVERSE EFFECTS
OF FOGGING FROM COOLING TOWERS
FIGURE 3.4
1. See page 90, footnote 3-
-92-
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7
MEAN ANNUAL MORNING MIXING HEIGHTS
IN HUNDREDS OF METERS
FIGURE 3-5
See page 91, footnote 1.
-------
14 12
MEAN ANNUAL AFTERNOON MIXING HEIGHTS
IN HUNDREDS OF METERS1
FIGURE 3-6
1. See page 91, footnote 1.
-------
urban areas where heat emissions are sufficient to prevent
surface based temperature inversions during the winter. 1
It should also be noted that low mixing depths are also
generally associated with low wind speeds, and that these
two effects will complement each other in producing high
pollutant concentrations with its effects on sulfate pro-
duction.
Temperature has a lesser effect on sulfate formation
in that solubility of SO2 in water aerosols increases as
temperature decreases. Several epidmiological studies
have suggested that the health effects of sulfates are as-
sociated with cold temperatures.2 Figures 3.7 and 3»8
show average daily temperature for the United States for
January and August [Environmental Data Service, 1968],
Relative humidity also plays a secondary role in that
it determines the amount of water vapor in the evaporative
cooling system plume which will condense once it mixes with
the environment. This in turn determines the total surface
area of liquid water available for oxidation reactions.
Figure 3«9 shows annual average relative humidities for
the United States [Environmental Data Services, 1968],
Highest humidities are associated with coastal areas.
We can identify two areas with characteristics which
are of special importance in evaluating the impact of alter-
native cooling systems—coastal sites and sites in complex
terrain.
lo Ewing, R. Ho (1972): "Potential Relief from Extreme
Urban Air Pollution,"J. Applied Meteor,, 11: ;3^2-;3^5«
2. Finklea, J. F., Shy, C. M., Love, G. J., Hayes, C„ G0J
Nelson, W„ C0, Chapman, R. S„, and House, D. E. (197^):
Health Consequences of Sulfur Oxides: Summary and Con-
clusions based upon CHESS Studies of 1970-1971. In:
Health Consequences of Sulfur Oxides: A Report from
CHESS, 1970-1971. U.S. EPA Research Triangle Park,
North Carolina. Pub. #EPA - 650/1-74-004.
-95-
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NORMAL DAILY AVERAGE TEMPERATURE (°F), JANUARY
i
i'**!
$
son --CAUTION SHOULD BI
USED I* INTERPOLATING 0>l
THESE GENERALIZED WPS.
SHARP CHANCES IUr OCCVI
IN SHORT DISTANCES, PAR-
TICULARLY IK MOCNTAINOLS
AREAS.DUE TO DIITEBEJ.CES
IN ALTITUDE, SLOPE OJ
LAND. TYPE OP SOIL,
VEGETATIVE COVER. BODIES
07 »ATER, AIR DRAINAGE,
URBAN HEAT ETTBCTS, MTC. J
=ra/i>sumciEt.T DATA
ISOLISM
PATTER!) TOO COMPLEX II
HAWAII TO INDICATE 08
SMALL SCALE HAPS.
THESE CHARTS ARE BASED
ON THE PERIOD 1931-60
0SSI1IJ
n
HAWAII
tain IhiM »tf » —Oil . 0«
AVERAGE DAILY JANUARY TEMPERATURE
(ENVIRONMENTAL DATA SERVICE, 1968)
FIGURE 3-7
-------
NORMAL DAILY AVERAGE TEMPERATURE
AUGUST
ft
°CES
IV ALTITUDE, SLOPE 0/
LAVD. TYPE OF SOIL
VEGETATIVE COVER. BODIES-
Of VATER, AIR DRAINAGE,
URBAN HEAT EFFECTS. *TC.
|veiTflCir»T D^TA
ye* I SOLI NFS
PATTER* TOO COMPLEX 15
RAVAII TO INDICATE OX
SMALL SCALE MAPS
I
THESE CHARTS ARE BASED
Oh THE PFRICD 1931-60
HAWAII
hiih (Omi »•»» »*0v€Ci>O"
AVERAGE DAILY AUGUST TEMPERATURE
(ENVIRONMENTAL DATA SERVICE, 1968)
FIGURE 3.8
-------
MEAN RELATIVE HUMIDITY (%), ANNUAL
LitU*
MEAN ANNUAL RELATIVE HUMIDITY
(ENVIRONMENTAL DATA SERVICE, 1968)
FIGURE 3-9
-------
Bodies of water have a very pronounced effect on me-
teorology in their vicinity. A review of the figures pre-
sented here will show not only higher relative humidities,
but also generally warmer winter temperatures and cooler
summer temperatures, lower afternoon mixing depths, and
an on-shore component of the prevailing wind,. These fac-
tors, along with the high frequency of fog, are seen in the
enhanced potential for cooling tower fogging show in Fig-
ure 3o1o There is also an enhanced potential for the ac-
celerated production of sulfates by the chemical decay
model discussed previously. Higher concentrations of
dissolved solid from the use of salt or brackish water as
well as the persistence of the wind from the above, can
produce high local salt deposition rates. These must be
compared with natural salt loads to determine potential
adverse environmental effects.
Areas with complex terrain also significantly alter
the local meterology0 Valleys channel the wind, restrict-
ing horizontal dispersion of pollutants0 Nocturnal in-
versions are frequent and may not be eliminated during the
day. Thus, power plant and evaporative cooling plumes
may be trapped in the valley by an inversion lid, with
enhanced sulfate production,, Valley fogging is also
common and cooling towers would aggravate this. Enhanced
local drift deposition is also likely as the droplets are
deposited on valley walls,,
It should again be emphasized that quantitative data
on evaporative cooling systems in this country is very
limited and there are not sufficient field observations
to make definitive generalizations about the air quality
impact of fog, drift or secondary pollutant formation,,
It is apparent that the effects are very strongly depend-
ent on the characteristics of the site and until we have
gained more experience, general evaluation criteria cannot
be definedo
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CHAPTER FOUR
THE ECONOMICS OP THERMAL POLLUTION ABATEMENT
4.1 Introduction
The costs of complying with EPA policy will even-
tually be included in utility balance sheets, giving
it the appearance of being more easily quantified than
the environmental benefits of the policy, but much of
the difference is illusory, because the costs of not
complying with EPA policy will never be seen in a
certified accountant's report.
The initial Impact of a policy affecting existing
plants is relatively straightforward to calculate. In
the case of the present decision to require steam-elec-
tric generating units of over 500 mw capacity built after
1969 to change to closed cycle cooling the costs may be
roughly accounted as follows:
(1) The costs of determining whether the plant is
eligible for an exemption.
(2) The costs of confirming that a new cooling system
will in fact comply.
(3) The capital costs of designing, acquiring, building
and installing the new cooling system.
(4) The outage costs during final hookup including in-
creased fuel costs, transmission costs, and possibly
costs for additional capacity.
(5) Additional (non-electric) operating and maintenance
costs for the new cooling system.
(6) The costs of additional power needed to run the
new cooling system.
(7) The value of the power no longer produced due to
decreased plant efficiency.
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(8) The additional capital costs for additional capa-
city to make up for reduced capacity from:
(a) reduced net generation for a given steam load-
ing due to (6) and (7).
(b) reduced steam capacity due to possible turbine
overheating
Solid engineering estimates of most of these eight
terms have only been made at a few plants, but at least
there is general agreement on what they mean and how
to estimate them. The impact of these new costs is sub-
ject to more debate. For a small plant in a non-infla-
tionary, stable economy, one could just add the interest
and depreciation cost of the capital items to the annual
operating and maintenance costs; this could then be com-
pared to annual plant revenue to get some measure of
the impact of the EPA ruling. In the present infla-
tionary time with a depressed utility industry, both
the real cost of capital when purchased and the proper
discount to a base year is subject to wide disagreement.
For plants that have not been built, the costs of
compliance are much more nebulous. The entire turbine
system will be designed differently if the plant is ex-
pected to use warmer recycled cooling water. So the
calculation of added capital cost involves not only the
cooling system but nearly the entire plant. The calcu-
lation becomes even more difficult if more than one
site is contemplated. If the plant is moved much fur-
ther away from the demand center to take advantage of
a site that allows once-through cooling, there will be
large costs involved even though the plant will not
require cooling towers. On the other hand, consider an
originally planned once-through site that is only slightly
cheaper than a different site. The cost of compliance
in this case is only the difference between the two
sites, which may be much less than the cost of the cool-
ing towers.
Looking further into the future, if some of the
economically feasible sites for once-through cooling
were not precluded by the EPA, all but the deep ocean
sites would soon be used up by new plants anyway. For
example the total runoff from the U.S. of 1.8 million
cubic feet per second would be warmed 3° F if used to
cool all of the 1970 capacity by once-through cooling
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and warmed 10° F by the 1990 capacity of 1 million mega-
watts. Soon thereafter, the rivers would be hotter than
the water in the cooling towers. Since the coldest water
source allows the most efficient energy production,
cooling towers would then be more economic than once
through. Although plants may presently be planning to
build closed cycle systems because of EPA regulations,
in the future plants will be closed cycle due to lack of
available water.
The long range costs of the EPA ruling are difficult
to calculate at all, likely to be grossly overestimated,
and probably not entirely meaningful. We will discuss
the inputs ERCO provided to estimate the expected cost
of EPA guidelines over the next five or ten years.
EPA made an analysis of cooling tower retrofit
costs; later work by the Utilities Water Action Group
(UWAG) amplified the analysis and increased the level
of estimated costs. ERCO's analysis was based on a
study of 53 engineering reports provided by the util-
ities in the sample.
4.2 ERCO Data Analysis
Since a majority of power plants have not under-
taken any engineering study of the cost of converting
to closed cycle cooling, it was not possible to obtain
a statistically representable sample of such costs.
Original engineering studies were not part of the scope
of work, so we dealt with available data. Based on
TBS's estimates, capital costs (item 3 above) of
retrofitting cooling towers for nuclear plants and for
fossil-fueled plants were estimated. The other
factors were not evaluated systematically, but the
following impressions were obtained. The other
capital costs items for outage and lost capacity may
be as large as the tower costs, especially for nuclear
units. With the lower steam temperatures, the nuclear
capacity is more sensitive to the cooling water temp-
erature and the (presumably nuclear) replacement
capacity is much more expensive. Also, since nuclear
fuel is so cheap, and other nuclear plants are fully
loaded, nearly the entire cost of fossil fuel burned to
provide replacement power during hookup must be charged to
cooling costs. The operating costs given by the other items
in the list will generally add up to as much as the annual-
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ized capital and operating costs. Utilities believe
that an optimal cost function equates operation and
maintenance with capital costs where cooling is reauired.
We were also able to determine that correlations
between the costs of cooling towers and the parameters being
considered in the options were low, causing costs to vary
in proportion to the installed generating capacity affect-
ed. Greater correlation was found for environmental risk.
For example, a larger fraction of the oldest plants were
safely located on large rivers. This reflects the fact
that the most advantageous sites were selected first,
reducing the number of available sites which could be
utilized for large power production facilities. We
therefore subdivided plants into relatively high risk and
low risk locations. For each option considered by the EPA,
we prepared for TBS, EPA1s contractor, a listing of
the impacts subdivided into the following categories:
before and after Jan. 1, 197^; nuclear and non-nuclear,
all risk and high risk; 500 mw, 300-500mw, 300mw, and
60% capacity factor. In each of these categories we listed
the operating capacity affected by the option and its capacity
factor. This listing is given in Appendix I.
4.3 Finding of Land Use and Population Density Analysis
for 37 Power Plants
Although exemptions for land availability were pro-
vided by the proposed guidelines, the extent of exemptions
applied for was not known. ERCO undertook an analysis of
the land availability question. ERCO's analysis concludes
that 75% of the plants examined have room for cooling
towers, but ^40% of the plants examined claimed that the
construction of cooling towers was not feasible due to
other site specific factors such as land planned for fuel
storage, unsuitability of terrain, and the deleterious
environmental impact of cooling towers.
This phase of the project involved four tasks:
1. locating the 37 power plants,
2. determining population densities in areas sur-
rounding the power plants,
3. obtaining land area and land values of the
plant sites, and
obtaining data concerning the possibility of
constructing cooling towers or cooling ponds
at the plant sites.
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4.4 Methodology
The location of the power plants was determined
through use of U.S. Geological Survey 7-1/2 minute maps
for the areas around the plant sites, an atlas, and a
series of Federal Power Commission naps on which principal
electric facilities in the U.S. are located. The USGS
maps not only located the plant sites but also provided
information as to the type of urban or rural setting of
the plant sites, topographical details, and information
useful in determining population density areas. The
Federal Power Commission maps were not detailed enough to
provide more than a general sense of location.
The population densities were not available and had
to be calculated using 1970 U.S. Census data. Three areas
were plotted around each plant site on a map which was
marked with U.S. Census county subdivisions for which
the total populations were known. The three areas were
rectangles centered at the plant site of 25, 100, and 400
square miles respectively, these showing the population
within 2-1/2 miles, 5 miles, and 10 miles of the plant,
respectively. The population within each area was
determined using the census figures for the county sub-
divisions mentioned and from this the density per square
mile was obtained.
Land value and area of land around the plant site
owned by the controlling utility companies were obtained
by contacting assessors' offices in the appropriate city
or county for each power plant. These offices were
able to provide the amount of land owned at the plant
site itself in most instances; however, sometimes only
the total amount of land owned by a power company within
a county was available. The assessed value of the land
was obtained and in most instances the conversion factor
used to convert assessed value to market value was also
given. From this and from the land acreage, market value
per acre was calculated. The conversion factor used to
obtain assessed value from market value varied from
location to location and made assessed value an incon-
sistent indicator of land value. Assessed value ran from
35% to 100% of market value, the average being between
505? and 60% of market value. The amount of land owned by
the power company at the plant site seemed to be related
to the location of the plant in an urban or rural (or
small town) area. The more rural the area, the larger
-] 04-
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amount of land owned by the power company.
Figures of land owned by power companies at power-
plant sites as obtained through the assessors' offices,
however, are not an adequate indicator of land avail-
ability for the construction of cooling towers or ponds.
Therefore, the power plants themselves or the utility
company owning them were contacted. The following types
of information were collected: amount of land owned at
the plant site by the utility company, breakdown of land
usage such as amount for ash piles, coal storage, plant
buildings, etc.; amount of vacant land; description of
the vacant land; future plans for the vacant land such
as plant expansion, storage, expansion, recreation
facilities, etc. In addition, the utility company was
asked if it considered the plant site adequate for the
construction of cooling towers or ponds, why, or why not.
Also asked for were descriptions of unique characteristics
of the plant site which the company felt were important
in a consideration of granting exemptions from the con-
struction of cooling towers, such as proximity of public
roads and/or facilities, public reaction to thermal
abatement equipment, type of land in surrounding area,
etc. Every effort was made to discuss specific plant
sites with the utility company in order to obtain an
in-depth view of factors involved in building cooling
towers.
