6EPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 2771 1
EPA-600/7-79-001
January 1979
Closed-cycle Cooling
Systems for
Steam-electric
Power Plants:
A State-of-the-art Manual
Interagency
Energy/Environment
R&D Program Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, u-.
Protection Agency, have been grouped into nine series. These nine
gories were established to facilitate further development and application o
vironmental technology. Elimination of traditional grouping was conscious./
planned to foster technology transfer and a maximum interface in related neios.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
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the views and policies of the Government, nor does mention of trade names or
commercial' products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informs
tion Service, Springfield, Virginia 22161. 'nrorma-
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EPA-600/7-79-001
January 1979
Closed-cycle Cooling Systems for
Steam-electric Power Plants:
A State-of-the-art Manual
by
D.C. Senges, H.A. Alsentzer, G.A. Englesson,
M.C. Hu, and C. Murawczyk
Mackell, Inc.
P.O. Box 411
Woodbury, New Jersey 08096
Contract No. 68-02-2637
Program Element No. EHE624A
EPA Project Officer: Theodore G. Brna
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
-------
DISCLAIMER
This report has been reviewed by the Industrial Environ-
mental Research Laboratory, Office of Energy, Minerals, and
Industry, Research Triangle Park, North Carolina 27711, U.S.
Environmental Protection Agency, and approved for publication.
Approval does not signify that the contents necessarily reflect
the views and policies of the U.S. Environmental Protection
Agency, nor does mention of trade names or commercial products
constitute endorsement or recommendation for use.
-------
ABSTRACT
A technical review of the state-of-the-art of thermal pol-
lution control and treatment of cooling water in the steam-
electric power generation industry has been performed and is
presented in a practical manual format.
The manual provides an assessment of current, near horizon,
and future technologies utilized or anticipated to be used with
closed-cycle cooling systems. The manual is organized into
several basic parts for ease of reference, including the design
and operation of closed-cycle cooling systems, their capital
and operating costs, methods of evaluation and comparison, water
treatment, environmental assessment of water and nonwater im-
pacts, permits required to build and operate, and a brief dis-
cussion of benefit-cost analyses.
The manual provides sufficient information to allow an
understanding of the major parameters which are important to
the design, licensing, and operation of closed-cycle cooling
systems. It was prepared for engineers, technical managers, and
federal and state regulatory agency staffs, who must evaluate
and render judgments on the application and use of these sys-
tems .
111
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CONTENTS
Abstract iii
Tables xiii
Figures xvii
Acknowledgments xxiii
1. Introduction 1
1.1 Pur po se 1
1. 2 Closed-Cycle Cooling Systems 1
1.3 Water Treatment for Closed-Cycle Cooling.... 2
1.4 Environmental Impacts of Closed-Cycle
Cooling Systems 3
2. Heat Rejection and Power Production From Steam
Electric Power Plants 5
2.1 Basic Power Plant and Cooling System
Components 5
2.1.1 Power Plant Components
2.1.1.1 Light Water Reactor (LWR)
Power Plant 5
2.1.1.2 Fossil Power Plants 6
2.1.2 Cooling System Components 6
2.2 Power Plant Cycle and Thermal Efficiency.... 6
2.2.1 Steam Cycle for Fossil and Light
Water Reactor Power Plants 7
2.2.2 Thermal Efficiency and Waste Heat
Re j ection 8
2.2.2.1 Thermal Efficiency 8
2.2.2.2 Waste Heat Rejection Rate... 10
2.3 Effect of Cooling System Performance on
Power Plant Performance 10
References 20
3. Economic Evaluation of Alternate Cooling
Systems 21
3.1 Methods of Economic Evaluation 21
3.1.1 General Description 21
3.1.2 Fixed Demand/Fixed Heat Source
Method 22
3.1.3 Fixed Demand/Scalable Heat Source
Method 22
3.1.4 Negotiable Demand/Fixed Heat Source
Method 23
3.2 Treatment of Loss of Plant Performance 23
3.3 Capacity and Energy Penalty Assessment 24
3.4 Economic Factors for Capacity and Energy
Penalty Assessment 26
v
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27
3. 5 Other Penalty Costs 27
351 Water Cost Penalty • • • • •'
2.5.2 Cooling System Maintenance Pen^^_ _ 27
3.6 Total Evaluated "cost "and Optimum Cooling^ ^
System 29
3.7 Economic Optimization 3?
References i " A" ' i "
4. Design and Operation of Conventional Cooling ^ ^
Systems ., Q
4.1 Evaporative Cooling Tower Systems **
4.1.1 General Description -J*
4.1.2 Heat Transfer ^ U
4.1.3 Design and Performance Parameters.... 44
4.1.4 Mechanical Draft Wet Cooling Tower
Design
4.1.5 Natural Draft Wet Cooling Tower
Design • 46
4.1.6 Fan-Assisted Natural Draft Cooling
Tower Design 48
4.1.7 Description of Components and
Materials of Construction Used
in Wet Cooling Towers 49
4.1.7.1 Tower Framework 49
4.1.7.2 Water Distribution System... 49
4.1.7.3 Fill or Packing Material... . 50
4.1.7.4 Drift Eliminators 50
4.1.7.5 Inlet Louvers 50
4.1.7.6 Water Collecting Basin 50
4.1.7.7 Fans 50
4 . 2 Cooling Ponds 51
4.2.1 General Description of Cooling
Ponds 51
4.2.2 Classification of Cooling Ponds 52
4.2.2.1 Shallow Ponds 52
4.2.2.2 Deep Ponds 53
4.2.3 Heat Transfer in Cooling Ponds 53
4.2.3.1 Mechanisms of Heat Transfer 53
4.2.3.2 Net Rate of Heat Transfer
Across a Cooling Pond
Surface 54
4.2.4 Design and Performance Parameters
for Cooling Ponds 55
4.2.4.1 Parameters Affecting Heat
Transfer 55
4.2.4.2 Parameters Affecting Water
Circulation Patterns 56
4.2.5 Design and Size of Cooling Ponds 58
4.2.5.1 Design of Cooling Ponds 58
4.2.5.2 Sizing of Cooling Ponds.... \ 58
vi
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4. 3 Spray Canals 61
4.3.1 General Description 61
4.3.2 Heat Transfer-Performance of Spray
Module. . 61
4.3.3 Design and Performance Parameters.... 63
4.3.4 Spray Canal Design 64
4.3.4.1 Canal Design Using System
Model _L_!_L 64
4.3.4.2 Canal Design Using Ntu
Model 66
4.3.5 Mechanical Design of Spray Modules... 67
4.4 Dry Cooling Tower Systems 68
4.4.1 General Description of Dry Cooling
Systems 68
4.4.2 Types of Dry Cooling Systems 68
4.4.2.1 Direct Dry Cooling System... 68
4.4.2.2 Indirect Dry Cooling System 69
4.4.2.3 Comparison of Direct and
Indirect Dry Cooling
Systems 70
4.4.2.4 Comparison of Spray
Condenser and Surface
Condenser 70
4-4.3 Heat Transfer in Dry Tower 71
4.4.4 Design of Dry Cooling Towers 75
4.4.4.1 Sizing of Mechanical Draft
Dry Towers 76
4.4.4.2 Sizing of Natural Draft Dry
Tower s 77
4.4.4.3 Design Parameters 77
4.4.5 High Back Pressure Turbines 78
4.4.6 Operating Experience of Dry Cooling
Towers 78
4.5 Design and Cost of Conventional Cooling
Systems 79
4.5.1 General Description 79
4.5.2 Typical Designs and Costs of
Conventional Cooling Systems 80
4.5.3 Adjustment of Capital and Penalty
Costs 81
References 126
5. Near Horizon Cooling Systems 133
5.1 Introduction 133
5.2 Wet/Dry Towers for Plume Abatement 134
5.2.1 General Description 134
5.2.2 Principles of Wet/Dry Tower
Operation for Plume Abatement 134
5.2.3 Plume Temperature and Moisture
Content of the Wet/Dry Tower Plume. 136
VII
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5.2.4 Design of Wet/Dry Towers for Plume
Abatement 138
5.2.5 Typical Size, Performance and Cost
of Wet/Dry Tower Systems for Plume
Abatement -*-3^
5.3 Wet/Dry Towers for Water Conservation 139
5.3.1 General Description 139
5.3.2 Design and Operation of Series Flow
Wet/Dry Towers for Water
Conservation 140
5.3.3 Design, Economics and Plant Perfor-
mance of Wet/Dry Tower Systems
for Water Conservation 141
5.3.3.1 Design and Cost 141
5.3.3.2 Plant Performance 142
5.3.3.3 Water Usage and Costs 143
5.3.4 Economic Feasibility of Wet/Dry
Tower Systems for Water
Conservation 144
References 165
6. Advanced Cooling Systems 167
6.1 Introduction 167
6.2 Ammonia Dry Cooling System 167
6.2.1 System Description and Principle of
Operation 167
6.2.2 Advantages and Disadvantages of the
Ammonia Dry Cooling System 168
6.2.3 Current Development Status of the
Ammonia Concept 169
6.3 Curtiss-Wright Dry Cooling System 169
6.3.1 Description of Curtiss-Wright
Integral-Fin Tubes 170
6.3.2 Development Status of the Curtiss-
Wright Dry Tower System 170
6.4 Fluidized Bed Dry Cooling Systems 170
6.4.1 General Description 170
6.4.2 Development Status 171
6.5 Rotary (Periodic) Heat Exchanger Dry
Cooling System 171
6.5.1 System Description and Principle of
Operation 171
6.5.2 Advantages and Disadvantages of
Periodic Cooling Tower Concept 172
6.5.3 Development Status 172
6-6 Plastic Tube Dry Cooling System 172
6.6.1 General Description 172
6.6.2 Development Status '.'.'.'.. 173
6. 7 Deluge Wet/Dry Cooling System | \ . 173
6.7.1 General Description 173
6.7.2 Development Status 174
Vlll
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6.8 MIT Wet/Dry Tower System . 174
6.8.1 General Description 174
6.8.2 Development Status 175
References 185
7. An Overview of Closed-Cycle Cooling Water
Treatment 187
7 .1 Introduction 187
7.2 Relationships Between Cycles of Concentra-
tion and the Flow Rates of Make-Up and
Slowdown 188
7.3 Problems Associated with Cooling Water
Systems 189
7.3.1 Scaling 189
7.3.2 Fouling 190
7.3.3 Corrosion 191
7.3.4 Deterioration of Wood and Asbestos
Cement Components 193
7.3.5 Scaling and Corrosion Indices 193
7.4 Circulating Water Quality Limitations 195
7.5 Restriction on Slowdown 196
References 210
8. Cooling Water Treatment Processes 213
8.1 Introduction 213
8. 2 Removal of Suspended Solids 213
8.2.1 Screening 213
8.2.2 Sedimentation 214
8.2.3 Filtration 215
8.2.4 Coagulation - 216
8.3 Removal of Hardness 216
8.3.1 Cold Lime-Soda Process 217
8.3.2 Hot Lime-Soda Process 217
8.3.3 Warm Lime-Soda Process 218
8.3.4 Ion Exchange.... 218
8.4 Use of Chemical Additives 218
8.4.1 pH Control 218
8.4.2 Corrosion Inhibitors 219
8.4.3 Scaling Inhibitors 220
8.4.4 Biological Fouling Control 220
8.4.5 Protection Against Deterioration of
Cooling Tower Components 223
8.5 Mechanical Methods for Fouling Control , 223
8.6 Sludge Processing 224
8.6.1 Thickening 224
8.6.2 Dewa tering 225
References 236
9. Methods of Closed-Cycle Cooling Water Treatment. . 237
9.1 Current Treatment Technology 237
9.1.1 Survey of Current Practice 237
9.1.2 Current Treatment Objectives 238
9.1.3 Definition of Current Technology 238
IX
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9.2 Near Horizon Treatment Technology 239
9.2.1 Make-Up Treatment
9.2.2 Circulating Water Treatment
9.2.2.1 Warm Lime-Soda Process
9.2.2.2 Sidestream Filtration 243
9.2.3 Slowdown Treatment 243
9.2.4 Costs of Near Horizon Technology 244
9.3 Specialized Cases of Make-Up Water 245
9.3.1 Use of Brackish or Saline Water 245
9.3.2 Use of Sewage Effluent - 246
References 261
10. Future Technologies for Closed-Cycle Cooling
Water Treatment 263
10.1 Introduction 263
10. 2 Treatment of Make-Up Water 263
10.2.1 Ion Exchange Softening 263
10.2.2 Ion Exchange Demineralization 264
10.3 Treatment of Circulating Water 265
10.3.1 Membrane Processes 265
10.3.2 Lime-Barium Softening 266
10.3.3 Use of Ozone to Control Biological
Fouling 267
10.4 Treatment of Slowdown Water 267
References 270
11. Environmental Impacts of Closed-Cycle Cooling
Systems 271
11.1 Background 271
11.1.1 Overview 271
11.1.2 Hydrological and Aquatic Impacts 271
11.1.3 Atmospheric and Terrestrial Impacts.. 272
11.1.4 Land Use Aesthetics and Noise
Impacts 272
11.2 Impact of Intakes 273
11.2.1 Introduction 273
11.2.2 Reduction of Impact Through Location 274
11.2.2.1 Freshwater Intakes 274
11.2.2.2 Small Freshwater Lakes and
Reservoirs 275
11.2.2.3 Estuaries 275
11.2.2.4 Oceans and Lakes 275
11.2.3 Reduction of Impact Through Design... 276
11.2.3.1 Velocity Consideration 276
11.2.3.2 Selection of Screen Mesh
Size 276
11.2.4 Conventional Intake System Designs... 276
11.2.4.1 Intake Arrangement 277
11.2.4.2 Screen Placement .* 278
11.2.4.3 Velocities Across the
Screens 278
11.2.5 Alternate Intake Designs 278
x
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11.2.5.1 Inclined Screens 278
11.2.5.2 Filter Type Intake 279
11.2.5.3 Fixed Screens 279
11.2.5.4 Perforated Pipe, Wedge Wire
Screens 280
11.2.5.5 Behavioral Screening
Systems 281
11.2.5.6 Fish Handling and Bypass
Facilities 282
11.2.6 Summary and Conclusions 283
11.3 Consumptive Water Use of Alternate Cooling
Systems 283
11.3.1 General Description 283
11.3.2 Methods for Calculating Evaporative
Losses 285
11.3.2.1 Evaporative Loss From
Cooling Towers 285
11.3.2.2 Evaporative Loss From
Cooling Ponds (Forced
Evaporation) 286
11.3.3 Evaporation Rates 290
11.3.4 Current and Projected Consumptive
Water Use 290
11.4 Impacts of Slowdown 290
11.4.1 Introduction 290
11.4.2 Impacts and Biological Control
Factors of Blowdown 291
11.4.2.1 pH and Sulfate Levels 291
11.4.2.2 Toxicity Level 292
11.4.2.3 Nutrient Levels 293
11.4.2.4 Thermal Shock 293
11.5 Atmospheric and Terrestrial Impacts 294
11.5.1 Introduction 294
11.5.2 Factors Affecting Drift Deposition
and Its Impact 294
11.5.2.1 Salt Deposition Impacts 295
11.5.2.2 Drift Emission Rate
Measurement 297
11.5.2.3 Particle Size and Mass
Distribution 297
11.5.2.4 Effects of Meteorological
Conditions 298
11.5.3 Control of Drift 298
11.5.3.1 Engineering Controls 298
11.5.3.2 Physical Controls 299
11.5.4 Impacts of Fogging and Icing 299
11.5.4.1 Fogging and Icing 299
11.5.4.2 Engineering Controls 300
11.5.4.3 Physical Controls 300
11.5.5 Effects on Weather Modification 301
XI
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11.5.6 Cooling Tower and Stack Plume
Interaction
11.6 Land Use, Aesthetics, and Noise Impacts 302
11.6.1 Land Use - Introduction 302
11.6.1.1 Environmental Land Impacts
of Cooling Ponds 303
11.6.1.2 Environmental Land Impacts