Parameters obtained which are applicable to all the
power plants surveyed include the following: whether or
not cooling towers are presently installed, whether or
not land is available for the construction of cooling
towers, and whether or not the construction of cooling
towers is considered infeasible due to factors other than
land availability. In addition, information from coop-
erative plants as to physical descriptions of plant sites,
future plans for land at plant sites, and other unique
characteristics of plant sites as pertain to the construc-
tion of cooling towers was obtained.
For this task, land availability was not given a
strict definition, such as acreage per megawatt. Many
who had room for cooling towers according to their own
definition, raised other objections to building cooling
towers—objections which they believed were as valid as
land limitations for cooling tower construction. Seventy-
five percent of the plants examined have room for cooling
towers, including twenty-three percent out of the twenty-
nine percent of the plants surveyed which have already
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installed cooling towers. (The other six percent have
installed cooling towers to accommodate part of their
total number of units, but have no room remaining to
construct cooling towers for the other units). Approxi-
mately seventy-two percent of the plants surveyed have
not installed cooling towers.
As mentioned, a number of utilities raised objec-
tions to the requirement to build cooling towers based
solely on land availability criteria. Forty percent of
the plants examined claimed that the construction of
cooling towers was not feasible due to other site-specific
factors. Back-fitting older plants with cooling towers
was claimed to be economically unfeasible by 11% of the
plants because these older plants are slowly being phased
out by a continual lowering of the percentage of full
capacity at which they operate and by their replacement
with newer, more efficient power plants. There were also
claims by the utilities that alternative methods of
cooling were adequate for certain sites. Seventeen per-
cent of the plants surveyed claimed that although they
had land available at the plant site, this land was
already planned for uses more pressing than cooling towers
such as fuel storage, waste disposal and plant expansion.
The need for increased fuel storage was acutely brought
to the fore by the recent fuel shortages, with one com-
pany mentioning that it could store no more than one
week's supply of fuel oil with its present facilities.
This company felt that most power companies operated on
the same short time span for storage.
Unsuitability of terrain for building cooling towers
was claimed by twenty-nine percent of the plants. This
"unsuitability" included ownership of vacant land that
was extremely steep-sided such as deep valleys or cliffs
and bluffs such as are found along some rivers, flood
plains, marshland, hogbacks, and hilly land. Eleven
percent of the plants surveyed are located on streams
which are badly polluted by acid drainage from mines;
these plants claim that they can do no further damage
to the ecology of the stream and hence should not be
required to construct cooling towers.
-infi-
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A large number of objections were raised concern-
ing the impact of cooling towers. The aesthetic disutility
of the cooling tower itself and of the plume "was mentioned
by six percent of the plants. Problems caused by the fog
water vapor from the cooling tower included in one in-
stance the immediate proximity of a state mental hospital
and a large, much-used state park; in another instance,
visibility problems were foreseen for the nearby heavily
traveled New Jersey turnpike. A total of eighteen percent
of the plants objected to the inconveniences and problems
caused to nearby public services and cities by the cooling
tower effluent. Noise pollution and the questionable
efficiency of cooling towers were also noted by various
utilities.
Since cooling towers necessitate an increased water
consumption of up to two and a half times the present
consumption of a plant, six percent of the plants felt
that this increased water comsumption might interfere
with the needs of other interests in the areas of plant
location. One instance cited was salt intrusion into the
Delaware River; another was that of a large city down-
stream from the plant. In the latter, both the increased
water comsumption and the increased temperature of the
water would affect the city.
Several factors mentioned which the utilities felt
would make the building of cooling towers infeasible
were: congestion at the plant site (claimed by nine
percent), public objection to the building of cooling
towers, alternative use of "available" land for public
use such as game preserve. The possibility of grant-
ing exemptions on the basis of alternative uses for
thermal effluents was raised by one power plant that
was planning to implement aquaculture for such species
as oysters and salmon in addition to providing public
fishing grounds (claiming that the warmer water attracted
the fish). This company felt that if beneficial enough
alternative uses could be found for the thermal
effluent of the plant, it should be exempt from the
requirement to construct cooling towers.
Two further divisions of the power industry were made
in this study, one by type of discharge media such as
ocean, estuary, river, and lake; the other by fuel
type, (nuclear, oil and coal). Three percent of the
plants studied have an ocean discharge media, nine percent
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have estuaries, nine percent lakes, and eighty percent
rivers. Fourteen percent of the plants are nuclear,
twenty-five percent use oil, and sixty percent use coal.
Each of these subdivisions, fuel type and discharge media,
are further categorized along the lines of land availabil-
ity, cooling towers installed, and feasibility of cooling
tower construction based on factors other than land avail-
ability in Tables 4-1 and 4-3-
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THERMAL VARIANCES
Land Availability Data - 35 Power Plants
Cooling
Land Available:
Cooling Tower
Discharge
Tower
Cooling
Cooling
Not Feasible
Plant
Media
Installed
Tower
Pond
Other Factors
Salem Harbor
Estuary
No
No
No
No
Brayton Point
Estuary
Yes*
Yes
Yes
Yes
Pilgrim
Ocean
No
Yes
Yes
Yes
Millstone
Estuary
No
Yes
No
Conn. Yankee
River
No
Yes
No
Mt. Tom
River
No
Yes
No
W. Springfield
River
No
Yes
Yes
Roseton
River
No
Yes
No
Dans Kammer
River
No
Yes
No
Bowline
River
No
Yes
No
No
Oswego
Lake
No
Yes
No
Yes
Nine-Mile Point
Lake
No
Yes
No
Fitzpatrick
Lake
No
Yes
Yes
No
Seward
River
No
No
No
No
Conemough
River
Yes
Yes
No
Yes
Keystone
River
Yes
Yes
Yes
Homer City
River
Yes
Yes
Yes
Yes
Shawville
River
No
No
No
No
Warren
River
No
Yes
No
Bergan
River
No
Yes
No
Yes
Mercer
River
No
Yes
No
Yes
Titus
River
Yes*
No
No
No
Portland
River
No
Yes
Yes
Amos
River
Yes
Yes
No
Mitchell
River
Yes
Yes
No
Kammer
River
No
Yes
No
Yes
Muskingum
River
Yes*
No
No
Yes
Big Sandy
River
Yes
Yes
No
Tanner's Creek
River
No
No
No
No
Sporns
River
No
Yes
No
No
Gavin
River
Yes
Yes
No
Tidd
River
No
No
No
Yes
Breed
River
No
Yes
No
No
Philo
River
No
No
No
Yes
Clifty Creek
River
No
No
No
Yes
*Plant has cooling tower for part of units, not all.
TABLE 4-1
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Land Availability for Installation of
Cooling Towers
Number of Plants
Fuel Type
Nuclear
Land
Available
Land
Not Available
Total
5
0
5
Oil
8
1
9
Coal
13
8
21
TOTAL
26
9
35
Total #
of plants
Percentage of Plants
Fuel Type
Nuclear
Oil
Coal
TOTAL
Land
Available
14*
23%
37%
7^%
Land
Not Available
3%
23%
26%
Total
lk%
26%
60%
100%
TABLE 4-2
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Plants With Installed Cooling Towers
Number of Plants
C.T.
C.T. Installed
No C.T.
Fuel Type
Installed
for Some Units
Installed
Total
Nuclear
0
0
5
5
Oil
0
1
8
9
Coal
7
2
12
21
TOTAL
7
3
25
35
Perc
entage of Plants
C.T.
C.T. Installed
No C.T.
Fuel Type
Installed
for Some Units
Installed
Total
Nuclear
0%
0$
111*
lk%
Oil
0%
3%
23%
26%
Coal
20%
6%
3
60%
TOTAL
20%
9%
71%
100%
TABLE H-3
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CHAPTER FIVE
OPTION ANALYSIS
5•0 Introduction
Heat loads from electric power production are growing
rapidly. As noted in Chapter Two, the power plant factors
that directly affect the extent of the thermal discharge
are (i) the location of the plant (ii) the efficiency of
generation and (iii) the total amount of generation. Other
plant characteristics that may be used to categorize plants
for exemptions are unit size, capacity factor, age and fuel
type.
5.0.1 Age Exemption
An age exemption is one of the easiest to administer
and least likely to cause uneconomic distortions. Existing
units can modify fuel use, heat rate, capacity factor,
and size to escape regulation. New units can modify these
variables over wider ranges. The only distortion possible
from exempting old plants is the increased use of nearly
retired plants to avoid the building of a new one with
towers. However, the changes in manpower productivity and
fuel efficiency in the last 30 years have been large enough
to make such a building freeze uneconomical and the growth
rate in demand makes a freeze impractical in the medium
term. Age is an excellent exemption criterion, affecting
both costs and benefits.
5.0.2 Size Exemptions
There was substantial interest in some type of size
exemption from the guidelines. Small units would experience
higher administrative costs of monitoring and the conversion
costs would be moderately higher per unit of capacity.
Typically the costs for small units would be over twice as
large for a given reduction in environmental impact. Size
correlates to some extent with age. Technological changes
have meant that the average unit size has grown continuously.
In 1950 70% of the industry was less than lOOmw, while by
1977 less than 10% will be smaller than lOOmw. In 1962
there was no capacity in plants larger than 500mw, by 1977
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more than 55% of the industry will be larger than 500mw.
Consequently size and age correlate highly. Size exemptions
are however useful to discriminate further between two age
exemptions.
5.0.3 Capacity Exemptions
Capacity exemptions would cause more problems than
almost any other measure for regulation. Capacity factor
fluctuates daily causing administrative difficulties.
Even if an annual capacity factor were employed, a permanent
exemption based on capacity factor in an arbitrary base
year in the past would lead to continual challenges from
plants that had fallen below the cutoff after the base year
while putting the base year into the future would compound
the problem of honest uncertainty with manipulation of pro-
duction to slip the maximum number of plants under the line.
The use of current production, in place of past or future
production, would raise impossible problems of planning
multi-year construction on the basis of exemptions which
fluctuate yearly.
Numerous options were examined incorporating capacity
factors although a capacity exemption was not incorporated
into the final regulation because of the difficult enforce-
ment problems.
5.1 Description of the Options, Their Costs and Risks
Units were to be exempted from the thermal guidelines
if they satisfy one or more of the requirements of the
option chosen. The cost of the option is approximated
by the fraction of all generating capacity using once-
through-cooling that is not exempted. The environmental
risk of the option is approximated by the fraction of net
generation at high risk that is exempted.
The March 4th EPA proposed guidelines failed to exempt
any units because nearly all units that would have been
exempt via the guidelines were likely to be exempt under
other sections of the act or were to retire before compliance.
The March guidelines would have exempted small units and
those expected to retire before 1989. Since units conven-
tionally last 35-^0 years, this means units built before
1950. The capital cost of implementing the guidelines
with the March option would have been 92% of the cost with
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no exemptions. The environmental risk remaining after
implementing the guideline would have been 3% of the risk
with no guideline.
In early summer, EPA began examining a new series of
options (labeled A through H in Table 1-1)1 almost all
of which took into account load factor and had age exemp-
tions for those plants built between 1956 and 1961. These
options would have been difficult to administer because
they depended on anticipated capacity factors and would
have provided only a slight reduction in cost over the
March proposed guidelines. The primary problems were:
1. Risk correlates almost equally well with
size load, and age; therefore it is more
important to determine the number of
plants included in the exemption than to
worry about the precise mix of characteris-
tics used to determine the exemption
2. Most importantly, since the cost-benefit
ratio for old plants is so much greater
than average, and since the industry is
growing rapidly, it was possible for EPA
to opt for a major reduction in cost
with only a small increase in long-term
risk
After analyzing the initial options, a large number
of alternatives were then considered. Those considered
long enough to leave a record were given in Table 1-1.1
The order is arbitrary except that those remaining on
September 23 are listed separately.
By September 23, EPA was considering a new set of
options, based almost entirely on age with relatively
late age exemptions (1970-1979).
The final decision, made by the end of September,
was a mixture of the 1970 and 197^ options. Units smaller
than 500mw were exempt through 1973 while units greater
than 500mw were exempt through 1970. The separation of
large and small units built between 1970 and 1973 causes
a noticeable decrease in the risk over a pure 1972 option.
(See Table 1-1)1
"'"See page 4
-11H-
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5.2 Elaboration on Effect of Final Option
The options have been compared by considering only
steam-electric plants expected to be In operation in 1978.
This accentuates the differences because all the non-steam-
electric and post 1978 units are treated the same under all
options. Once the final option was determined, it was
necessary to consider these other units in order to compute
the overall impact on the Industry. Compilations of indi-
vidual utility construction plans are not only inadequate
for estimation of the industry composition in 1983 when
the option takes full effect, but they are also inconsistent
with more recent estimates of the total growth rate of the
industry. A compromise projection connecting shortrun
construction plants to long-term growth rates were there-
fore worked out and the original March and final October
options compared in this context.
5•3 Methodology of Estimating Utility Industry Growth
The most comprehensive listing of the production of
electricity in the United States appears to be the monthly
Federal Power Commission publication "Electric Power Sta-
tistics". The latest full year covered is 1972. Total
electrical utility and industrial production is given as
1853 Twh (terawatt hours - millions of Kw). With the aid
of FPC publications S-232, S-235, S-236, and S-237 and the
corrections for small unreported plants suggested in some
of these reports, the above totals may be broken down as
follows: 298 Gw and 1384 Twh by fossil fueled steam-
electric utilities, 15 Gw and 5^ Twh by nuclear fueled
steam-electric utilities, 28 Gw and 30 Twh by fossil gas
turbine and diesel peaking units, 57 Gw and 279 Twh hydro-
electric utilities, and 19 Gw and 106 Twh by power plants
of industrial concerns — nearly all fossil steam-electric.
The regulations consider the first two of these classes
consisting of 75% of the capacity of 78% of the net gene-
ration .
Years after 1972 require estimated values, which were
gathered from the following sources. The growth of net
generation was estimated in a July 1974 working paper of
the FPC power survey group. It estimated growth of 9-4%
in 1973, 1.0* in 1974, 4.3% in 1975, 6.2% in 1976, 6.5%
annually through 1980 and 6.0% annually through 1983-
The long-term capacity growth can then be found by assuming
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GROWTH OF
ENTIRE INDUSTRY
YEAR
TOTAL
FOSSIL
ELECTRIC
STEAM-
UTILITY
NUCLEAR
IGC
NG
ICG
NG
IGC
NG
1969
329
1529
247
1170
4
14
1970
357
1622
264
1246
6
22
1971
285
1713
281
1287
9
38
1972
CO
1—I
1853
298
1384
15
' 54
1973
454
2027
318
1476
22
93
1974
475
2047
"3][P)
1518
29
136
1975
498
2136
337
1565
37
180
1976
517
2267
345
1602
43
229
1977
545
2415
354
1644
55
267
1978
568
2572
358
1662
68
341
1979
603
2739
366
1699
86
422
1980
642
2917
377
1750
105
533
1981
680
3092
386
1792
124
651
1982
721
3277
396
1839
145
769
1983
764
3474
407
1890
166
899
TABLE 5-1
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I
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the capacity factor will remain near 51%. The short-term
growth and composition was found by comparing this value
with all reported planned additions as given in PPC S-237
for 1972. As the planned construction presumed a larger
growth rate than is now projected, a compromise was needed.