of Spray Ponds 303
11.6.1.3 Environmental Land Impacts
of Cooling Towers 304
11.6.2 Aesthetic Impacts 304
11.6.3 Noise Impacts 306
11.6.3.1 Noise Impact Measurement.... 307
11.6.3.2 Control Measures 308
J1.7 Licensing and Permits 308
11.7.1 Introduction 308
11.7.2 Consumptive Water Use Permits 309
11.7.3 Discharge and Navigational Permits... 310
11.7.3.1 Federal Requirements 310
11.7.3.2 State and Local Permits 313
11. 8 Benefit-Cost Analysis 313
11.8.1 Introduction 313
11.8.2 Benefit-Cost Analysis Methods 314
References 355
XII
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TABLES
Number Page
4.1 Power Plants over 100 MWe Using Dry Cooling
System 82
4.2 Costs of Typical Conventional Cooling Systems
for Fossil Power Plants (1978 Dollars) 83
4.3 Costs of Typical Conventional Cooling Systems
for Nuclear Power Plants (1978 Dollars) 84
4.4 Economic Factors 85
4.5 Design Condition and Size of Typical Convention-
al Cooling Systems for a 1000-MWe Fossil
Power Plant 86
4.6 Design Condition and Size of Typical Convention-
al Cooling Systems for 1000-MWe LWR Power
Plant 88
4.7 List of Major Equipment 90
4.8 Capital Cost Elements of Typical Conventional
Cooling Systems for a 1000-MWe Fossil Plant
($106, 1973 Dollars) 93
4.9 Capital Cost Elements of Typical Conventional
Cooling Systems for a 1000-MWe LWR Power
Plant ($106, 1973 Dollars) 95
4.10 Plant Performance Data of a 1000-MWe Fossil
Plant Using Conventional Cooling Systems
Site: Middletown, U.S.A. (Boston, MA
Meteorology) 97
4.11 Plant Performance data of a 1000-MWe Nuclear
Plant Using Conventional Cooling Systems
Site: Middletown, U.S.A. (Boston, MA
Meteorology) 98
5.1 Typical Size, Performance and Costs of Hybrid
Wet/Dry Tower Systems for Plume Abatement 146
Xlll
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Number
5.2
5.3
5.4
5.5
7.1
7.2
7.3
7.4
8.1
8.2
8.3
8.4
9.1
9.2
9.3
9.4
Design Data of Typical Wet/Dry Cooling Tower
Systems for a Fossil Plant •
Cost Components ($106) of Typical Wet/Dry
Cooling Systems for a Fossil Plant
Design Data of Typical Wet/Dry Tower Systems
for a Nuclear Power Plant
Cost Components ($106) of Typical Wet/Dry
Cooling Systems for a 1000-MWe Nuclear Plant...
Typical Analysis of Scales from Power Plant
Condenser Systems
Maximum and Minimum Values of Selected Water
Quality Parameters for 98 Rivers
Types of Biological Growth Affecting Operation
of Recirculating Cooling Water Systems
Control Limits for Cooling Tower Circulating
Water Composition
List of Chemicals Associated with Nuclear
Power Plants
Common Chemical Additives for Corrosion and
Scaling Control in Recirculating Cooling
Water Systems
Partial Listing of Commercially Available
Formulations for Microorganism Control
Wood Preservatives Used for Pretreatment of
Wood in Cooling Tower Installations
Type of Water Treatment According to EPA
Region and Treatment Category
Recirculating System Plants by Cycles of Concen-
tration Range and Type of Blowdown Treatment . . .
Analysis of Hypothetical Ohio River Water
Analysis of Hypothetical Lake Erie Water
Page
-i « 1-1
147
148
149
150
TOO
198
199
200
202
227
231
232
235
249
250
251
251
XIV
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Number
9.5 Effect of Near Horizon Technology on Cycles
of Concentration for Hypothetical Ohio River
Water 252
9.6 Effect of Near Horizon Technology on Cycles
of Concentration for Hypothetical Lake Erie
Water 253
9.7 Analysis of Irrigation Wastewater for the Pro-
posed Sundesert Nuclear Plant 254
9.8 Analysis of Water Streams for the Proposed
Sundesert Nuclear Plant 254
9.9 Comparison of Treatment Costs for Selected
Examples 255
9.10 Estimated Chemical Consumption for Alternative
Treatment Technologies for Selected Examples... 257
9.11 Analyses of Make-up Water Qualities 259
9.12 Typical Wastewater and Treatment Plant Analyses.. 260
11.1 Projected Consumptive Water Use, MGD 316
11.2 Estimated Fog Frequencies for Natural Draft
and Hybrid Cooling Towers 317
11.3 Approximate Land Required by Various Cooling
Systems 318
11.4 Relative Area Requirements for Alternate Cooling
Tower Systems (800-MWe Fossil Power Plant) 319
11.5 Land Requirements for Dry Cooling Towers for
Representative 1000-^MWe Power Plants 320
11.6 Guidance List of Documents Available From the
Federal Government for Filing Permits Related
to Closed-Cycle Cooling Systems 321
11.7 States That Have NPDES Granting Authority (As of
31 December 1977) 326
11.8 Environmental Factors to be Used in Comparing
Alternative Plant Systems 330
xv
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FIGURES
Number Page
2.la Power Generation and Waste Heat Rejection -
Pressurized Water Reactor (PWR) with Evapo-
rative Cooling Tower 12
2. Ib Boiling Water Reactor 13
2.1c Fossil Fuel-Fired Boiler 13
2.2 Temperature-Entropy Diagram of the Rankine Cycle. 14
2.3 Typical Fossil Power Plant Cycle Diagram (Single
Reheat, 8-Stage Regenerative Feedwater Heating) 15
2.4 Steam Cycle for Fossil Fuel—Temperature-Entropy
Diagram—Single Reheat, 8-Stage Regenerative
Feed Heating—3515 psia, 1000F/1000F Steam 16
2.5 Typical Nuclear Power Plant Cycle Diagram 17
2.6 Typical Heat Rate Correction Curve for a Fossil
Plant with a Conventional Turbine 18
2.7 Typical Heat Rate Correction Curve for a Nuclear
Plant with a Conventional Turbine 19
3.1 Relative Performance of a Dry Cooled Plant
Utilizing a High Back Pressure Turbine Under
the Fixed Demand/Scalable Steam Source/
Scalable Plant Approach 31
3.2 Relative Performance of a Dry Cooled Plant
Utilizing a High Back Pressure Turbine Under
the Fixed Demand/Scalable Steam Source/
Scalable Plant Approach with Maximum Required
Scaling 32
3.3 Relative Performance of a Dry Cooled Plant
Utilizing a High Back Pressure Turbine Under
the Negotiable Demand/Fixed Heat Source
Approach with Maximum Required Derating 33
xvi i
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, Page
Number —^—
3.4
3.5
3.6
4.1
4.2
4.3
4.4
4.5
4.6a
4.6b
4.7
4.8
4.9
4.10
4.11
4.12
4.13
Ambient Temperature Duration and Corresponding
Plant Performance for Fixed Demand/Fixed Heat
Source Approach
Relative Performance of Differnt Size Cooling
Systems
Schematic Diagram of Economic Trade-Offs and
Optimum Selection of Cooling Systems
Typical Mechanical Draft Wet Cooling Towers
Typical Natural Draft Wet Cooling Towers
Typical Fan-Assisted Natural Draft Wet Cooling
Towers
Representation of the Wet Bulb Temperature,
Range, Approach, Operating Line, and Driving
Force on an Enthalpy-Temperature Diagram
for a Fresh Water Tower
Cooling Tower Nomenclature
Effect of Varying Range on Tower Size
Effect of Varying Approach on Tower Size
Typical Performance Curves of a Wet Cooling
Tower
Trend in Tower Size for Natural Draft Wet
Cooling Towers
Fan Power Requirements for Fan-Assisted
Natural Draft Cooling Tower
Typical Packing Configurations for Wet Cooling
Towers
Typical Drift Eliminators for Wet Cooling
Towers
Mechanisms of Heat Transfer Across a Water
Surface
Cholla Site Development Plan. . . .