For each year the actual additions were set at the average
of the values predicted from the net generation and the
old construction plans. Excess nuclear capacity was as-
sumed to be delayed and excess fossil capacity was dropped.
After 1978, when the nuclear backlog is caught up, 50% of
the net new capacity is assumed nuclear. Each nuclear
plant is assumed to have a total of one year of outages
and subnormal operation before reaching a long-term average
of 71% capacity factor. Fossil steam-electric stays at
53%. (See Table 5-1)
5.4 Distribution of the Units Affected by the Options
Table 5-2 combines the results of the ERCO survey
with the projections for the steam-electric utility indus-
try to show the changing impact of the options. For the
extension to 1983, it was assumed that retirements and
closed cycle plants would grow at the same rate as found
for 197*1-77. Of particular interest is the rapid fall
in the impact of the final option. Although it exempts
almost everything as of this year, by the time it is
actually implemented in 1983, only 44% of the high risk
generation will be exempt. Since the high risk net gene-
ration will have declined to 19$ of all steam-electric
generation which is in turn Q0% of all electricity pro-
duction, only about 7% of all electricity production will
involve significant environmental risk because of this
option. The corresponding number for the March option is
a miniscule 0.1%. Further, much of this high risk pro-
duction that would be exempt from federal regulation would
still have to meet state water quality regulations.
The characteristics of the steam-electric utilities
were determined by sampling 131 existing plants and 44
new units by literature search, FPC form 67 tape, and a
telephone and a telegram survey. The units were sub-
divided into three categories of closed cycle, low envi-
ronmental impact open cycle, and high environmental risk
open cycle. The number of units, capacity, and generation
for each category were determined. The general trends
are as follows:
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GROWTH. BY RISK TYPE
MEASURE:
RISK:
High
UNITS
Low
<#)
Closed
GENERATING CAPACITY (Gw)
High Low Closed
NET
High
GENERATION (Twh)
Low Closed
As of Jan 1, 1970
723
1300
678
76
141
34
358
689
137
Exempt under:
Pinal Option
100$
100%
100%
100%
100%
100%
100%
100%
100%
March 4 Option
46%
45%
59%
16%
16%
18%
7%
10%
15%
Retirements 1970-73
89%
220
76
3
5
1
26
50
8
Additions 1970-73
32
49
116
16
24
58
77
115
277
As of Jan. l, 1974
666
1129
718
89
160
91
409
754
406
Exempt under:
Final Option
98%
98%
92%
87%
89%
53%
86%
88%
48%
March 4 Option
38%
48%
47%
10%
11%
5%
5%
7%
4%
Retirements 1974-77
74
183
63
3
6
1
36
72
14
Additions 1974-77
26
28
103
16
17
63
91
198
367
As of Jan. 1, 1978
618
974
758
102
171
153
464
880
759
Exempt under:
Final Option
93%
95%
79%
13%
80%
31%
68%
67%
24%
March 4 Option
31%
42%
38%
6%
6%
3%
3%
4%
1%
Retirements 1978-82
74
183
63
5
9
2
69
132
27
Additions 1978-82
39
42
155
26
29
108
165
180
670
As of Jan. 1, 1983
583
833
850
123
191
259
560
928
1402
Exempt under:
Final Option
86%
89%
63%
56%
66%
17%
44%
50%
11%
March 4 Option
34%
36%
29%
1%
5%
1%
1%
3%
<1%
TABLE 5-2
-------
1. Due to the rapid increase in unit size
the number of units retiring exceeds
new construction. From 1970 to 1983
the number of units drops from about
2700 to less than 2300.
2. Total capacity more than doubles from
251 to 573 Gw. Nuclear capacity rises
from 2 1/2% to 29%-
3. Closed cycle production rises over 10-
fold from 137 to 1^02 Twh, reflecting
increased environmental concern and a
shortage of sites.
High risk plants are expected to go closed cycle
by 1981 with up to two years extension allowed if system
reliability is compromised during the retrofit. As a
practical matter, it will be cheaper and easier to fit
most plants to be completed after 1978 with closed cycle
cooling as initial equipment. Therefore the 5^ Gw of
high risk capacity subject to the final option will be
converted at the rate of approximately 10 Gw/year during
1979-1983.
-119-
-------
CHAPTER SIX
ALTERNATIVE USES FOR WASTE HEAT
6.1 Introduction
In producing electricity, steam-electric power plants
create waste heat approximately equivalent in energy to
twice their electric generating capacity. The efficiency
of fuel use for energy production varies from about 33% to
h0% for new plants. Some older plants have efficiencies
of less than 25%. For Instance, a nuclear power plant
operating at 33% efficiency needs three kwhr of nuclear
energy to produce one kwhr of electrical energy. The two
other kwhr are lost to the condensing cooling water.1 This
wasted energy is mainly in the form of heated effluent dis-
charged from these power plants back into lakes, rivers, and
oceans. In 1970, the total amount of waste heat lost from
industrial operations in the form of heated cooling water
was 7-7 x 1015 BTUs. Eighty-five percent of that waste
heat was attributable to power plants.2 A number of ideas
have been advanced for the use of this waste heat, some of
which have been either experimented with or put into use.
The two main areas of waste heat utilization are that of
recreational use of the heated effluent and/or cooling faci-
lities and the use of waste heat either directly or indi-
rectly for commercial purposes.
Several factors enter into the consideration of the
utilization of waste heat. Most of this heat is termed
"low quality" waste heat because the temperature of the
heated effluent has been degraded to the point where its
uses are limited, and for the most part it has been con-
sidered practical only to discharge it into the environ-
ment. Sixty to ninety degrees fahrenheit is a typical
range for the temperature of this type of waste heat when
it is discharged directly into rivers. When designed to
be recycled using cooling towers, these outlet water temp-
eratures are fifteen to forty degrees fahrenheit higher.
1. M. M. Yarosh, et al., "Agricultural and Aquacultural
Uses of Waste Heat," NTIS Report ORNL 4797, Oak Ridge,
National Laboratory, Oak Ridge, Tennessee, 1972, p. 1.
2. Franklin Agardy, et al., "Waste Heat Utilization in
Waste Water Treatment," URS Research Co. (San Mateo,
Calif.), 1973, p. i.
-120-
-------
Low temperature heat as opposed to this waste heat ranges
in temperature from 150° to 300°F and is obtained from an
earlier stage in the turbine cycle. This higher temper-
ature effluent is useable for such things as space heating
and cooling; however, obtaining this heat lowers the effi-
ciency of the turbine cycle.1 In order to maximize the
efficiency of a total power plant system, it is necessary
to weigh the trade-off between the amount of electricity
generated and the benefits gained through alternative uses
for the heated effluent. For instance, using conventional
operating techniques, a central steam plant runs at approx-
imately forty percent efficiency; sixty percent of the
energy is released directly into the cooling water; and,
unless that cooling water and energy are utilized, a sixty
percent waste in total energy use occurs. Alternative
methods of operation exist whereby steam is removed from
the turbine cycle after it has produced a considerable
amount of electricity but still has a temperature high
enough to be used for more purposes than low grade heat.
Depending upon the temperature of the steam removed and the
point in the turbine cycle at which it is removed, the
trade-offs resulting could be as follows: 35# energy used
for electricity, 35% extracted as higher temperature steam
for beneficial uses, 30% wasted energy (as opposed to the
earlier 60% figure). Another method of improving the over-
all efficiency of energy use would be to use a high back-
pressure turbine, removing all the steam at the higher,
more useable temperature. This reduces the efficiency of
electricity production to 30%, however, the other 70% of
the energy would be useable as steam, reducing the waste
heat almost to zero.
Low temperature heat has many more uses than low grade
heat. Heat in the form of steam and/or hot water for such
uses as space heating and cooling, domestic hot water,
industry, water desalting, and transportation needs to be
at higher temperatures in order to be efficient. The
table on the following page indicates the supply tempera-
tures required by some uses for both low temperature and
low grade heat.
Another consideration in the use of waste heat is
the distance over which this energy must be transported.
In order to use the heated effluent it must either be
directly piped to the place of disposal or another medium,
to which the heat is transferred, must be so transported.
1. ORNL, p. 3.
-121-
-------
ENERGY USE ESTIMATE1
Energy Component Supply Temperature*
(°P)
Electricity
Low Temperature Heat
Space heat 200
Domestic hot water 200
Absorption air conditioning 250
Water distillation 265
Industry 300
Snow and ice melting 212
Transportation 300
Waste Heat
Secondary sewage treatment 95
Agriculture-aquaculture 95
* Approximate minimum temperature of transmitted steam
or hot water.
TABLE 6-1
1. NTIS Report CONF-711031, Waste Heat Utilization Pro-
ceedings of the National Conference, Gatlinburg,
Tennessee, Oct. 27-29, 1971, P- 71-
-122-
-------
Loss of heat and cost of transportation over long distances
makes only close use of the waste heat feasible as far as
piping is concerned.
Another question raised in the application of alterna-
tive uses for waste heat is that of the total amount of such
heat which can be used in these processes. For the most
part, the amount of waste heat available greatly exceeds
the demand which could be created for its usage in these
alternative systems. This lowers the economic incentives
to power companies to implement these programs because in
most instances they would be financing the alternative uses
in addition to maintaining conventional cooling techniques
such as ponds and/or cooling towers. Not only is not being
able to use all of the waste heat supplied a problem, but
also a number of the alternative uses suggested do not con-
siderably lower the temperature of the heated waste water.
In these instances, an alternative use results, but the
problem of thermal pollution still remains. The demand for
waste heat would also be seasonal, thus the power companies
involved would have to deal with a higher heat disposal
rate in the summer months.
One final aspect in the consideration of alternative
uses of waste heat is the possibility of creating other
sources of pollution. It will be necessary to consider
what kinds of damage may result from trying to lessen
thermal pollution. It may not be desirable to decrease or
eliminate thermal pollution at the cost of introducing
even more harmful elements into the system.
6.2 Commercial Uses of Waste Heat and Low Temperature Heat
The commercial uses suggested for waste heat include
the areas of aquaculture, agriculture, waste treatment,
water desalination, spaceheating, industrial use, melting
of ice in shipping lanes, in city streets and sidewalks,
transportation, air conditioning, and cleaning and warming
urban air.l As mentioned, the distance from the supplying
power plant to the point of discharge of the steam and/or
the hot water is a major consideration. One suggestion has
been that of combining the facilities of plants and the
other services giving a total energy complex which could
1. David Berkowitz, et al., Power Generation & Environmental
Change, MIT Press (Cambridge), 1969-
-123-
-------
include agricultural and/or aquacultural sites, and waste
treatment plants in addition to the power plant itself.
6.3 Agriculture
Waste heat could be used in the areas of open field
agriculture and environmental control of greenhouses and
animal shelters. All of these applications can use low
grade heat in the form of the cooling water discharge with-
out lowering the electrical energy output of the power
plant.
Open field agriculture would benefit from the use of
heated effluents through rapid plant growth, improved crop
quality, extended growing seasons, prevention of damage
due to temperature extremes, and some pest and disease
control. The heated effluent could be applied through a
network of underground pipes used to heat the soil and to
provide moisture for the crops or through spray irrigation.
Warm water in a spraying system alleviates damage due
to temperature extremes in two ways: 1) prevention of
freezing of plants during a frost, and 2) prevention of
wilting in the hot, dry summer months during times of low
atmospheric humidities. In the latter, the heated water
reaches an ambient temperature by the time it reaches the
soil surface from the spray system.1 This application of
waste heat is not in constant demand as these extreme con-
ditions occur only a few times during the year. Therefore,
it does not provide the economic incentive for installation
which an alternative use with more constant demand would.
If used in conjunction with a total agricultural applica-
tion of waste heat, however, its implementation becomes
feasible.
Increased plant growth and the extended growing sea-
son result from the use of thermal effluent due to the off-
setting of weather effects, especially at the critical
time of plant germination, by maintaining a favorable and
constant soil temperature. Farm income could be enhanced
by the increase not only in crop yield, but also by the
additional number of crops which could be increased to
two or more per year. An additional advantage accrues to
the farmer in the form of earlier maturation leading to
earlier marketing times.2
1. ORNL, p. 6.
2. Ibid, p. 6.
-124-
-------
Within certain temperature ranges, biological activity
doubles with each temperature increase of 10°C. Some
experiments with plant growth and yield increases through
application of heated water have shown that rice (grain)
yields were increased from 12% to 55$ when the root temper-
ature was increased from 18° to 30°C; corn yields increased
68% when the soil temperature was increased from 12° to
20°C.l These yield increases are encouraging; however, it
is important to note that too much of a good thing is not
necessarily better. When the temperature of the corn soil
was increased yet another 7°C the yield was decreased by
*10%. Table 6-2 shows the results of some testing done near
Corvallis, Oregon in 1969.
RESULTS OF FIELD EXPERIMENTS DESIGNED TO MEASURE THE EFFECT
OF WARMING THE SOIL ABOVE ITS NATURAL TEMPERATURES^
Crop Yield (tons/acre) Yield
Unheated Heated Increase (%)
Corn
Silage
5.5
8.0
*15
Grain
3.2
*1.3
3*t
Tomatoes
32.1
*13-3
50
Soybeans, silage
2.25
3-7*1
66
Bush beans
First planting
6. *1*1
7.80
21
Second planting
3-30*
5.70
73
Total
9-7*1
13.50
39
* Did not mature
TABLE 6-2
1. Ibid, p. 6.
2. Ibid, p. 6.
-125-
-------
The project from which this table comes is an experi-
mental 170 acre demonstration farm which utilizes the
thermal effluent from a nearby pulp and paper plant. Ther-
mal effluent between the temperatures of 90° and l40°F is
pumped a distance of two miles at a rate from 4,000 to
5,000 gallons per minute through a sixteen inch steel main
line. The constant flow maintains a relatively constant
temperature. The water loses between four and ten degrees
fahrenheit to the lines as it is transported. At the pro-
ject site, the main line branches off into several sub-
mains which service different parts of the project.
By 1971j conclusions concerning the project included:1
1. Thermal water provides complete frost protection.
2. Water application for frost control should be kept
within a narrow range to minimize icing.
3. Thermal water cools "hot plants" and raises
humidity.
4. Thermal water, for irrigation alone, is as good as
normal "cold" water.
5. Thermal water has a definite advantage in frost
and sunburn protection.
6. The cost per acre of using a multiple-use water
system to control frost, cool plants, and irrigate
is considerably less than for combinations of other
systems. Table 6-3 demonstrates a comparison of
cost per acre.
Total Annual Cost Per Acre for Three Crop Protection and
Irrigation Systems
COMPARATIVE COST PER ACRE
2
System
Multi-Use
Solid Fuel & Hand-Move
Annual
Fixed
Cost
Annual
Operational
Cost
(per acre)
Annual
Total
Cost
$81.54
$ 11.20
$ 92.74
Irrigation
$13.59
$265.05
$278.64
Central Distribution & $74.75 $295-05
Hand-Move Irrigation
TABLE 6-3
$308.80
1. NTIS, pp. 178-180.
2. Ibid, p. 185.
-126-
-------
Research done by the TVA in Muscle Shoals, Alabama In
1971 using heated water for control of soil temperature and
subirrigation also showed considerable increase in crop
production. Heated soil, both irrigated and non-irrigated,
doubled the yield of string beans and almost doubled that
of corn. Table 6-4 summarizes these results:
EFFECTS OF SOIL HEATING AND SUBIRRIGATION ON VEGETABLE-
PRODUCTION,
MUSCLE SHOALS
, ALABAMA,
1971x
Yield, Tons
Per
Acre
Irrigation
No Irrigation
Vegetable
Heat
No Heat
Heat
No Heat
String beans
8.1
4.0
6.9
2.7
Sweet corn
9-0
5-0
6.2
3.2
Summer Squash
30.6
26.9
20.6
17-6
TABLE 6-4
Open field agricultural use of heated effluent has some
questionable areas. As mentioned earlier, the possibility
exists of causing more pollution through thermal pollution
abatement. In this instance some problems could be changes
in temperature of chemical characteristics of ground water,
spreading pesticides and stream warming through short-
circuiting of return water. Other areas in which adequate
research have not been conducted include pest control and
the definition of the limits of the water temperatures which
may be used.2
Another and perhaps more promising area for the use of
thermal effluent is in the heating and/or cooling of green-
houses. Cultivation in greenhouses gives larger crops and
yields, allows for year-round cultivation, and for optimal
control of the environmental condition for crop growth. In
general, produce grown in greenhouses is of better quality.
1. Ibid, p. 202.
2. Ronald R. Garton & Alden G. Christianson, "Beneficial
Uses of Waste Heat—An Evaluation," National Thermal
Research Program, Environmental Protection Agency,
Pacific Northwest Water Laboratory, Corvallis, Oregon,
1970, p. 3-
-127-
-------
Greenhouse use of thermal effluents is particularly desirable
because it allows the cooled water to be recycled just like
a cooling tower. A study of the economics and feasibility
of using thermal effluent from a nuclear plant for heating
and cooling greenhouses in the Denver area showed that
cooling towers could be replaced with low-cost (relative
to cooling tower cost) evaporative heat exchangers located
in the greenhouses. Heat dissipation would be constant
and "full load."l A greenhouse does not require modification
of the power plant, nor does it reduce efficiency of the
power cycle. Water loss from using greenhouses as cooling
devices would be less than that for cooling towers if the
water condensing on the greenhouse surface were collected
and returned to the original source. A large amount of
land would be required, however, for the construction of
enough greenhouses to use up the entire amount of effluent
from a single given plant. For instance, it has been esti-
mated that 250 acres of greenhouses would be necessary to
use up one-fourth of the waste heat from a 100 Mw power
plant.2 The incentive for the use of greenhouses would pri-
marily have to be the production of agricultural products
rather than that of abatement of thermal discharge because
it is questionable whether or not any more than one to five
percent of the total waste heat could be utilized by green-
houses .
Both the greenhouse operator and the power company
stand to gain through the use of heated effluent for temper-
ature control of greenhouses. The cost of operation would
be significantly lowered for greenhouses. Currently, heating
costs for greenhouses range from 10 to 30% of the total
operating costs, which are $2,000-$ll,000/acre.3 If waste
heat from a power plant were available at 20 cents/million
BTU, operating costs to greenhouses in some parts of the
country could be reduced by ,000-$6,000/acre. The initial
investment involved in setting up greenhouses, however, is
extremely high. Capital costs for setting up a heat delivery
system from a generator to a greenhouse is estimated to be
$28,000/acre for each 100 acre installation. This is higher
than the normal capital investment in heating equipment for
greenhouses, usually between $15,000-$25,000/acre. This
1.
ORNL,
P-
1—1
1—1
2.
Ibid,
P-
9-
3-
Ibid,
P-
9-
Ibid,
P-
O
1—1
-128-
-------
cost per acre would be lower by $10,000-$l8,000/acre when
the cost of cooling tower construction is deducted.*
A large enough greenhouse operation could be profit-
able for the power company also. The greenhouse would pro-
vide a substitute heat rejection system and market for a
previously wasted by-product of power production. If the
heat from a power plant were sold at the previously men-
tioned figure of 20 cents/million BTU to a 500 acre green-
house operation, the operating profit to the power plant
would be $500,000 to $1,000,000/year.2
The University of Arizona has been conducting experi-
ments with the applicability of heating and cooling green-
houses using low level waste heat in Sonora, Mexico. Table
6-5 summarizes the comparative results of products grown in
their greenhouse facility with those grown indoors and out-
doors elsewhere in the U.S.
Table 6-5 indicates that greenhouse production greatly
exceeds even that of a good yield outdoors. Greenhouse pro-
duction of vegetables and fruits near power plant sites
would supply the urban areas serviced by the power plant
with Its fresh produce requirements. Not only would the
cost of transportation of fresh produce be lowered for areas
where such products are not locally available due to incom-
patible weather conditions, but the produce could be made
more available year-round. The advantages of year-round
production include more uniform productivity and matching
of harvesting with periods of high demand and price.
Some problems exist for the implementation of green-
houses for the use of thermal effluents, a few of which
have been previously mentioned. These include the large
investment costs of building greenhouse facilities, the
probability that not all the waste heat can be used by
greenhouses, the actual market potential for greenhouse
produce, the question of public acceptance of produce that
has been grown with the use of waste water, particularly
food produced near a nuclear plant where the possibility
of radioactive contamination exists.
Another agricultural use of heated effluent from power
plants is in the area of livestock shelters. It has been
shown (see Figure 6.1) that maintaining optimal temperature,
1. A. J. Miller, et al., "Use of Steam—Electric Power
Plants to Provide Thermal Energy to Urban Areas,"
ORNL-HUD-ll, 1971, p. 38.
2. ORNL, p. 10.
-129-
-------
A COMPARISON OF MARKETABLE CROP YIELDS1
PUERTO PENASCO GREENHOUSES
COMPARATIVE
DATA FOR U.S.
(ACRES)
Kind of
Vegetable
Marketable
Yield
Approx. Av.
Yield From
Greenhouses
Approx. Av.
Yield Out-
doors/Year
Good Yield
Outdoors/Yr.
CUCUMBER
(European
type*)
Fall crop
Spring crop
6,600 bu
(48 lb/bu)
7,290 bu*
185 bu1
500 bu*
EGGPLANT
Fall crop
Spring crop
4,000 bu*
4,000 bu*
(33 lb)
— — —
433 bu1"
500 bu*
LETTUCE
(Bibb & Leaf)
Winter crop
3,500 ctn
(2 doz)
3,500 ctn
OKRA
Winter crop
40 ton
5 ton*
PEPPERS
(Bell)
Winter crop
1,200 bu
(25 lb)
372 bu+
500 bu*
RADISH
Winter crop
40,000 bnch
(12/bnch)
40,000 bnch
20,000 bnch*
SQUASH
(Zucchini)
Spring crop
2,000 bu*
(45 lb)
400 bu*
TOMATO
Fall crop
Spring crop
75 ton*
65 ton
40 ton*
60 ton*
6.8 ton+
30 ton
Vegetable crops grown in greenhouses in
Mexico (1969 - 1970)
Puerto Penasco, Sonora,
t
From: United States Department of Agriculture Statistics, 1969
*From: Knot, J.E., 1962, Handbook for Vegetable Growers, John
Wiley & Sons, Inc., New York
•Based on a harvest period of 90 days
1. NTIS , p.35
TABLE 6-5
-130-
-------
humidity, and ventilation in animal shelters decreases feed
consumption and increases livestock productivity.
Both winter heating and summer cooling could be pro-
vided through the use of heated discharge water in an eva-
porative pad and fan system similar to that which could be
employed for greenhouses. This creates a type of "hori-
zontal cooling tower," thereby eliminating the need for
construction of cooling towers. The power plant condenser
water is cooled to a temperature approaching the ambient
wet-bulb temperature in such a system.
EFFECT OF AIR TEMPERATURE ON SWINE FEED CONSUMPTION AND TIME
TO MARKET-L
2000
900
t«00 2
400
Ftto CONSUMPTION
- 300
200
400 O
100
TIME TO MARKET A
240 4b SWINE
0
60
TO
90
100
40
SO
eo
FIGURE 6. 1
As mentioned, maintenance of optimal temperature condi-
tions for animal shelters increases the feed efficiency.
For broilers, an increase in the ambient temperature from
60° to 70°F Increases the feed efficiency by at least 0.05
lb.-feed/lb.-gain. With feed at $0.05/lb. and with produc-
tion of broilers at 11 million lbs. annually, this repre-
sents a savings of $2.7 million/year or $0.0075/broiler
when applied to 105? of the broiler production. For hogs,
an increase in the temperature from 60° to 65°F reduces
the amount of feed consumed by 20 lbs./hog. This represents
a savings of $7 million/year or $0.70/hog when applied to
10% of the hog production.2
1. Ibid, p. 35.
2. ORNLj p. 25-
-131-
-------
The use of waste heat for warming animal shelters
could save poultry and swine operators $8 million/year
in fuel costs based on current fuel consumption figures,
assuming that 10$ of American broilers and hogs are grown
using free waste heat before incremental costs are sub-
tracted. 1
The amount of total waste heat that could be used in
the maintenance of poultry and hog shelters is not very
large. Based on 1970 data, 3 billion broilers were grown
in the U.S. The average energy required to brood all these
these chicks is taken as 10,000 BTU/chick. Approximately
0.3 x lO1^ BTU/year are required to brood all the broilers
currently grown in the U.S. If all the broilers were
raised using waste heat from power stations, about 1% of the
total waste heat generated could be used for raising
broilers. In the winter this would amount to 2% of the
total heat discharged, but in the summer it would only be
0.5%- A similar estimate for hog production shows that 1%
of the total waste heat generated and about 3% of the winter
waste heat would be used. Together, poultry and swine pro-
duction would consume only 2% of the total yearly production
of waste heat.
A number of problems are foreseen in the widescale
implementation of thermal effluent in the regulation of
animal shelters. Among these is the lack of knowledge of
the economic feasibility of large scale livestock production
with such a system. Problems with disease, odor, waste
disposal, and land use also face the producers. The geo-
graphic concentration of livestock production precludes
widescale implementation of this use of waste heat in other
than the Midwest, where hog production is very concentrated,
and in the Southwest where broiler production is concentrated.
Elsewhere in the country, only a very small portion of power
plant waste heat could be used in such operations.2 Land
requirements could also limit the use of waste heat in these
shelters. A 1000 hog operation requires about 30 acres. In
order to produce enough hogs to use 10% of the waste heat
from a typical 1000 mw(e) plant, 30,000 acres would be
necessary.3
1.
Ibid,
P-
2k.
2.
Ibid,
P-
25.
3-
Ibid,
P-
26.
-132-
-------
LIVESTOCK WASTE RECYCLING SYSTEM1
LIVESTOCK
SETTLING
ALGAE
WASTE
TANK
POND
GAS«
SEALED
DIGESTION
ALGAE
20$ WASTE
FIGURE 6.2
CLEANER
COOLED
h2o
One scheme for a total agricultural Industry developed
around a power generating station for the purposes of utilizing
waste heat is shown in Figure 6.3-^
ENERGY
GENERATING STATION - TOTAL AGRICULTURAL
SYSTEM ~
GENERATING
STATION
WATER
RETURN TO
¦[--STREAM
PROCESSED
GOODS
T~!—1—1—1—r
I liti
iVAPORATIVB
ICOOLING f
£RQCES£IUfiJ
FOR
PROCESSING
ELSEWHERE
4-
_WATER_FROM_j_|
STREAM
PRODUCTS
RAISED IN
COOLING
BASIN
ANIMAL
FEEDING*
LIQUID
[WASTE
1
FIGURE 6.3
r
'-i I— 1 r
ii ii
1 J I L
. j
i
OIL WARMING
I
I I
I I
I l
PRODUCTS
RAISED
1 J 1 J i I
FRESH
MARKET
1. NTIS, p. 203-205
2- ORNL, p. 8
-133-
-------
An area of waste heat application that could be used
in conjunction with livestock production and which could
alleviate the problem of waste disposal mentioned above
is the use of hot water for recycling nutrients from live-
stock wastes. The TVA is currently doing research on this
at its Brown's Ferry power plant site. The nutrients from
manures are utilized in a series of lagoons and ponds to
produce algae, a high-protein aquatic food. The algae can
then be harvested and processed into a high-protein feed
source for livestock. In addition, the water would be
cooled by exposure to the atmosphere before being returned
to its source. One problem with this system is the expense
and difficulty associated with the harvesting of algae.
6.4 Aquaculture
Aquaculture offers an area for the use of thermal ef-
fluents which are presently wasted; however, it does not
generally offer a solution to the problems of thermal pol-
lution. Aquaculture is cultivation of aquatic animals for
consumption as opposed to the sport and/or chance aspect
involved in fishing. Warm water fish growth rates could
be increased by a factor of two or three by controlling
the temperature of the water medium. Note shrimp and cat-
fish growth in Figure 6.U.
EFFECT OF TEMPERATURE ON GROWTH OR PRODUCTION OF FOOD ANIMALS1
.LAYING HENS (R I R )
(Lonqhouse eta! 19601
BROILERS, WT. GAIN
(Boroll, Prinqle 1949)
¦MILK PRODUCTION
JERSEY COWS
(Ragjdale eta! 1950)
SWINE, WT GAIN
(Mangold tt a/ 1965)
SHRIMP GROWTH
(Zein-Eiden,ff/ a/ 1965)
CATFISH, WT GAIN
(Strown Bt O/ 1965)
o 10 20 30 40
TEMPERATURE <*C)
1. Ibid., p. 31.
FIGURE 6.4
-13^-
-------
Fishing for wild species on the continental shelf using
methods such as trawling and purse seining may yield 20 lb./
acre-year. Catfish culture in ponds under semi-controlled
conditions may yield 2,000 lb./acre-year, whereas, under
intensive culture in a flowing stream with a relatively high
degree of environmental control, yields as high as 2 million
lbs./acre-year could be obtained. An 80$ increase in shrimp
growth results from a water temperature maintained at 80°F
rather than 70°F, and catfish growth is three times faster
at 83°F than at 76°F.l Temperature control is not the only
factor to be considered for optimum fish production, however.
It is also necessary to consider dissolved oxygen content,
biological oxygen demand of the culture system, fish waste
control and nutrition.
There are basically three methods of aquaculture imple-
mentation: ponds, cages and flowing water culture. The
relatively simple pond method involves stocking and harvest-
ing fish in a pond where the water is primarily stationary.