34
35
36
99
100
100
101
102
103
103
104
105
106
107
108
109
110
XV11J.
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Number Page
4.14 Design Surface Heat Exchange Coefficient
for Cooling Ponds Ill
4.15 Typical Power Spray Canal System with Power
Spray Module Details 112
4.16 Ntu Determined from Tests on a Single Spray
Module 113
4.17 Possible Spray Cooling System Configuration 114
4.18 Control Volume for Sizing Spray Canal Systems... 114
4.19 Design Curves for Sizing Spray Canal Systems.... 115
4.20 Typical Pump-Motor-Float Assembly for Spray
Modules 116
4 . 21 Types of Fin-Tube Construction 117
4.22 Direct, Dry Cooling Tower Condensing System
with Mechanical Draft Tower 118
4.23 Condenser Elements for Direct Dry Cooling
System 119
4.24 Wyodak Air Cooled Condenser Arrangement 120
4.25 Indirect, Dry Cooling Tower System with
Direct Contact (Spray) Condenser (Heller
System) 121
4.26 Typical Spray Condenser 122
4.27 Indirect, Dry Cooling Tower System with Surface
Condenser 123
4.28 Temperature Diagram of Indirect Dry Tower 124
4.29 Schematic Tower Designs with Horizontal and
Vertical Tube Layouts 125
4.30 Size Comparison Between High Back Pressure
and Conventional Turbine of Approximately
Equal Power Rating 125
5.1 Schematic of Hybrid Wet/Dry Tower for Plume
Abatement with Film-Type Dry Section 151
xxx
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, Page
Number —-—
5.2 Conventional Mechanical Draft Wet Cooling
Tower
5.3 Psychrometric Process for a Mechanical Draft
Wet Cooling Tower
5.4 Wet/Dry Mechanical Draft Cooling Tower 153
5.5 Psychrometric Process for a Mechanical Draft
Wet/Dry Cooling Tower -15-3
5.6 Total Evaluated Cost as a Function of Ground
Fogging for Various Wet and Wet/Dry Tower
Systems (Seattle Site, 1985 Dollars) 154
5.7 Series Water Flow Wet/Dry Tower System for
Water Conservation 155
5.8 Parallel Water Flow Wet/Dry Tower System for
Water Conservation 156
5. 9 Wet/Dry Tower-Mode 1 Operation 157
5.10 Wet/Dry Tower-Mode 2 Operation 157
5.11 Performance Curves for a 10% Wet/Dry Cooling
System at Middletown Site 158
5.12 Plant Performance Characteristics (Gross Out-
put) using Wet/Dry Cooling Systems 159
5.13 Plant Performance Characteristics (Net Out-
put) using Wet/Dry Cooling Systems 160
5.14 Total Monthly Make-Up Requirements of Wet/Dry
Cooling Systems for Water Conservation:
1000-MWe Nuclear Plant at San Juan, New
Mexico 161
5.15 Maximum Monthly Make-Dp Requirements of Wet/Dry
Cooling Systems for Water Conservation:
1000-MWe Nuclear Plant at San Juan, New
Mexico 162
5.16 Total Monthly Make-Up Requirements of Wet/Dry
Cooling Systems for Water Conservation:
1000-MWe Fossil Plant at San Juan, New
Mexico 163
XX
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Number
Page
5.17 Maximum Monthly Make-Up Requirements of Wet/Dry
Cooling Systems for Water Conservation:
1000-MWe Fossil Plant at San Juan, New
Mexico 164
6.1 Process Flow Diagram for a Proposed Ammonia
Dry Tower System 176
6.2 Typical Curtiss-Wright Integral-Fin Multi-port
Tube 177
6.3 Fluidized Bed Dry Tower 178
6.4 Periodic Dry Cooling Tower Schematic 179
6.5 Cross Section of a Dry Cooling Tower Using
Periodic Cooling Elements 179
6-6 Proposed Design of Low Profile Natural Draft
Dry Tower Using Plastic Tubes for a 1100-MWe
Nuclear Power Plant 180
6.7 Plate-Fin Deluge Detail 181
6.8 Plate-Fin Deluge Tower Arrangement 182
6.9 Conceptual Design of the New Wet/Dry Surface.... 183
6.10 Schematic Diagram of the MIT Advanced Wet/Dry
Tower Packing Arrangement 184
7.1 Locations for Potential Water Treatment in a
Wet Tower System 203
7.2 Mass Balance for an Evaporative Cooling Tower... 204
7.3 Ratio of Make-Up or Slowdown Rate to Evaporation
Rate Versus Cycles of Concentration 205
7.4 Solubilities of Selected Scale Deposits 206
7.5 Corrosion Reaction Schematic 207
7.6 Nomograph for Determination of Langelier or
Ryznar Index 208
11.1 Conventional Vertical Traveling Screen 342
xxi
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Number Page
11.2 Modification of Conventional Traveling Screens
to Protect Impinged Fish 343
11.3 Screen Settings 344
11.4 Pier Design Consideration 345
11.5 Inclined Plane Screen with Fish Protection 346
11.6 Perforated Pipe Make-Up Water Intake Detail 347
11.7 Johnson Welded (Wedge-Wire) Well Screen 348
11.8 Operation of a Velocity Cap 349
11.9 Cooling Tower Evaporation Rate 350
11.10 Estimating the Increase in Reservoir Evaporation
Resulting from the Addition of Heat by a
Power Plant 351
11.11 Cumulative Mass Distribution of Drift Droplets
for Natural Draft Cooling Towers 352
11.12 Cumulative Mass Distribution of Drift Droplets
for Mechanical Draft Cooling Towers 353
11.13 Nominal Settling Rate of Water Droplets in Air.. 354
XX1J.
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ACKNOWLEDGMENT
A State of the Art Manual on Thermal Pollution Control and
Treatment of Cooling Waters in the Steam Electric Power Generat-
ing Industry was completed under the direction of T. G. Brna,
Project Officer of the U. S. Environmental Protection Agency,
and D. C. Senges, Vice President of Mackell, Inc. Funding for
this project was provided by the Industrial Environmental Re-
search Laboratory, Research Triangle Park, North Carolina
under a small business set aside, Contract No. 62-02-2637.
The principal contributors and authors of this manual were
G. A. Englesson, M. C. Hu and C. Murawczyk of Engineers for
Energy and the Environment, Box 317, Huntingdon Valley, Pa.
19006.
XXlll
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SECTION 1
INTRODUCTION
1.1 PURPOSE
The purpose of this manual is to provide a user-oriented
practical handbook on closed-cycle cooling systems for fossil-
and nuclear-fueled steam electric generating stations. This
document has been written for engineers, technical managers, and
state and federal regulatory staffs who must deal with all as-
pects of power plant cooling systems. The manual is intended to
provide a broad understanding on the subject, not to serve as a
design or technical specification manual. It includes fundamen-
tal, technical, and practical information, which reflects the
progress and experiences gained in utilizing closed-cycle cool-
ing systems in the steam-electric industry.
The manual can be characterized as providing an assessment
of current, near horizon, and future technologies. Current
technologies include those technologies in extensive use in the
electric power industry. Near horizon technologies are those
which are in wide use in other industrial areas or which may have
already had limited use in the steam electric industry. Future
technologies are defined as those technologies which have not yet
been deployed extensively in any industry or those which have had
limited industrial use.