In this instance, environmental control is limited and
variable. Costs for development of such ponds runs from
$i100-$1200/acre. A number of problems are involved with
this method. Increased stocking density necessitates addi-
tional enrichment of the water nutrient levels. Aeration
may also become necessary if the oxygen content of the pond
drops. Disposal of fish wastes and growth of algae and
other organisms in the system also have to be dealt with.
Cage aquaculture consists of containers placed in large
volumes of water such as natural lakes and streams or in
cooling ponds and channels of cooling water. If placed in
a source of flowing water, a higher stocking density is pos-
sible due to the flushing away of fish wastes and the aera-
tion which results. Flowing water aquaculture consists of a
series of channels or raceways in which depth and flow rates,
in addition to temperature, may be controlled. The same
benefits of flushing away fish wastes, increased and evenly
distributed oxygen, occur, both of which increase the yield
per acre. Capital costs for flowing water culture are ap-
proximately ten times that of pond or cage culture.2
Use of thermal effluent from power plants for aquacul-
ture could be beneficial in a number of ways. Culture fa-
cilities could be located at plant sites thereby using the
land, especially the exclusion areas around nuclear plants.
The plant would provide water and power to facilitate
1. Ibid., p. 30.
2. Ibid., p. 32.
-135-
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temperature control through water blending. If flowing
water culture were used, year-round cultivation of aquatic
species could be implemented, and improvement over the
seasonal production afforded by ponds, hence decreasing the
variability in supply due to the seasonality. Use of
thermal effluent would also lower the cost of aquaculture
A major problem involved in the feasibility of estab-
lishing aquaculture facilities is the dependability and
existence of a large enough market for the cultured product.
Presently, the U.S. demand for seafood is growing. Per
capita shrimp consumption rose 160% from 1950 to 1970.
Imports account for more than 50% of the annual supply.
The U.S. seafood industry cites scarcity of naturally pro-
duced seafoods as a major problem.2
The seafood Industry is totally responsive to the
classic conditions of supply and demand. At present,
increasing rates of world consumption of seafood will make
aquaculture necessary in order to keep up with the demand.
Increasing costs of capturing wild seafood also makes
aquaculture viable. The regulated "agricultural" approach
to raising the seafood will stabilize the seafood industry
in addition to mitigating the supply problems.3
If the U.S. per capita consumption of fish is taken
to be 10 lbs./year, the national consumption of fish food
would be 2 billion lbs. for a population of 200 million.
If 10% of this consumption were provided for through the
use of thermal aquaculture, the amount of land required for
aquaculture facilities would be approximately 10,000 acres.^
Table 6-6 shows some extrapolations for the amount of land
aquaculture will require and the total amounts of heated
effluent used for thermal aquaculture. The latter decreases
as power demand increases. It is to be noted again that
although aquaculture does provide a use for thermal effluent,
it only incidentally consumes heat. Therefore, the amount
of thermal effluent utilized is larger than the amount that
thermal pollution is decreased.
1.
Ibid,
P-
37.
2 .
Ibid,
P-
36.
3.
NTIS,
P-
246.
4.
Ibid,
P-
571.
-136-
-------
THERMAL AQUACULTURE LAND AND WASTE HEAT UTILIZATION1
Fraction of Heated Land for***
Population Effluent for Thermal Thermal Aqua-
Year (millions)* Aquaculture (%)** culture (acres)
1970 200 14 10,000
1980 235 6.8 11,750
1990 270 3.4 13,500
2000 300 2.1 15,000
* Reference: National Academy of Sciences, Resources
and Man (1969) •
** Market assumptions: (1) per capita consumption of
fish foods, 10 lb./year; (2) 10% of demand fur-
nished by thermal aquaculture. Changes in con-
sumer tastes could change these assumptions.
*** Assumes 20,000 lb. live product/acre-year.
TABLE 6-6
Several power companies have already implemented aqua-
culture at the plant sites themselves or in conjunction
with a commercial operation. An example of the latter are
the oyster farms of Northport, Long Island, which use the
heated effluent from a Long Island Light Company plant.
The four year oyster growing cycle has been reduced by one
and a half years.2 A fossil fuel plant owned by Texas
Electric Service Company at Lake Colorado City, Texas, uses
the cage technique in a thermal discharge canal to obtain
catfish yields equivalent to 200,000 lb./acre-year.
1. Ibid., p. 38.
2. Effects & Methods of Control of Thermal Discharges,
Report to Congress by Environmental Protection Agency,
November 1973, P- 7^2.
-137-
-------
The TVA steam plant at Gallatin, Tennessee, provides
heated discharge water for a series of canals covered to
minimize algae growth. Extrapolated yields of up to
2,000,000 lbs./acre-year have been obtained. With a 230
channel expansion, the Trans-Tennessee Industries believes
it can supply the catfish demands of the Nashville area at
a lower cost than through pond cultivation.! The Florida
Power Corporation and the Ralston Purina Company joined to-
gether in an aquaculture project at the Crystal River Power
plant. A total of 50 acres at the plant site has been set
aside for the cultivation of marine shrimp. The total gen-
erating site includes 4,500 acres, two fossil fueled gener-
ating units with a total combined capacity of 825 row, a
nuclear unit with a capability of 825 mw, and plans for an
additional nuclear plant in 1978 with a capability of 1,897
mw. Cooling water is provided by canals running to and
from the Gulf of Mexico.^
Other companies doing research with aquaculture in-
clude Florida Power and Light, who, in conjunction with
Armour and United Fruit, is culturing shrimp at the Turkey
Point power plant; Shellfish Enterprises' oyster culture
in the thermal discharge canals at the Humboldt Bay power
plant, owned by Pacific Gas and Electric; and the Manifarms
Inc. shrimp culture using the local Panama City, Florida
plant's effluent. The Japanese have successfully utilized
waste heat for aquaculture in numerous projects starting
with a program at the Sendai power plant in 1964.3
Although aquaculture only slightly decreases the ther-
mal pollution from a power plant, it does offer an area of
productivity and profitability. As mentioned, a number of
problems would have to be dealt with: disposal of fish
wastes; possibility of radioactive contamination from
nuclear plant effluents used in aquaculture; copper, chlor-
ine, and other particulate and/or chemical contents of the
effluents (particularly from cooling tower blowdown); legal
and regulatory restrictions placed on water use; the avail-
ability of a market for the cultured product; and the sea-
sonal use of heated effluent (i.e., demand in winter months,
not in summer months, for the effluent). The latter problem
1.
ORNL,
P.
33-
2.
NTIS,
P-
227.
3-
ORNL,
P-
34.
-138-
-------
could be dealt with through the implementation of a combined
agriculture-aquaculture system. In the summer, greenhouses
could be used as cooling towers to extract the heat from
the effluent which could then be used at temperatures suit-
able for aquacultural purposes. A closed system for re-
circulating effluent would thus be established, providing
maximum use of waste heat for food production. However,
the problem of disposal of fish wastes would still remain.1
6.5 Waste Treatment
Secondary sewage treatment is a third area in addition
to aquaculture in which low grade waste heat may be em-
ployed. Biological processing of sewage may be increased
by a factor of ten by raising the temperature using low
grade waste heat.2 Savings would accrue to power plants
due to the lowering of the temperature of the effluent.
Another benefit to be derived from the use of low grade
waste heat for the processing of wastes is a decrease in
the area of mixing zones where the effluent enters the
discharge media.3 a cost-benefit analysis done on the
waste heat utilization in waste water treatment indicates
that the use of waste heat would be favorable where sec-
ondary treatment is employed and the plant capacity is
greater than 5 MGD. The benefits would exceed the costs
by 0.2 to 0.9 cents/1000 gallons of waste water processed.
The highest benefits occur with advanced treatment result-
ing in reverse osmosis, carbon adsorption, and ion ex-
change. The costs would be $.09Vl000 gallons for a 1 MGD
plant and from $.008 to $.073/1000 gallons for a 10 MGD
plant. Benefits that would result from use of waste heat
in secondary treatment to raise the base temperature 5°C
are a decrease in aeration tank volume necessary by 2^%,
a decrease in hydraulic detention time by 2^%, a decrease
in the amount of oxygen required for processing by 2H%, and
a decrease in carbonaceous oxidation by 12%.^
1. Ibid., p. 40.
2. EPA, p. 733-
3. Agardy.
4. Ibid.
-139-
-------
The distance from the power plant to the place of sewage
treatment is an important consideration in the economic fea-
sibility of using waste heat from treatment. Cost-benefit
analysis shows that the distance to transport waste heat
should be less than one mile.l A savings of $.001-$.45/1000
gallons of waste water treated would result from a group
utility facility where the treatment plant was adjacent to
the power plant.2
One factor not accounted for in this cost-benefit
analysis was the reduction in savings which could result
in fouling of treatment equipment due to contact with the
chemical content of the material undergoing treatment.
This could be a significant amount unless precautions were
taken to protect the equipment.
The adaptability of power plants to facilitating waste
treatment processes is limited by several factors. These
are the low temperature of the cooling water (i.e., not
generally greater than 28-^3°C), and the variations in sea-
sonal and daily power demand on the power plant which could
interfere with its supply to the waste treatment facility.3
The desalting of sewage by distillation to obtain
water for recycling is a possible use for thermal effluent;
however, this process generally requires steam of a higher
temperature than that of low grade waste heat. Oak Ridge
National Laboratory has estimated that a seawater distilla-
tion plant which would use the full exhaust steam flow at
a temperature of about 100°P from the turbine of a nuclear-
fueled light-water-cooled reactor producing about 20 MGD
of distilled water for an estimated cost of 20-25 cents/1000
gallons.^ Another process for dehydration of sewage sludge
or evaporation has been patented. This process uses steam
at temperatures of 250-300°F, a more conventional tempera-
ture range than that of the previously mentioned process
utilizing steam at 100°F.
1. Ibid.
2. Ibid.
3. Ibid.
4. Miller, p. HH.
-140-
-------
CONVENTIONAL WATER SUPPLY AND SEWAGE DISPOSAL
TREATED NATURAL WATER SUPPLY
150 Mgal/dj 250 ppm TDS
USERS
WASTE WATER
100 Mgal/d, 500 ppm TDS
I
PRIMARY + SECONDARY TREATMENT
RIVER SLUDGE TO
INCINERATION
FIGURE 6.5
COSTS OF CONVENTIONAL SYSTEM WITH NATURAL WATER
SUPPLY AND PRIMARY AND SECONDARY TREATMENT OF SEWAGE
TREATMENT
COSTS
(cents/kgal)
Natural water
10
Primary plus secondary treatment at
4 cents/kgal waste x
(100 Mgal/d waste/150 Mgal/d supply)
2.7
Sludge disposal at
2 cents/kgal waste x (100/150)
1.3
TOTAL for water supply and
sewage disposal
14.0
TABLE 6-7
-141-
-------
CONVENTIONAL WATER SUPPLY
WITH TERTIARY TREATMENT OF WASTES
TREATED NATURAL WATER SUPPLY
150 Mgal/d, 250 ppm TDS
\
USERS
WASTE WATER
100 Mgal/d, 500 ppm TDS
1
PRIMARY-SECONDARY TREATMENT
I I
FILTRATION SLUDGE TO INCINERATION
J
ACTIVATED CARBON
(to remove organics)
i
RIVER
FIGURE 6.6
COSTS OF CONVENTIONAL SUPPLY AND STRICT POLLUTION STANDARDS
REQUIRING MORE COMPLETE REMOVAL OF ORGANICS FROM WASTE
TREATMENT
COSTS
(cents/kgal)
Natural water
Primary plus secondary treatment
(as Table 6-7)
Sludge disposal
(as Table 6-7)
Filtration plus activated carbon treatmen
6 cents/kgal waste x
(100 Mgal/d waste/150 Mgal/d supply)
TOTAL for water supply and
sewage disposal
10
2.7
1.3
t at
7-0
18.0
TABLE 6-8
-142-
-------
Figures 6.5 and 6.6 are examples of conventional sewage
treatment followed by tables of cost estimates. The costs
for the complete recycling system involving the distillation
of waste water range from 23-^5? higher than for the con-
ventional systems and are shown in an additional table.1
ESTIMATED COST FOR SEWAGE DISPOSAL AND WATER RECYCLE SYSTEM
Cost (cents/kgal)
Supply High-Cost Low-Cost
(MGD) Energy Energy
Natural water 50 3-3 3-3
Primary plus secondary treatment -- 2.7 2.7
Sludge disposal — 1.3 1.3
Filtration and activated carbon
treatment 65-5 3^ 3^
VTE distillation-dehydration 3^-5 11¦5 7•9
Total 150.0
Ozonation — 0.2 0.2
Recycle pumping and storage — 2.7 2.7
Disposal of dry solids — 0.7 0.7
Total cost for water supply
and sewage disposal 25-8 22.2
TABLE 6-9
The recycle process provides a beneficial use of the
waste heat from the power plant in addition to decreasing
the heat emission from the power plant condenser. How-
ever, a condenser is also used by the distillation process
and this condenser would have to be located at some dis-
tance from the power plant in order to avoid a concentrated
1. Ibid., pp. 49-51.
-1^3-
-------
release of thermal pollutants in the discharge media. Use
of waste heat in distillation processes does not decrease
the total amount of thermal effluent released into the sys-
tem, but does derive some use from an otherwise wasted
source of energy, and then releases the heat in another
fashion.1
6.6 Marketing Steam, Space Heating, and Air Conditioning
Steam, and/or hot water from power plants could be
marketed for water heating, space heating, air condition-
ing, and for industrial use. Both of these would be re-
quired at higher temperatures. Hot water is adequate for
use in cases such as space heating, absorption refrigera-
ion, domestic hot water, and for providing low temperature
process heat. Steam is preferable for industries which
require high rates of heat transfer through containers and
in processing where steady high temperatures are needed to
speed processes such as water evaporation from chemicals
and in cooking of foods.2 Power plant efficiency is lowered
less in the provision of hot water than in the provision
of steam at the same temperatures. Water can be heated in
stages at the plant whereas steam must be extracted from
the turbines at the high temperature required by the sys-
tem; and then losses of both pressure and temperature occur
in the pipelines. From the point of view of waste heat
utilization, hot water is more efficient than steam.
Prime steam production in large nuclear reactors and
large modern fossil fuel plants costs 30-50 cents/MBTU.
Recent reports from large district heating companies es-
timate that high-pressure steam suitable for industrial
and space heating purposes costs about 70 cents/MBTU to
produce. Table 6-10 shows the average revenue received by
district heating companies in 1968 based on 106 BTU/103
lbs. of steam.
Sales prices for district heat often have seasonal
variations. One company charged 92.5 cents/103 lbs. of
steam for consumption over 10° lbs. of steam from May
through October, as opposed to charges from 1^5-195 cents/
103 lbs. of steam from November through April (1967). The
1. Ibid., p. 51.
2. Ibid., p. 98.
-urn-
-------
AVERAGE REVENUE RECEIVED BY DISTRICT HEATING COMPANIES1
(IM
System Revenue
(cents/MBTU)
Average of 43 systems reporting 142
Second to tenth largest systems 133
Range is second to tenth largest
systems 119-154
Largest system 152
Smallest system 148
Highest cost system 232
Lowest cost system 73
TABLE 6-10
cost of electricity for space heating usually runs between
200-600 cents/MBTU, depending on the region of the country.
Initial costs of installation and maintenance of electric
heating systems are less than that of steam heating; how-
ever, in some areas, especially urban and/or industrial
areas where piping systems have already been installed,
steam heating is much less expensive in terms of heat cost.2
Growth of electrical air conditioning has created
problems for electric utilities in parts of the country by
requiring large capital investments for the plant to carry
the summer load peaks while also eroding the System of An-
nual Load Factor. District steam in the form of waste heat
of power plants could alleviate these problems. Although
steam air conditioning on its own is not tremendously prof-
itable, it does contribute to the overall net profitability
1. Ibid., p. 100.
2. Ibid., p. 101.
-145-
-------
of a company by cancelling the large negative profitability
of the tonnage of electric air conditioning which it would
replace.1
The location of the refrigeration equipment is a major
consideration in the feasibility of the installation of air
conditioning. The energy disposal at the generating site
resulting from the production of a ton-hour of refrigeration
varies with the type and location of the refrigeration sys-
tem. If the equipment were located at the plant site, the
consumers would have to be nearby because present technology
for the distribution of coolant allows a maximum transporta-
tion distance of a half-mile.2 if consumption sites were
located at long distances from the plants, neither absorp-
tion systems nor turbine driven systems could compete eco-
nomically with electrically driven compressors, if charged
full steam generation and distribution costs. However,
most utilities make absorption refrigeration competitive by
offering summer heat at a discount.3
Whether the use of steam and/or hot water for air con-
ditioning lowers the total amount of thermal pollution to
the environment depends on whether the overall efficiency
is improved. However, it always lowers the thermal impact
per area by distributing the heat normally released at a
power plant site to scattered heat-use sites, thereby re-
ducing plant site energy disposal requirements.
Space heating and hot water may be provided over a
larger area than that for air conditioning. An area within
a two-mile radius of the steam generator could feasibly be
serviced if appropriate planning had been done to maintain
high steam pressures.^ A high consumption must be assured
in order for the sale of steam to be economically feasible.
Provision of hot water and steam for individual residences
is not feasible except in high population density areas.
One study shows that if population density in an apartment
area were 1^,000 people/square mile, the price of heat pro-
vided by a power plant would be equal to the average
1. NTIS, p. 262.
2. Miller, p. 70.
3. Ibid., p. 7^•
Personal communication—Boston Edison Co.
-1^6-
-------
commercial sale price of district heat in this country.
Even with a population density of 5,000/square mile, the
system would be competitive with electrical heating.1
Manufacturing process heat for industry would be a
viable use of waste heat for industries situated relatively
near a power plant. An estimate of the 1980 consumption
of industrial steam is 67.6 x 10l^ BTU's. Primary consum-
ers of this heat are chemical industries, who use 39% of
the total, petroleum refineries, 22% of total, paper mills,
18% of the total, and food processing plants, 8% of the
total. The following tables show the fuel types and heat
values consumed by these industries, and the estimates of
steam pressures required.
ESTIMATES OF STEAM PRESSURES AND PRESSURE
DISTRIBUTIONS REQUIRED IN 1980^
Percentage Steam Pressures and
of Total Distribution
Industry
Process Pressure Distribution
Steam Usage Range
(psig) (T5
Chemicals and allied
products
39
^50-1000
200- ^50
100- 200
<100
3
15
53
29
Petroleum refining and
related industries
22
150- 600
<150
20
80
Paper and allied products 18
100- 200
<100
71
29
Food and kindred products 13
50- 100
< 50
10
90
Other industries
8
TABLE 6-11
1. NTIS, p. 75-
2. Miller, p. 69-
-147-
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The use of this steam would be most feasible, as men-
tioned, for an industry built and run in conjunction with
the power plant or located very nearby. The Midland Power
Plant in Michigan supplies process steam to the Dow Chem-
ical Company facilities located across the river. The pro-
cess steam is extracted from the turbine cycle after a
point where it has already produced a substantial amount of
electricity. After Dow has utilized the energy in the steam,
it returns the steam as a condensate to the power plant.
This reduces the condensing requirement for the electricity
produced by the steam by approximately 250 mw, also reducing
the total waste heat produced by the plant. The remainder
of the waste heat from the plant is dissipated in an 880
acre evaporative cooling pond.l
6.7 Snow and Ice Melting
Another suggestion that has been made for the use of
waste heat is that of snow melting. An integral system of
sidewalk and/or street heating would prevent the accumula-
tion of snow and ice. The heat would be provided by a sys-
tem of hot water pipes placed underneath the sidewalks and
roads. Table 6-13 shows high and low cost estimates for a
city sidewalk system. For the high-cost system, the annual
steam usage was estimated to be 1^% of that required to heat
the adjacent building, while in the low-cost system, it was
2.6^.2 The high-cost estimate is based on a system which
was installed in Detroit in 1958 to heat the sidewalks,
steps, and arcade of a large fourteen story building using
the same source of steam as the building heating system.
Use of this type of heating system in roadways would be
considerably more expensive, some estimates going up to
$12/ft.2 (1948).3
Steam and/or hot water could be supplied from the con-
denser of a power plant in the same manner as district heat-
ing. Again, the distance between the plant and the point
of consumption is a constraining factor. In Northern areas
where heavy snowfall causes a buildup of snow in dumping
areas, hot water could be used for snow melting if the cost
of transporting the snow close enough to the power plant
was not prohibitive.
1. NTIS, pp. 77-79.
2. Ibid., p. 63•
3. Ibid., p. 63.
-149-
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COST ESTIMATE FOR A CITY SIDEWALK SNOW-MELTING SYSTEM
BASED ON 1969 COSTS1
SYSTEM PARAMETER
LOW-COST
SYSTEM
HIGH-COST
SYSTEM
INSTALLATION* (Does not
include sidewalk)
$
13,620
$
21,900
ANNUAL COSTS
Maintenance
Operation
Fixed Charges at 11.5%
$
290
260
1,566
$
580
260
2,866
Subtotal
$
2,116
$
3,706
Steam at $1-30/100 lb.
Power at $0.lVkwhr
187
13
988
56
TOTAL Annual Cost
$
2,316
$
1,750
UNIT COSTS
Unit total annual cost
$
0.58/ft2
$
1.19/ft2
Incremental charge for
- 50% variation of energy
(steam & electricity cost)
0.03/ft2
0.13/ft2
Unit cost for installation
3. 40/ft2
6.23/ft2*
Unit annual cost for fixed
charges
0.39/ft2
0.72/ft2
*The installation cost experienced for the
system in 1958 was $ 4.11/ft .
Detroit
TABLE 6-13
1. Miller, p. 63
-150-
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Proposals have also been made for the use of waste
heat to keep shipping lanes and harbors free from snow
and ice accumulations. One study has been done on the
feasibility of extending the shipping season of the St.
Lawrence Seaway (J.G. Biggs, Waste Heat to Extend the
St. Lawrence Seaway Season, Canadian Report AECL-3061,
1968). The investigation of this use of waste heat in
general has not gone beyond preliminary investigation.
6.8 Vehicle Propulsion
One proposal based on a study by A.P. Fraas of ORNL
is for the use of waste hot water and steam for vehicle
propulsion. Although the implementation of this is not
immediate, there is a long range interest in this system.
Heat distributed through a district heating system or
from a power plant could be used to reduce air pollution
by providing steam or superheated water for buses and
trucks. This system has been used in industries where
the elimination of sparks was necessary. Table 6-1*1 shows
a comparison of the energy available from several sources.
ENERGY AVAILABLE FROM TYPICAL SOURCES FOR AUTOMOBILE PROPULSION1
Energy Sources
Energy Stored
[BTU(thermal)
/lb. ]
Useful Energy
at Drive Wheels
(BTU/lb.)
Batteries
Lead-acid
Nickel-cadmium
Silver-cadmium
Silver-zinc
46.0
39.2
68.3
136.6
41.5
35.2
61.5
123.0
Superheated water
Release from 400° to 280° F
(260 to 50 psia)
Release from 545° to 280° F
(1000 to 50 psia)
130.0
292.0
26.0
58.0
Gasoline
18,000.0
3,600.00
TABLE 6-14
1. Ibid, p. 56.
-151-
-------
Performance of vehicles using energy storage systems
such as those that would be required in this case is
limited by space and load capacity of the storage units,
the efficiency of energy utilization, and the power require-
ments of the vehicle. An estimate of the operating range
for a vehicle powered from *J00°F superheated water shows
that 20% of the gross vehicle weight could be used for
tankage. 120 pounds of superheated water per mile or about
150 lbs. of water plus tankage would be required. For a
16,000 lb. BTUs, the range of the vehicle between refills
would be approximately 20 miles. If the temperature of the
water were decreased to 300°F, the range would drop to 10
miles and the tankage requirement would increase to 30# of
the total vehicle weight.1
6.9 Recreational Uses of Waste Heat and Cooling Facilities
Another area to be considered for the use of waste
heat from power plants is that of recreation. The heated
effluent could either be directly utilized or the cooling
facilities, i.e., ponds, could be used.
Land required for cooling ponds runs one acre of pond
plus ten acres drainage per megawatt.2 For even a small
plant of 20-25 megawatts, this means a good-sized pond of
20-25 acres. Cooling ponds which are fairly large, such as
reservoirs, lakes, or even man-made canals, could be used
for boating, swimming, fishing, and other water-associated
pastimes. Spray ponds would be smaller and their use for
swimming and boating limited due to the spraying equipment.
These types of ponds could be used in a park or garden set-
ting as fountain displays.
As in the cases for aquaculture, heated water would
enhance the growth of wild aquatic species, thereby pro-
viding fishing, clamming, etc. Heated water also could
extend the swimming season beyond its normal limits at cer-
tain seasons of the year. If ponds were not used directly
for swimming, the heated water could be used for facilities
such as swimming pools.
Nuclear plants are required by federal regulations to
have an exclusion area around the plant. An area of 300-
1. Ibid, p. 59.
2. Economy, Energy, & the Environment. Energy Policy
Division, Library of Congress, 1970.
-152-
-------
500 acres is needed by a 3j000 megawatt plant. If power
companies were to combine a landscaping plan with the
building of some cooling facility such as a pond, a public
park could be provided. This would not only improve the
power company's public relations, but could also provide
for land and facilities which presently are either unused
or not being utilized to their maximum potential. Parti-
cularly in these exclusion areas of nuclear reactors, public
parks, camping areas, wild life preserves, and other
recreational facilities, such as tennis courts, playgrounds,
playing fields, etc., would be an improvement. Public
information centers explaining the operation of the power
plant could be established in conjunction with these public
parks.
There are some problems involved with the establish-
ment of these recreational facilities. One problem deals
with the quality of the heated effluent. If it contains
mineral and/or other contaminants, its use for swimming
would be questionable. The enhanced growth of water plants
such as algae by warm water could also interfere with the
recreational use of cooling facilities. Again, the ques-
tion of public acceptance of use of facilities established
near nuclear plants arises because of the fear of radio-
active contamination. In this instance, the establishment
of information centers at the plant site would alleviate
this problem by familiarizing the public with the plant
operation.
The Fitzpatrick nuclear power plant on Lake Ontario
and the Pilgrim power plant in Plymouth, Mass., are two
examples of the establishment of recreational facilities.
The Fitzpatrick plant site includes approximately 700
acres, some of which is to be used for a wildlife preserve.
The Pilgrim nuclear power plant has established a recre-
ation area and a public information center at the plant
site.2 The hot water discharged into the ocean attracts
fish. Free fishing and use of the five acre beach-park
area is provided for the public and helps maintain good
public relations for the power company.
1. Electrical Power and the Environment, The Energy Policy
Staff Office of Science & Technology, 1970.
2. Personal communication—Pilgrim Power Plant
-153-
-------
6.10 Total Energy Complex
The final use, and perhaps the most efficient, for
waste heat is that of a combination of the uses discussed
above. In establishing a total energy complex, electri-
city could be produced, high quality steam extracted for
industrial space heating, and waste treatment uses for
facilities at the plant site. Greenhouses and aquaculture
facilities could also be built at the plant site. As
discussed earlier in this memo, a trade-off can be affected
between the percentage of fuel converted into electricity
and the percentage of fuel which produces waste heat. The
latter can be effectively reduced to zero, if a smaller
percentage production of electricity is accepted, by using
extraction and back-pressure turbine methods for the pro-
duction of process heat. An example of combined district
heating and electrial production is New York's Consolidated
Edison. Another example previously cited for the combina-
tion of electrical production and provision of process heat
for industry is the Midland power plant and Dow Chemical
Company.
Oak Ridge National Laboratory did an analysis of a
model city with a population of approximately *100 ,000 and
the climate of Philadelphia in which a power plant pro-
vided thermal energy for electricity, space heat, hot water,
and air conditioning for the commercial buildings and two-thirds
of the city's inhabitants who lived in three-story apart-
ment buildings. Heat was also provided for manufacturing
processes and for treating sewage for re-use. The use of
heat by the city reduced the average heat rejected by the
power plant in its cooling water to 63% of that of a plant
which only produced electricity. This would be reduced to
2\% at the period of maximum heat consumption in the summer.
Some of the costs associated with the model city are
as follows: a) distributed hot water costs were 1*12.5 cents/
MBTU, competitive for most U.S. cities; b) space heating and
domestic hot water costs were 198 cents/MBTU. With green-
houses, cooling towers would be eliminated, reducing the
cost of heating. Cost reduction would also result from
closer siting of the energy center to the city. Two points
were made about the geographical location of the model city.
Northern cities would have a space heating cost of 170 cents/
MBTU and would not be sensitive to air conditioning charges.
Southern cities would have higher space heating and hot water
costs in addition to being more sensitive to air conditioning
charges.1
1. Miller, p. x.
-154-
-------
Table 6-15 shows the distribution of energy produc-
tion in the reference city.
ENERGY PRODUCTION AND LOADS FOR REFERENCE CITY1
Production capacity of heat source
Annual average thermal power production
Annual average net electrical power
production
Annual average internal power consumption
Annual average district heating load
Peak summer district heating load
Peak winter district heating load
Minimum district heating load
Industrial steam load at 965 psig
Industrial steam load at 450 psig
Industrial steam load at 207 psig
Sewage distillation steam at 32 psig
Annual average heat to condenser
Maximum heat to condenser
Heat to condenser at hottest summer hour
TABLE 6-15
The heat rejection to the condenser cooling water
shown in Table 6-15 during the hottest summer hour is con-
sidered small. This could be utilized by approximately
200 acres of greenhouses, poultry or swine shelters, or
aquaculture facilities. 200 acres of greenhouses has a
maximum short-term heat disposal capacity sufficient to
dispose of the entire 1180 Mw(t) at any time of the year,
hence eliminating the need for cooling towers.2 Below is
Table 6-16 which shows heat costs at the power plant with
cooling towers and with greenhouses.