This manual is organized into several basic parts for ease
of reference. A description of the design and operation of cur-
rent, near horizon, and advanced closed-cycle cooling systems,
including the capital and operating costs, are presented in Sec-
tions 2 through 6. Current, near horizon, and future methods
available for water treatment of make-up, circulating, and blow-
down waters are presented in Sections 7 though 10. The environ-
mental impacts of the closed-cycle cooling systems, the consump-
tive water use, the permits required to build and operate these
systems, and a discussion of the environmental cost-benefit
analysis are presented in Section 11. References are included in
each of the sections.
1.2 CLOSED-CYCLE COOLING SYSTEMS
The current state-of-the-art in closed-cycle condenser cool-
-------
ing includes mechanical draft, natural draft, fan-assisted nat-
ural draft wet and dry cooling towers, cooling ponds and lakes,
and spray ponds. These cooling systems are currently being pro-
posed for most new power plant construction except those plants
proposed for ocean or Great Lakes sites.
The manual provides sufficient information on each of these
heat rejection systems to allow an understanding of those major
parameters which are important to the design and operation of
each system. In addition, information is provided on several
methods used for the economic evaluation of closed-cycle cooling
systems and capital and operating costs for all of the convention-
al cooling systems using one of the methods of evaluation.
Closed-cycle cooling systems have unique environmental/
economic impacts associated with them; e.g., the vapor plume of
low profile cooling towers may reduce visibility or cause icing
on roads and bridges, while evaporative heat rejection may
deplete the available water in rivers and streams during low
water periods. In order to minimize these impacts, the cooling
tower industry and government agencies have developed and
evaluated a number of new systems, which can potentially mini-
mize these effects.
Two of these newly developed systems, wet/dry cooling for
plume abatement and wet/dry cooling for water conservation, have
been offered by cooling tower manufacturers and have been pur-
chased for use in the late 1970- early 1980 time frame. Since
there is no current industrial experience for these two systems,
they have been designated as near horizon technology in this
manual. Economic costs and design descriptions of these systems
as described in several published studies have been included.
Those systems which have not yet been offered by industry
but have undergone evaluation and/or development by the Federal
Government have been designated as future technology. A descrip-
tion of each system and its development status are included.
1.3 WATER TREATMENT FOR CLOSED-CYCLE COOLING
The current state-of-the-art for closed-cycle water treat-
ment has been limited primarily to acid or base addition for pH
£h?«rh 3K chlorin^ion for controlling biological fouling.
This has been possible because of the low number of cycles of
* 1 thS SS
oTcoSufT/* S1^ thS SYStemS Were Derated and the absence
of cooling water blowdown regulations. As the use of closed-
strln5"5^5 ^ the 6leCtric utilit? i^ustry ^crease's
w^f T .llmitati°ns on blowdown are defined, more ex-
water treatment will be commonly applied.
-------
The manual provides a description of the problems that occur
with closed-cycle cooling operation which will require water
treatment and the water treatment methods currently used in in-
dustry to alleviate these problems.
Those water treatment methods which are currently applied
in other segments of the industrial community have been designat-
ed near horizon technology for the purpose of this manual. De-
scriptions of examples of the application of these water treat-
ment methods on different types of cooling waters, the costs of
these treatment methods, and the resulting water quality have
also been provided.
Future technologies are those water treatment technologies
which are currently used in applications to provide good water
quality in relatively small quantities. Although these techno-
logies can have application in the power industry, in most cases,
the large volume of water which must be processed makes these
technologies economically not feasible.
1.4 ENVIRONMENTAL IMPACTS OF CLOSED-CYCLE COOLING SYSTEMS
The widespread application of closed-cycle cooling in the
expanding electric industry will provide new potentially adverse
environmental impacts, while minimizing the thermal impacts on
the aquatic systems. The environmental impacts of closed-cycle
cooling systems can be divided into three broad categories.
These are: hydrological and aquatic impacts, atmospheric and
terrestrial impacts, and land use, aesthetics and noise impacts.
Hydrological and aquatic impacts are those effects caused
by the make-up water intake structure itself, effects due to the
water consumption, and effects created by the cooling tower blow-
down. Atmospheric and terrestrial impacts are those effects
caused by the discharge of large quantities of warm, humid air
into the atmosphere, as well as effects on biota due to the en-
trained impurities in the discharged vapor. Land use, aesthetics,
and noise impacts are those effects related to the quantity and
utilization of land required by the various closed-cycle cooling
systems, their visual impacts and noise generated by the various
systems on the environment as a whole. Each of these impacts
is discussed and the available methods of prediction and minimi-
zation are provided.
A brief description of the important permits required to
initiate construction and operation of closed-cycle cooling
systems is provided, as well as an integrated method of display
of the costs and benefits of alternative cooling systems.
-------
SECTION 2
HEAT REJECTION AND POWER PRODUCTION
FROM STEAM ELECTRIC POWER PLANTS
2.1 BASIC POWER PLANT AND COOLING SYSTEM COMPONENTS
2.1.1 Power Plant Components(1-4) *
The basic components of steam-electric power plants using
either fossil or nuclear fuel are shown in Figures 2.la, b, and
c. The components to the right of Section A-A in Figure 2.la are
common to all steam-electric power plants. The components to the
left of A-A belong to the steam generation system which provides
the major distinction between the fossil- and nuclear-fueled
plants.
The operation of the steam cycle of a steam-electric power
plant is basically as follows: steam at high temperature and
pressure enters a turbine where energy in the form of shaft work
is removed; the turbine shaft is coupled to a generator which
produces electricity; the exhaust steam from the turbine enters
a condenser where it is converted to a liquid phase (condensate)
by continual removal of latent heat in the exhaust steam; the
waste heat; the condensate then returns to the steam generator
to complete the cycle.
2.1.1.1 Light Water Reactor (LWR) Power Plant—
A light water reactor plant may be either a pressurized
water reactor (PWR) or a boiling water reactor (BWR) power plant.
The components shown to the left of Section A-A in Figure 2.la
represent a power plant with a pressurized water reactor. Heat
from the reactor is transferred to a steam generator by means of
water in a closed circuit system under a pressure of about 2300
psig. Steam leaves the steam generator at a pressure of about
1000 psig. Figure 2.Ib shows the components to the left of
Section A-A (Figure 2.la) in a boiling water reactor. In a BWR
plant, steam is generated directly in the reactor vessel. Both
water and steam are at a pressure of about 1000 psig. In either
the PWR or BWR reactor vessel, the maximum steam or circulating
water temperature is about 600°F. This temperature is governed
by the heat transfer characteristics at the surface of the
*Indicates references at the end of each section.
-------
uranium dioxide fuel rods to limit the maximum temperature of the
fuel. This temperature limitation is responsible for the rela-
tively low thermal efficiencies of the present day nuclear power
plants.
2.1.1.2 Fossil Power Plants—
Figure 2.Ic shows the components to the left of Section A-A
in Figure 2.la for a fossil-fueled steam-electric power plant.
In terms of components, it is similar to those of a BWR plant,
except that steam is produced in a boiler by the burning of coal,
gas or oil. Current large fossil plants are designed with a
steam pressure of 2400 psig to 3500 psig and superheat and re-
heat steam temperatures of approximately 1000°F and 1000°F, re-
spectively.
2.1.2 Cooling System Components(5-7)
The cooling system which rejects the power plant waste heat
is shown to the right of Section B-B in Figure 2.la. A cooling
system is termed "once-through" (open-cycle) when the cooling
water flow is circulated only once through the system, and waste
heat is discharged into natural bodies of water, such as rivers,
lakes or coastal waters. A cooling system is termed "closed-
cycle" when the cooling water is recirculated, and waste heat is
rejected to the atmosphere by such "terminal heat sink devices"
as evaporative cooling towers, cooling ponds, spray ponds, and
dry cooling towers. In certain cases a cooling pond or wet cool-
ing tower is combined with a once-through system to discharge to
the atmosphere a portion of the total waste heat through the de-
vice before the rest is discharged to a natural body of water.
This type of open-cycle cooling system is sometimes called a
"topping" or "helper" system.
This manual discusses the closed-cycle cooling systems for
both fossil and light water reactor power plants. The major com-
ponents of a closed-cycle coolxng system (shown to the right of
Section B-B in Figure 2.la) include the condenser, thl circulat-
ing water pump, piping and associated equipment, and the terminal
heat sink device, e.g., cooling tower or cooling ™* »term^nai
system may also include: 1) a make-uo wa?er svItSS A • £ c°o1"*
make-up water to replace the loss of circuit?7 \ 1Ch 5uPPlieS
evaporation, drift, blowdown, and leakage 1?ThV*^ thr°Ugh
ment and disposal system, and 3) a water tJL™ bi°wdown treat-
treats the make-up and circulating water to Srevf ^System which
scaling, corrosion, and fouling. prevent or minimize
2.2 POWER PLANT CYCLE AND THERMAL EFFICIENCY (1 2)
The Rankine cycle of the steam-electric n
Figure 2.1 is illustrated in the temperature Yer Plant shown in
Figure 2.2. Liquid water is compressed isentrn -°PY dia9ram of
a to b in the feedwater pump. From b to c h~°Plcally from
' neat is added
-------
reversibly in the compressed liquid, two-phase, and superheated
states of water in the steam generator and superheater. Isentro-
pic expansion of steam through the turbine with shaft work out-
put takes place from c to d. Condensation of the spent steam
takes place from d to a with the rejection of waste heat to the
atmospheric heat sink.
The thermal efficiency of the cycle is defined as the ratio
of the net work output to heat input of the cycle. The theoreti-
cal maximum efficiency of all ideal heat cycles operating between
given temperature limits, including the (ideal) Rankine cycle, is
the Carnot efficiency. The Carnot efficiency is determined by
the temperature of the heat sources and the temperature of the
surroundings which serve as a heat sink and is given by:
max
Tc
•source J
where the temperatures are measured on an absolute scale.
Equation (2.1) indicates that there are three choices for im-
proving the ideal cycle efficiency; that is, decreasing
increasing Tsource or varying both to reduce the ratio,
Tsource- Modern steam electric power plants utilize improved
variations of the basic Rankine cycle which effectively increase
the heat source temperature and the cycle efficiency. In this
section, a brief description will be given for the modern fossil
and nuclear steam cycles and the associated thermal efficiencies.
The effect of heat sink temperature as determined by the cooling
system performance will be discussed in Section 2.3.
2.2.1 Steam Cycle for Fossil and Light Water Reactor Power
Plants
One improvement to the Rankine cycle is the adoption of
regenerative feedwater heating. It is done by extracting steam
at various stages in the turbine to heat the feedwater as it is
pumped from the condenser hotwell to the boiler. Regenerative
heating not only improves cycle efficiency, but has other ad-
vantages; among them are lower volume of steam flow in the final
turbine stages and a convenient means of deaerating the feed-
water.
Where maximum temperatures are limited by physical or eco-
nomic means, reheating of steam after its partial expansion in
the turbine can be used as an effective means of raising the
average temperature of the heat source and, thus, the thermal
efficiency of the cycle. Reheat also reduces the moisture of
the steam in the low pressure turbine stages. Reduction of
-------
moisture improves the expansion efficiency and provides an ef-
fective means to control blade and nozzle erosion.
Figure 2.3 shows the cycle diagram of a typical fossil
power plant, illustrating schematically the arrangement of vari-
ous components, including the steam reheater and feedwater heat-
ers. As shown in Figure 2.3, steam is reheated after expansion
through the high pressure turbine. The temperature-entropy dia-
gram for the cycle shown in Figure 2.3 is given in Figure 2.4 for
a supercritical throttle steam condition of 3515 psia and 1000F
and a reheat steam condition of 540 psia and 100OF. This figure
illustrates how the principle of regenerative feedwater heating
and steam reheat increases the mean temperature level for heat
addition. Consequently, the maximum cycle thermal efficiency is
increased (See Equation (2.1))
Figure 2.5 illustrates a Rankine cycle whose thermal energy
source is a light water reactor system. Pressure and tempera-
ture limitations required for a nuclear reactor mean that the
steam leaving the steam generator is either saturated or slight-
ly supersaturated and that expansion through the power cycle
is largely in the region of wet steam. Three different methods
are generally utilized for moisture removal, which both improve
the thermal efficiency and minimize blade erosion. After expan-
sion in the high pressure turbine, the steam passes through an
external moisture separator. After passing through the external
moisture separator, the steam is then reheated, increasing its
temperature and reducing its moisture content. Current plant
designs also include mechanical moisture separation in the low
pressure turbine blades. These separations utilize grooves on
the back of the turbine blades to drain the collected moisture.
2.2.2 Thermal Efficiency and Waste Heat Rejection
2.2.2.1 Thermal Efficiency—
As indicated earlier, the performance of a steam cycle
plant can be expressed in terms of cycle thermal efficiency,^,
or cycle heat rate, HR. The thermal efficiency is expressed
as a dimensionless parameter, while the heat rate is expressed
as a dimensioned parameter.
1) Cycle thermal efficiency, 7f :
# = Net power output from the steam cycle ,7 -»
Heat input to the steam cycle
2) Cycle heat rate, HR:
HR = —Jjeat^input to cycle in Btu/hr 1,4-,,/**,>, /0 ,.
Net poorer output from cycle in kw' Btu/Kwh <2-3)
-------
The cycle thermal efficiency, expressed as a fraction, and the
heat rate are related by the following equation:
where the numerator is the conversion factor from Btu/hr to kW.
In engineering practice, several other thermal efficiency
terms and corresponding heat rate terms have been used in power
plant applications. These are: 1) gross plant efficiency and
gross plant heat rate, 2) net plant efficiency and net plant
heat rate, and 3) net station efficiency and net station heat
rate. The definitions of these efficiency terms are as follows
1) Gross plant efficiency, 7?- :
77 = Turbine-generator output ,2 5,
'3 Heat input to the steam cycle
The turbine-generator output is the electric output at the gen-
erator, and it is equal to the turbine output less the loss in
the generator.
2) Net plant efficiency,
•ft _ Electric output at bus bar ,~ g
r Heat input to the steam cycle
The electric output at bus bar is equal to turbine-generator
output less the sum of the plant auxiliary power requirements,
e.g., pumps and fans, air conditioners, lights, etc.
3 ) Net station efficiency,
- Electric output at bus bar /2 -j\
~ Heat input to station
For nuclear power plants, the heat input to the station is
theoretically equal to the heat input to the cycle, neglecting
the heat losses in the primary reactor coolant circuit. For
fossil plants, the heat input to the station is equal to the sum
of the heat loss through the smoke stack and the heat input to
the steam cycle. Therefore, for nuclear plants, the net plant
efficiency and the net station efficiency are equal? for fossil
plants, the net station efficiency is equal to the net plant
efficiency times a boiler efficiency,^ , defined as:
-------
7) - Heat input to the steam cycle (2.8)
'£ ~ Heat input to the boiler
2.2.2.2 Waste Heat Rejection Rate—
The heat rejection rate of a power plant to its condenser
cooling system can be calculated by the following equation,
given the cycle heat rate and net cycle power output:
Qrej = (HR - 3413) x P x 1000 (2.9)
where:
Qrej = heat rejection rate to the condenser
cooling system, Btu/hr.
HR = cycle heat rate, Btu/kWh.
P = net cycle power output, MW.
The above equation is derived from the energy equation for the
steam cycle and the definitions of cycle thermal efficiency,
heat rate, and power.
It has been common practice, however, to use the turbine-
generator output and the corresponding heat rate to calculate
the heat rejection for sizing a cooling system. This practice
gives a more conservative estimate of the heat rejection rate.