2268
Mw (t)
1—\
-=r
O
C\J
Mw (t)
463
Mw(e)
OJ
Mw(e)
457
Mw(t)
1144
Mw(t)
1088
Mw(t)
0
Mw(t)
43
Mw (t)
251
Mw (t)
74
Mw(t)
90
Mw( t)
634
Mw(t)
1180
Mw (t)
230
Mw(t)
1. Ibid, p. xxv.
2. Ibid, p. xxiv.
-155-
-------
UNIT HEAT PRODUCTION COSTS1
Heat Costs at Power Plant
(cents/MBTU)
Heat Production
With Cooling With
Tower Greenhouses*
Industrial steam
Prime (965 psig)
50. 4
46.3
450 psig
207 psig
32 psig
43.8
4o. 3
37.5
34.5
24.3
22.3
District heat
36.5
34.6
* Assuming no thermal energy charge to greenhouses.
TABLE 6-16
The implementation of a total energy complex would
result in a more efficient use of power, hence conservation
of fossil fuels, in addition to reducing the thermal pollu-
tion and air pollution. A number of services could be pro-
vided for areas around the power plants such as recreational
facilities; food from greenhouses, and other agricultural
and aquacultural uses of waste heat; sewage would be treated
for recycling; space heating; air conditioning; hot water;
and process heat for industries.
1. Ibid, p. xxvi.
-156-
-------
APPENDIX I
DATA ON OPTIONS FOR TBS
Total Industry Composition
Capacity
IGC
%
Factor
nuclear £ 1973
248
100
54
Open Cycle
178
72
52
Already Closed Cycle
70
28
56
Forced Draft Towers
29
12
46
Natural Draft Towers
21
8
67
Ponds
20
8
56
nuclear 1974-1978
112
100
63
Open Cycle
25
22
64
Planning Closed Cycle
87
78
62
Forced Draft Towers
23
21
67
Natural Draft Towers
47
42
59
Ponds
17
15
64
Nuclear £ 1973
Open Cycle
Already Closed Cycle
Forced Draft Towers
Natural Draft Towers
Ponds
23
15
8
4
4
0
100
67
33
17
16
0
73
71
77
77
78
Nuclear 1974-1978
Open Cycle
Planning Closed Cycle
Forced Draft Towers
Natural Draft Towers
Ponds
94
5^
40
13
27
0
100
57
43
14
29
0
73
75
69
68
70
Rules for Compliance Date
Base-load _> 500Mw
Base-load 300-500Mw
Base-load <_ 300Mw
(For Option I, base-load plant£25Mw
Capacity Factor<60$
YEAR
1979
1980
1981
1983
1983
(IGC in Thousands
of Mw)
1-1
-------
Expected Coverage of Alternative Guidelines
Option A - exempt:
plants £ 25 Mw and utilities £ 150 Mw
units built before 1956
units operating below 40$ of capacity
Capacity Placed
In Service
% Coverage by Required
Compliance Date
I.G.C. 1979 1980 1981 1983
Total
Cumulative
Coverage
Non-nuclear
Prior to 197^
Covered by guidelines
before 316(a)
107
6.7
2.1
12. 7
21. 4
43.0
after 316(a)
44
1.8
1.1
7-2
7.5
17.6
Average capacity factor
before 316(a)
67.2
69.4
69.7
52.3
60. 7
after 316(a)
67.6
69-4
72.2
52.4
63.2
197^-1978
Covered by guidelines
before 316(a)
25
11.8
0
3-2
7.3
22.4
after 316(a)
10
4.1
0
1.0
3.7
8.7
Average capacity factor
before 316(a)
68.4
68.7
55.4
64.2
after 316(a)
67.6
69-8
55-4
62.7
Nuclear
Prior to 1974
Covered by guidelines
before 316(a)
15
45. 8
13-9
3.8
0
63.5
after 316(a)
3
12.9
0
1.1
0
14.0
Average capacity factor
before 316(a)
74.3
74.9
64.9
73-9
after 316(a)
74. l
60.9
73-0
1974-1978
Covered by guidelines
before 316(a)
54
53.4
3.4
0
0
56.8
after 316(a)
28
30.1
0
0
0
30.1
Average capacity factor
before 316(a)
75.0
74.9
75-0
after 316(a)
75-1
-
-
-
75.1
1-2
-------
Expected Coverage of Alternative Guidelines
Option B - exempt:
plants <_ 25 Mw and utilities £ 150 Mw
units built before 1961
units operating below 40% of capacity
%
Coverage by
Required
Total
Capacity Placed
Compliance
Date
Cumulative
In Service
I. G . C
• 1979
1980
1981
1983
Coverage
Non-nuclear
Prior to 1974
Covered by guidelines
16. 0
before 316(a)
83
6.7
2.1
8.6
33-5
after 316(a)
38
1.8
1.1
5-3
7.2
15-4
Average capacity factor
61.1
before 316(a)
Si.2
69.4
69.5
53.0
after 316(a)
67. 6
69.4
71.1
52.9
62.0
197*1-1978
Covered by guidelines
before 316(a)
25
11.8
0
3-2
7.3
22.4
after 316(a)
10
4.1
0
1.0
3.7
8.7
Average capacity factor
68.7
64.2
before 316(a)
68.4
55.4
after 316(a)
67.6
-
69-8
55.4
62.7
Nuclear
Prior to 1974
Covered by guidelines
before 316(a)
13
45.8
13.9
3.8
0
63.5
after 316(a)
3
12 .9
0.0
1.1
0
14 .0
Average capacity factor
before 316(a)
74.3
74.9
64.9
73.9
after 316(a)
74.1
60. 9
73.0
1974-1978
Covered by guidelines
before 316(a)
54
53-4
3-4
0
0
56.8
after 316(a)
28
30.1
0
0
0
30.1
Average capacity factor
before 316(a)
75.0
74.9
75.0
after 316(a)
75-1
-
-
-
75-1
1-3
-------
Expected Coverage of Alternative Guidelines
Option C - exempt:
plants £ 300 Mw
units built before 1956
units operating below 40% of capacity
Capacity Placed
In Service
% Coverage by Required
Compliance Date
I.G.C. 1979 1980 1981 1983
Total
Cumulative
Coverage
Non-nuclear
Prior to 1974
Covered by guidelines
before 316(a) 59 6.7 2.1 0 15.0 23.8
after 316(a) 21 1.8 1.1 0 5.6 8.5
Average capacity factor
before 316(a) 67.2 69-4 53-1 58.5
after 316(a) 67.6 69-4 53-9 58.8
19714-1978
Covered by guidelines
before 316(a) 22 11.8 0 0 7.3 19.2
after 316(a) 9 1.1 0 0 3-7 7-7
Average capacity factor
before 316(a) 68.4 55.4 63.4
after 316(a) 67.6 - 55-4 61.8
Nuclear
Prior to 1974
Covered by guidelines
before 316(a) 14 45.8 13.9 0 0 59-7
after 316(a) 3 12.9 0 0 0 12.9
Average capacity factor
before 316(a) 74.3 74.9 74.5
after 316(a) 74.1 74.1
1974-1978
Covered by guidelines
before 316(a) 54 53-4 3-4 0 0 56.8
after 316(a) 28 30.1 0 0 0 30.1
Average capacity factor
before 316(a) 75-0 74-9 75-0
after 316(a) 75.1 - 75.1
1-4
-------
Expected Coverage of Alternative Guidelines
Option D - exempt:
units <_ 300 Mw
units built before 1961
units operating below k0% of capacity
Capacity Placed
In Service
% Coverage by Required
Compliance Date
I.G.C. 1979 1980 1981 1983
Total
Cumulative
Coverage
Non-nuclear
Prior to 197^
Covered by guidelines
before 316(a) 50 6.7 2.1 0 11.2
after 316(a) 21 1.8 1.1 0 5-6
Average capacity factor
before 316(a) 67-2 69.4 53-9
after 316(a) 67.6 69.^ 53-9
197^-1978
Covered by guidelines
before 316(a) 22 11.8 0 0 7-3
after 316(a) 9 4.1 0 0 3-7
Average capacity factor
before 316(a) 68.4 55-^
after 316(a) 67.6 - 55-^
20.0
8.5
60.0
58.8
19-2
7-7
63-^
61.8
Nuclear
Prior to 197^
Covered by guidelines
before 316(a) 14
after 316(a) 3
Average capacity factor
before 316(a)
after 316(a)
197^-1978
Covered by guidelines
before 316(a) 5^
after 316(a) 28
Average capacity factor
before 316(a)
after 316(a)
15.8 13.9
12.9 0
7^-3 7^-9
74 .1
53.4
30.1
3.4
0
75-0 7^.9
75-1
0
0
0
0
0
0
0
0
59.7
12.9
7^.5
7^.1
56.8
30.1
75-0
75-1
1-5
-------
Expected Coverage of Alternative Guidelines
Option E - exempt:
units built before 1956
units operating below 40% of capacity
Capacity Placed
In Service
% Coverage by Required
Compliance Date
.G.C. 1979 1980 1981 1983
Total
Cumulative
Coverage
Non-nuclear
Prior to 1974
Covered by
guidelines
before 316(a)
108
6.7
2.1
12.9
21.6
43.4
after 316(a)
44
1.8
1.1
7.2
7-6
17.7
Average capacity factor
before 316(a)
67.2
69.4
69.7
52.3
60. 7
after 316(a)
67.6
69.4
72.2
52.6
63-2
1974-1978
Covered by guidelines
before 316(a)
25
11. 8
0
3.2
7.3
22.4
after 316(a)
10
4.1
0
1.0
3.7
8.7
Average capacity factor
before 316(a)
68. 4
&
68.7
55-4
64 . 2
after 316(a)
61.6
-
69.8
55-4
62.7
Nuclear
Prior to 1974
Covered by guidelines
before 316(a) 15 45.8 13-9
after 316(a) 3 12.9 0
Average capacity factor
before 316(a) 7*1.3 74.9
after 316(a) 74.1
1974-1978
Covered by guidelines
before 316(a) 54 53-^ 3-4
after 316(a) 28 30.I 0
Average capacity factor
before 316(a) 75.0 74.9
after 316(a) 75.1
3-8
1.1
64.9
60.9
0
0
0
0
0
0
63.5
14.0
73-9
73-0
56.8
30.1
75.0
75-1
1-6
-------
Expected Coverage of Alternative Guidelines
Option F - exempt:
units built before 1961
units below Ho% of capacity
Capacity Placed
In Service
% Coverage by Required
Compliance Date
I.G.C. 1979 1980 1981 1983
Total
Cumulative
Coverage
Non-nuclear
Prior to 1974
Covered by guidelines
before 316(a)
84
6.7
2.1
8.8
16.1
33.8
after 316(a)
38
1.8
1.1
5-3
7.2
15. 4
Average capacity factor
before 316(a)
67.2
69. 4
69-5
52.9
61.1
after 316(a)
67.6
69.4
71.1
52.9
62.0
1974-1978
Covered by guidelines
before 316(a)
25
11.8
0
3-2
7.3
22. 4
after 316(a)
10
4.1
0
1.0
3-7
8.7
Average capacity factor
before 316(a)
68.4
68.7
55.4
64.2
after 316(a)
67.6
69-8
55-4
62. 7
Nuclear
Prior to 1974
Covered by guidelines
before 316(a)
15
45.8
13.9
3.8
0
63.5
after 316(a)
3
12. 9
0
1.1
0
14.0
Average capacity factor
before 316(a)
74.3
74.9
64.9
73-9
after 316(a)
74.1
60. 9
73-0
1974-1978
Covered by guidelines
before 316(a)
54
53-4
3.4
0
0
56.8
after 316(a)
28
30.1
0
0
0
30.1
Average capacity factor
before 316(a)
75-0
74.9
75.0
after 316(a)
75-1
-
-
-
75-1
1-7
-------
Expected Coverage of Alternative Guidelines
Option G - exempt:
units
built
before
1961
units
below
20% of
capacity
%
Coverage
¦ by 1
Required
Total
Capacity Placed
Compliance
Date
Cumulative
In Service
I.G.C.
1979
1980
1981
1983
Coverage
Non-nuclear
Prior to 1972
Covered by guidelines
8.8
before 316(a)
94
6.7
2.1
20. 3
37-9
after 316(a)
43
1.8
1.1
5.3
9.2
17.4
Average capacity factor
before 316(a)
Si.2
69.1
69-5
49.1
58.2
after 316(a)
67.6
69.4
71.1
48.2
58.5
1974-1978
Covered by guidelines
before 316(a)
25
11.8
0
3-2
7.3
22.4
after 316(a)
10
4.1
0
1.0
3-7
8.7
Average capacity factor
64.2
before 316(a)
68. 4
68.7
55.4
after 316(a)
67.6
~
69.8
55-4
62.7
Nuclear
Prior to 1974
Covered by guidelines
3.8
63-5
before 316(a)
15
45.8
13.9
0
after 316(a)
3
12.9
0
1.1
0
14.0
Average capacity factor
before 316(a)
74.3
7^.9
64.9
73-9
after 316(a)
7^.1
60.9
73-0
1974-1978
Covered by guidelines
before 316(a)
54
53-4
3-4
0
0
56.8
after 316(a)
28
30.1
0
0
0
30.1
Average capacity factor
before 316(a)
75-0
74.9
75.0
after 316(a)
75.1
-
-
-
75.1
1-8
-------
Expected Coverage of Alternative Guidelines
Option H - exempt:
units built before 1972
% Coverage by Required Total
Capacity Placed Compliance Date Cumulative
In Service I.G.C. 1979 1980 1981 1983 Coverage
Non-nuclear
Prior to 1974
Covered by guidelines
before 316(a)
13
3-7
0
0
1.5
5.2
after 316(a)
6
1.8
0
0
0.7
2.6
Average capacity factor
before 316(a)
67.6
55.5
64.1
after 316(a)
67.6
55.5
64.1
1974-1978
Covered by guidelines
before 316(a)
25
11.8
0
3.2
7.3
22. 4
after 316(a)
10
4.1
0
1.0
3.7
8.7
Average capacity factor
before 316(a)
68.4
68.7
55.4
64.2
after 316(a)
67.6
-
69.8
55.4
62.7
Nuclear
Prior to 1974
Covered by guidelines
before 316(a) 14 45.8 13-9 0 0 59-7
after 316(a) 3 12.9 0 0 0 12.9
Average capacity factor
before 316(a) 74.3 74.9 74.5
after 316(a) 74.1 74.1
1974-1978
Covered by guidelines
before 316(a) 54 53.4 3-4 0 0 56.8
after 316(a) 28 30.1 0 0 0 30.1
Average capacity factor
before 316(a) 75.0 74.9 75.0
after 316(a) 75-1 - - 75-1
1-9
-------
Expected Coverage of Alternative Guidelines
Option I - exempt:
plants £ 25 Mw and utilities £ 150 Mw
units built before 1959
Capacity Placed
In Service
% Coverage by Required
Compliance Date
I.G.C. 1979 1980 1981 1983
Total
Cumulative
Coverage
Non-nuclear
Prior to 1974
Covered by guidelines
before 316(a)
133
6.7
2.1
14.1
30.6
53.6
after 316(a)
57
1.8
1.1
7-8
12.1
22.8
Average capacity factor
before 316(a)
67. 2
69.4
69-9
47.6
56.8
after 316(a)
67.6
69.4
72.1
45. 4
57.4
1974-1978
Covered by guidelines
before 316(a)
25
11.8
0
3-2
7-3
22.4
after 316(a)
10
4.1
0
1.0
3.7
8.7
Average capacity factor
64.2
before 316(a)
68.4
68.7
55.4
after 316(a)
67.6
69.8
55.4
62. 7
Nuclear
Prior to 1974
Covered by guidelines
before 316(a)
15
45.8
13.9
3.8
3-0
66.5
after 316(a)
3
12.9
0
1.1
0
14.0
Average capacity factor
before 316(a)
74.3
74.9
64.9
OJ
OJ
1—1
71.1
after 316(a)
74.1
60. 9
73.0
1974-1978
Covered by guidelines
before 316(a)
54
53.4
3.4
0
0
56.8
after 316(a)
28
30.1
0
0
0
30.1
Average capacity factor
before 316(a)
75-0
74.9
75-0
after 316(a)
75.1
-
-
-
75-1
1-10
-------
Expected Coverage of Alternative Guidelines
Option J - exempt:
units below 60# of capacity
% Coverage by Required
Total
Capacity Placed
Compliance
Date
Cumulative
In Service
I.G.C.