2.3 EFFECT OF COOLING SYSTEM PERFORMANCE ON POWER PLANT
PERFORMANCE
The cooling system used with a steam electric power plant
determines the lowest or the heat sink temperature in the thermo-
dynamic cycle of the power plant. Ideally, this temperature is
the steam condensing temperature. Since the cycle thermal ef-
ficiency increases as the heat sink temperature decreases (as-
suming all other conditions remain constant), it is desirable to
reject the waste heat at the lowest possible temperature. Thus,
a lower exhaust pressure means higher efficiency and more useful
work by the turbine.
The effect of the steam condensing temperature on the tur-
bine exhaust pressure and the plant efficiency is generally
presented in terms of steam turbine heat rate corrections ver-
sus turbine exhaust pressure curves or heat rate tables (8).
These heat rate corrections and the corresponding outputs are
different for different power plant cycles and specific power
plants, as well as different load conditions. The corrections
represent the change in heat rate relative to a fixed reference
neat rate, called base heat rate, at a particular exhaust
10
-------
pressure. Typical heat rate corrections for 1000-MWe fossil and
light water reactor power plants operated with conventional tur-
bines at valve wide-open conditions are shown in Figures 2.6 and
2.7, respectively.
It should be noted that for a fixed heat input to the power
cycle, the product of power output and its corresponding heat
rate at any exhaust pressure within the operational range is al-
ways equal to the product of the base output and the base heat
rate. This relationship allows the determination of plant out-
put at off-design conditions.
11
-------
STEAM
ELECTRICITY
TURBINEh=GENERATOR
J L
WASTE HEAT
COOLING WATER
STEAM
GENERATOR
CONDENSER
STEAM
COOLING TOWER
AIR FLOW
[SLOWDOWN WATER v
PUMP
FEEDWATER
E-UP WATER
PUMP
Figure 2.la. Power generation and waste heat rejection -
Pressurized Water Reactor (PWR) with evapo-
rative cooling tower.
-------
»• STEAM TO TURBINE
FEEDWATER
Figure 2.1b. Boiling water reactor,
STEAM DRUM
FUEL
*• STEAM TO TURBINE
STACK
FEEDWATER
RHHHHHHH HHHH H
A
Figure 2.Ic. Fossil fuel-fired boiler.
-------
LU
or
I
LU
CL
LU
ENTROPY-S
Figure 2.2.
Temperature-entropy dia-
gram of the ideal Rankine
cycle.
14
-------
Stack Loss Air In
Net Power Loss
Net Power
Net
Generator
& Mechanical
Loss
Figure 2.3
High Pressure Bleed Heaters (*f Low Pressure Bleed Heaters
^ Boiler Feed Pump
Typical fossil power plant cycle diagram
{single" reheat, 8-stage regenerative feed--
water heating)(1). Reprinted from Steam--
Its Generation and Use, 1972, with permis-
sion of Babcock & Wilcox Company.
-------
1000
fc 500
0.5 1.0 1.5 1.72
s (Entropy). Btu/lb,F (Based on High Pressure Steam Flow)
Figure 2.4.
Steam cycle for fossil fuel—tempera-
ture-entropy diagram--single reheat,
8-stage regenerative feed heating--
3515 psia, 1000F/1000F steam(l).
Reprinted from Steam—Its Generation
and Use, 1972 with permission of
Babcock & Wilcox Company.
16
-------
*»
J
External
Moisture
Separator
^
Auxiliary
Leu
Steam
Generator
Feed Pump
Tjrbine
(jj Demineralirer
FT/
Low Pressure Bleed Heaters
& Internal Moisture Separator Receivers
Figure 2.5.
Typical nuclear power plant cycle
diagram (1). Reprinted from Steam--
Its Generation and Use, 1972, with
permission of Babcock & Wilcox
Company.
-------
7.0 -r
oo
Base Plant Heat Rate = 7698 BtuAWh (8128
Base Plant Output = 1039 Mfe
Back Pressure (ran HgA)
2.5
f°
3.0
,
1
3.5
100
4.0
1 i
1
4.5
120
1 -
,
5.0
Back Pressure (in.HgA)
Figure 2.6. Typical heat rate correction curve for a fossil plant
with a conventional turbine(6,7).
-------
1.0
g 6.0
TO
&
g 5.0
Cj 4.0
s
I 3.0
•5 2.0
i
.§ 1.0
40
-1.0
Base Plant Heat Rate = 9900 Btu/kWh. (10438 KVJ<5ffli)
Base Plant Output = 1094 MWe
Back Pressure (mm HgA)
120 140
4.5 5.0 5.5
Back Pressure (in.HgA)
Figure 2.7. Typical heat rate correction curve for a nuclear plant
with a conventional turbine(5,7).
-------
REFERENCES
1. Babcock & Wilcox Company. Steam—Its Generation and Use,
38th Edition. New York, 1972.
2. Motoiu C. Thermal and Hydro Electric Stations. Editura
Didactica Si Pedagogica, Bucharest, Romania, 1974 (In
Romanian).
3. Ditmars, J. E. Heat Dissipation and Power Generation. _In:
Engineering Aspects of Heat Disposal from Power Generation,
Chapter 3, D. F. R. Harleman, et al., ed. Ralph M. Parson
Laboratory for Water Resources, Massachusetts Institute of
Technology, Cambridge, MA, 1972.
4. Boyack, E. E. and D. W. Kearney. Plume Behavior and Po-
tential Environmental Effects of Large Dry Cooling Towers.
Gulf General Atomic, San Diego, CA, Gulf-GA-A12346, 1973.
5. United Engineers & Constructors Inc. Heat Sink Design
and Cost Study. Philadelphia, PA, UE&C-AEC-740401, 1974.
(Available from National Technical Information Service,
Springfield, Virginia, WASH-1360).
6. Hu, M. C. Engineering and Economic Evaluation of Wet/Dry
Cooling Towers for Water Conservation. United Engineers &
Constructors Inc., Philadelphia, PA, UE&C-ERDA-761130, 1976,
(Available from National Technical Information Service,
Springfield, Virginia, COO-2442-1).
7. Hu, M. C. and G. A. Englesson. Wet/Dry Cooling Systems
for Fossil-Fueled Power Plants: Water Conservation and
Plume Abatement. United Engineers & Constructors Inc.,
Philadelphia, PA, UE&C-EPA-771130, 1977. (Available from
National Technical Information Service, Springfield
Virginia, EPA-600/7-77-137).
8. General Electric Company. Heat Rates for General Electric
Steam Turbine Generators. GET-2050B, Schenectady, New
York.
20
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SECTION 3
ECONOMIC EVALUATION OF ALTERNATE COOLING SYSTEMS
3.1 METHODS OF ECONOMIC EVALUATION
3.1.1 General Description
In order to assess alternate cooling systems on a common
economic basis, several penalty costs must be included in the
evaluation in addition to the capital cost of the equipment and
its installation. Common to all cooling system evaluations are
the penalties incurred to account for: 1) the loss of plant per-
formance (capacity and energy) at elevated temperatures, 2) the
power and energy required to operate the cooling system, and 3)
the cooling system maintenance requirements. Other penalties
may be included under special circumstances. For instance, the
cost incurred for the purchase of water and the capital and op-
erating costs of the water supply, treatment, and blowdown dis-
posal systems may be included.