1979
1980
1981
1983
Coverage
Non-nuclear
Prior to 1974
Covered by guidelines
74
before 316(a)
6.7
2.1
21.1
0
29-9
after 316(a)
31
1.8
1.1
9-5
0
12.4
Average capacity factor
67-2
69. 4
69.1
68.7
before 316(a)
0
after 316(a)
67.6
69- 4
72.0
0
71.2
1974-1978
Covered by guidelines
11.8
22. 4
before 316(a)
25
0
3-2
7.3
after 316(a)
10
4.1
0
1.0
3.7
8.7
Average capacity factor
68.4
68.7
64. 2
before 316(a)
55.4
after 316(a)
67.6
69-8
55.4
62. 7
Nuclear
Prior to 1974
Covered by guidelines
45. 8
3-8
66.5
before 316(a)
15
13-9
3.0
after 316(a)
3
12.9
0
1.1
0
14.0
Average capacity factor
74.3
74.9
64.9
before 316(a)
OJ
C\J
1—1
71.1
after 316(a)
74.1
60. 9
73-0
1974-1978
Covered by guidelines
54
56.8
before 316(a)
53.4
3-4
0
0
after 316(a)
28
30.1
0
0
0
30.1
Average capacity factor
74.9
before 316(a)
75-0
75-0
after 316(a)
75.1
-
-
-
75-1
1-11
-------
Expected Coverage of Alternative Guidelines
Option K - exempt:
turbine units < 150 Mw
units built before 1961
Capacity Placed
in Service
% Coverage by Required
Compliance Date
I.G.C. 1979 1980 1981 1983
Total
Cumulative
Coverage
Non-nuclear
Prior to 1974
Covered by
guidelines
before 316(a)
82
6.7
2.1
6.6
17.7
33.1
after 316(a)
36
1.8
1.1
3.7
8.0
14. 6
Average capacity factor
before 316(a)
67. 2
69. 4
69-6
50.2
58.8
after 316(a)
67.6
69.4
71.9
50.2
59-3
1974-1978
Covered by guidelines
before 316(a)
23
11.8
0
1.2
7-3
20. 4
after 316(a)
9
4.1
0
0
3.7
7-7
Average capacity factor
before 316(a)
68.4
67.0
55.4
63-6
after 316(a)
67.6
~
'
55.4
61.8
Nuclear
Prior to 1974
Covered by guidelines
before 316(a)
14
45.8
13-9
0
0
59-7
after 316(a)
3
12.9
0
0
0
12.9
Average capacity factor
before 316(a)
74.3
74.9
74.5
after 316(a)
74.1
74.1
197^-1978
Covered by guidelines
before 316(a)
54
53.4
3.4
0
0
56.8
after 316(a)
28
30.1
0
0
0
30.1
Average capacity factor
before 316(a)
75-0
74.9
e-
e-
75.0
after 316(a)
75.1
-
-
-
75-1
1-12
-------
Expected Coverage of Alternative Guidelines
Option L - exempt:
all units built before or during I960
Capacity Placed
In Service
I.G.C.
Coverage by Required
Compliance Date
1979 1980 1981 1983
Total
Cumulative
Coverage
Non-nuclear
Prior to 1974
Covered by guidelines
before 316(a)
95
6.7
2.1
8.8
20.5
38.2
after 316(a)
1.8
1.1
5-3
9.4
17.6
Average capacity factor
before 316(a)
67.2
69.4
69.5
48.6
57.9
after 316 (a)
•
67.6
69.4
71.1
47.4
57.9
197^-1978
Covered by guidelines
before 316(a)
25
11.8
0
3.2
7.3
22.4
after 316(a)
10
4.1
0
1.0
3-7
8.7
Average capacity factor
64 . 2
before 316(a)
68.4
68.7
55-4
after 316(a)
67.6
69.9
55.4
62.7
Nuclear
Prior to 1974
Covered by guidelines
63-5
before 316(a)
15
45.8
13.9
3.8
0
after 316(a)
3
12.9
0
1.1
0
14 .0
Average capacity factor
64.9
before 316(a)
74.3
74.9
73-9
after 316(a)
74.1
—
60.1
73-0
197^-1978
Covered by guidelines
56.8
before 316(a)
54
53.4
3.4
0
0
after 316(a)
28
30.1
0
0
0
30.1
Average capacity factor
before 316(a)
75-0
74.9
75.0
after 316(a)
75.1
-
-
-
75-1
1-13
-------
Expected Coverage of Alternative Guidelines
OPTION M
- I960 - 200 Mw < 40# CAPACITY
Capacity Placed
In Service
I.G.C
% Coverage by Required
Compliance Date
1979 1980 1981 1983
Total
Cumulative
Coverage
Non-nuclear
Prior to 1974
Covered by guidelines
before 316(a)
68
6.7
2.1
6.1
12.5
27.4
after 316(a)
32
1.8
1.1
3.7
6.3
12.9
Average capacity factor
before 316(a)
67.2
69.4
70.0
53-8
61.9
after 316(a)
67.6
69.4
71-9
53.8
62.3
197^-1978
Covered by guidelines
before 316(a)
22
11.8
0
0
7.3
19-2
after 316(a)
9
4.1
0
0
3-7
7.7
Average capacity factor
before 316(a)
68.4
-
-
55.4
63-4
after 316(a)
67.6
55.4
61.8
Nuclear
Prior to 1974
Covered by guidelines
before 316(a)
14
45.8
13-9
0
0
59.7
after 316(a)
3
12.9
0
0
0
12.9
Average capacity factor
before 316(a)
74.3
74.9
-
-
74.5
after 316(a)
74.1
-
-
-
74.1
1974-1978
Covered by guidelines
before 316(a)
54
53.4
3.4
0
0
56.8
after 316(a)
28
30.1
0
0
0
30.1
Average capacity factor
before 316(a)
75.0
74.9
-
-
75-0
after 316(a)
75.1
-
-
-
75-1
1-14
-------
Expected Coverage of Alternative Guidelines
OPTION N ^ I960 < 200Mw NO CAPACITY FACTOR
Capacity Placed
In Service
% Coverage by Required
Compliance Date
I.G.C. 1979 1980 1981 1983
Total
Cumulative
Coverage
Non-nuclear
Prior to 1974
Covered by guidelines
before 316(a) 75 6.7 2.1 6.1 15-2 30.2
after 316(a) 34 1.8 1.1 • 3-7 7-3 13-9
Average capacity factor
before 316(a) 67.2 69-4 70.0 50.8 59-6
after 316(a) 67.6 69-4 71-9 50.9 60.2
1974-1978
Covered by guidelines
before 316(a) 22 11.8 0 0 7-3 19-2
after 316(a) 9 4.1 0 0 3-7 7-7
Average capacity factor
before 316(a) 68.4 - 55.4 63-4
after 316(a) 67*6 - - 55-4 61.8
Nuclear
Prior to 1974
Covered by guidelines
before 316(a) 14 45.8 13*9 0 0
after 316(a) 3 12.9 0 0 0
Average capacity factor
before 316(a) 74.3 74.9
after 316(a) 74.1 -
1974-1978
Covered by guidelines
before 316(a) 54 53-4 3-4 0 0
after 316(a) 28 30.1 0 0 0
Average capacity factor
before 316(a) 75-0 74.9
after 316(a) 75-1 -
59.7
12.9
74.5
74.1
56.8
30.1
75-0
75-1
1-15
-------
SEPTEMBER OPTION
Expected Coverage of Alternative Guidelines
Option 0: exempt
all units before or during 1974
Capacity Placed
In Service
% Coverage by Required
Compliance Date
I.G.C. 1979 1980 1981 1983
Total
Cumulative
Coverage
Non-nuclear
Prior to 197^
Covered by guidelines
before 316(a)
0
0
0
0
0
0
after 316(a)
0
0
0
0
0
0
Average capacity factor
before 316(a)
-
-
-
-
-
after 316(a)
-
-
-
-
-
1973-1977
Covered by guidelines
before 316(a)
9
3-7
0
2.2
2.0
7.9
after 316(a)
2
0
0
0.5
1.0
1.5
Average capacity factor
before 316(a)
70.0
-
67.0
55-3
67.5
after 316(a)
-
-
67.0
55.3
59.0
Nuclear
Prior to 197^
Covered by guidelines
before 316(a) 0 0 0 0 0 0
after 316(a) 0 0 0 0 0 0
Average capacity factor
before 316(a) -
after 316(a) -
1973-1977
Covered by guidelines
before 316(a) 36 37.8 0 0 0 37.8
after 316(a) 21 22.3 0 0 0 22.3
Average capacity factor
before 316(a) 7^.7 - 7^.7
after 316(a) 7^.9 - 7^.9
1-16
-------
SEPTEMBER OPTION
Expected Coverage of Alternative Guidelines
Option P: Exempt
all units built before 1970
% Coverage by Required
Total
Capacity Placed
Compliance
Date
Cumu
In Service
I.G.C.
1979
1980
1981
1983
Cove:
Non-nuclear
Prior to 1974
Covered by guidelines
before 316(a)
27
3.7
0
2.0
5.2
10.9
after 316(a)
13
1.8
0
1. 0
2.3
5.2
Average capacity factor
before 316(a)
67.6
-
68.1
57.0
62.6
after 316(a)
67-6
-
74. l
75.0
64 .1
1974-1978
Covered by guidelines
before 316(a)
25
11.8
0
3.2
7.3
22.4
after 316(a)
10
4.1
0
1.0
3.7
8.7
Average capacity factor
before 316(a)
68.4
-
68.7
55.4
64. 2
after 316(a)
67.6
—
69.8
55.4
62. 7
Nuclear
Prior to 1974
Covered by guidelines
before 316(a)
14
45.8
13.9
0
0
59.7
after 316(a)
3
12. 9
0
0
0
12.9
Average capacity factor
before 316(a)
7^.3
74.9
-
-
74.5
after 316(a)
7^.1
-
-
-
74 .1
1974-1978
Covered by guidelines
before 316(a)
54
53-4
3.1
0
0
56.8
after 316(a)
28
30.1
0
0
0
30.1
Average capacity factor
before 316(a)
75-0
74.9
-
-
75.0
after 316(a)
75-1
-
-
-
75.1
1-17
-------
FINAL OPTION
Expected Coverage of Alternative Guidelines
Option Q: Exempt units built before 1970
and units - 500 Mw built before 1974
or: Exempt all units built before 1974 except
for units - 500 Mw built after 1969
Capacity Placed
In Service
I.G.C
Coverage by Required
Compliance Date
1979 1980 1981 1983
Total
Cumulative
Coverage
Non-nuclear
Prior to 1974
Covered by guidelines
before 316(a)
after 316(a)
Average capacity factor
17
8
3-7
1.8
0
0
0
0
3.1
1.5
6.7
3.4
before 316(a)
67.6 -
—
57-5
63.0
after 316(a)
67.6 -
-
57-5
63.0
1974-1978
Covered by guidelines
before 316(a)
25
11.8 0
3.2
7.3
22.4
after 316(a)
10
4.1 0
1.0
3-7
8.7
Average capacity factor
before 316(a)
68.4
68.7
55.4
64.2
after 316(a)
67.6
69.8
55.4
62.7
Nuclear
Prior to 1974
Covered by guidelines
before 316(a) 11
after 316(a) 3
Average capacity factor
before 316(a)
after 316(a)
197^-1978
Covered by guidelines
before 316(a) 54
after 316(a) 28
Average capacity factor
before 316(a)
after 316(a)
45.8
12.9
74.3
74.1
53.4
30.1
75-0
75-1
0
0
3-4
0
74.9
0
0
0
0
0
0
0
0
45.8
12.9
74.3
74.1
56.8
30.1
75.0
75.1
1-18
-------
MARCH OPTION
Expected Coverage of Alternative Guidelines
Option R:
Exempt Plants < 25 Mw
And Utilities ^ 150 Mw
And Units * 1949
%
Coverage by
Required
Total
Capacity Placed
Compliance
Date
Cumulati
In Service
I.G.C.
1979
1980
1981
1983
Coverage
Non-nuclear
Prior to 1974
Covered by guidelines
63.1
before 316(a)
157
6.7
2.1
20. 5
33.7
after 316(a)
65
1.8
1.1
9.5
13.7
26.1
Average capacity factor
56.7
before 316(a)
67.2
69. 4
69.1
46.2
after 316(a)
67.6
69. 4
72.0
43.2
56.5
197^-1978
Covered by guidelines
before 316(a)
25
11.8
0
3-2
7-3
22 . 4
after 316(a)
10
4.1
0
1.0
3-7
8.7
Average capacity factor
68.7
64.2
before 316(a)
68.4
-
55.4
after 316(a)
67.6
-
69.8
55-4
62.7
Nuclear
Prior to 1974
Covered by guidelines
before 316(a) 15 45-8 13-9 3.8 3.0 66.5
after 316(a) 3 12.9 0 1.1 0 14.0
Average capacity factor
before 316(a) 74.3 74.9 64.9 12.2 71.1
after 316(a) 74.1 - 60.9 - 73-0
1974-1978
Covered by guidelines
before 316(a) 54 53-4 3-4 0 0 56.8
after 316(a) 28 30.1 0 0 0 30.1
Average capacity factor
before 316(a) 75-0 74.9 - - 75-0
after 316(a) 75-1 - 75-1
1-19
-------
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