The evaluation of capacity and energy penalties depends
both on how the loss of plant performance is assessed and how
that loss is made up. For these reasons, three different methods
have been used in the economic evaluations of cooling system
alternatives(1-6). These methods have been categorized by
Fryer(7) as follows:
1. Fixed demand/fixed heat source method
2. Fixed demand/scalable steam source-scalable plant method
3. Negotiable demand/fixed heat source method.
In the first two methods, a fixed demand or load is imposed
on the plant. This fixed demand serves as the basis from which
the loss of plant performance can be assessed. In other words,
as the plant output changes due to changes in cooling system
performance, the capacity and energy generated are compared to
the fixed demand required of the plant. If the heat source is
fixed, the next step is to decide how to meet that demand from
generating units other than the plant. The methods of meeting
that demand then completely define the capacity and energy penal-
ty assessment. If the scalable steam source method is selected,
the next step is to define what fraction of the loss of capacity
21
-------
will be made up by scaling up the size of the heat source, i.e.,
the entire plant exclusive of the cooling system.
in the third method, the demand is ne9f^le meaning that
the utility system will take whatever output that the plant is
capable of generating. The performance differences of the cool-
ing systems are reflected in the differences in the net energy
output. There is no lost capacity or energy to be considered.
3.1.2 Fixed Demand/Fixed Heat Source Method
In the fixed demand/fixed heat source method, it is assumed
that a fixed demand is imposed on the plant output. This fixed
demand is generally the name plate power output of a reference
plant operating with a conventional turbine at a specified tur-
bine back pressure. The power plant under consideration also has
identical energy input and plant design as the reference power
plant. As the plant performance changes, due to changes in cool-
ing system performance, the capacity and energy generated are
compared to the fixed demand required of the plant. If the cool-
ing system caused the plant to operate below the fixed demand, a
penalty equivalent to an increase in capital cost is added to the
capital cost of the cooling system; credit is taken if the plant
operates above the demand value. A penalty is also assessed for
the capacity and energy requirements for operating the pumps and
fans .
3.1.3 Fixed Demand/Scalable Heat Source Method
The fixed demand/scalable heat source method assumes that
while the demand is basically set by the reference plant, the
heat source and the balance of the plant can be scaled up in size
to provide a part or all of the loss of plant performance. When
scaling up the heat source, other plant components must also be
increased to accommodate an increased steam flow For fossil
plants the additional scaling up of plant components would in-
clude the boiler, superheater, reheater , feedwater heaters, steam
pipes, coal handling equipment, turbine-generator, etc For a
nuclear plant, it would include the reactor core and its associ-
ated equipment. ^-LC ctuu xtt> dt>buux
steam source has been scaled so thlt ? ? V£allng- The
steam for the same capacity as tS r J P haS adec3uate
spective rated back P?essuLs in 1*^™* Plant at their re
the approach used inerence
22
-------
such that during the coldest temperatures some excess capacity
above the fixed demand imposed on the reference plant would
exist. However, during the hottest temperature periods a short-
age would result, which would have to be made up by some capaci-
ty leveling means, such as gas turbines (Figure 3.1).
In some studies which concerned dry cooling systems, the en-
tire plant, including necessary additional steam supply, has been
scaled up so that the dry cooling plant will meet the demand or
load imposed on the plant even during the highest maximum ambient
temperature as shown in Figure 3.2. This represents the maximum
amount of scaling that would be required. Excess capacity would
exist at all temperatures except at the maximum temperature. On
a normalized basis, the same unit costing results from using a
derating method.
Steam source and plant size scaling of fossil plants are
possible, barring problems of scaling between discrete standard
sizes of certain equipment. Scaling of the steam source of a
nuclear plant may not be at all possible if the reference plant
is at the current U. S. Nuclear Regulatory Commission limits on
the thermal power. An alternative method which circumvents this
problem is to reduce the load or demand imposed upon the plant,
or to essentially derate the dry cooling plant relative to the
reference plant as in the method discussed below.
3.1.4 Negotiable Demand/Fixed Heat Source Method
The negotiable demand/fixed heat source method involves
a derating process rather than a size scaling process. Barring
economics of scale, derating or scaling done to the same propor-
tion should result in the same unit costs. The derating of the
load imposed on the dry cooling plant has involved derating the
dry cooling plant to the output that it can produce at maximum
steam flow during the maximum ambient temperature. Figure 3.3
exemplifies this method. Derating to this level would be a ra-
tional approach if the dry cooling plant were isolated and had
to meet a constant base load. However, in an actual utility
system, it does result in significant and uneconomic excess
capacity during the cold periods. On the other hand, no direct
energy or capacity must be made up, thereby, greatly simplifying
the analysis.
3.2 TREATMENT OF LOSS OF PLANT PERFORMANCE
In this and in subsequent subsections the fixed demand/fixed
heat source method of analysis is described in detail. Cooling
system costs reported in Sections' 4 and 5 are based on this method,
The quantitative evaluation of the loss of plant performance
23
-------
required for assessing the capacity and energy penalties in a
fixed demand/fixed heat source evaluation is illustrated in Fig-
ure- 3.4.
Figure 3.4 shows the typical gross plant output of the re-
ference power plant as a function of ambient temperature and
time when the plant is operated. The ambient temperature affects
the plant output, since the performance of a cooling system
determines the lowest temperature of the thermodynamic cycle and,
consequently, the plant output as discussed in Section 2.3. This
figure also shows the net plant output obtained by deducting_from
the gross plant output the capacity required to run the cooling
system auxiliary equipment.
The maximum plant capacity deficit with respect to the fixed
demand occurs at the highest ambient temperature and represents
the capacity replacement needed. This includes both the maximum
loss of plant performance, (AkW)max, and the coincidental auxil-
iary power requirement, (Hp)aux- Tne hatched area represents
the replacement energy required during the annual cycle. The
area above the gross plant output curve represents the energy
deficit caused by the changes in cooling system performance,
whereas the hatched area between the gross plant output and the
net plant output curves represents the energy requirement by the
cooling system auxiliary equipment, e.g., pumps and fans.
Figure 3.5 shows the relative performance of a power plant
with different size cooling systems. As indicated in this figure,
when the cooling system size or design changes, the plant per-
formance curves are shifted; both the capacity and energy
deficits with respect to the base values change, resulting in
different penalty costs for different cooling systems. However,
the plant fuel costs will not be affected by the change in
cooling systems, because the size of the heat source is kept
unchanged regardless of cooling system changes, and the heat
source is assumed to operate at full power during the period of
the year when it is operating. There is no change in capital
cost for the balance of the power plant, as the boiler and the
balance of the plant are also assumed to be fixed. Thus, in the
fixed source-fixed demand method of analysis, the cost of in-
stallation and operation of the boiler and the balance of the
plant is not included in an assessment of the penalty cost in-
curred by the cooling system deficiency.
3.3 CAPACITY AND ENERGY PENALTY ASSESSMENT
The annual capital needed to provide the extra capacity and
energy to compensate for the losses as discussed in the pre^iSSs
sectlon are a part of the total penalty cost. in evaluating ?he
24
-------
penalties, it is assumed that the plant either operates at full
capacity or is off-line and has an average capacity factor of a
certain percent, e.g., 75 percent.
The equations for evaluation of these annual penalty costs
are given below:
Capacity Penalty (P^) :
PI = afcr-K- (AkW)max (3.1)
Replacement Energy Penalty (P2):
r8760 Pf * 1
P2 = cap f KOAM + F-HR(T)> -AkW(T)-dt (3.2)
Cooling System Auxiliary Power
P3 = afcr-K- (HP)aux (3.3)
Cooling System Auxiliary Energy (P^):
-8760 r, ^ -|
?4 = cap f KOAM + F'HR(T» *HP(T)'dt (3.4)
where:
(AkW)max, AkW(T), (HP)aux, and HP(T) are shown in
Figure 3.1.
and:
afcr = annual fixed charge rate, 1/100.
K = capacity penalty charge rate, $/kW.
(AkW)max = maximum loss of capacity at Tmax, kW.
Tmax = Pea^ ambient temperature, °F.
cap = average capacity factor of the plant, %/100,
OAM = operation and maintenance cost for the
generating unit used, $/kWh.
F = fuel cost for the generating unit used to
make up the loss of energy, $/Btu.
25
-------
HR(T) = heat rate as a function of ambient tem-
perature for the generating unit used to
make up the loss of energy, Btu/kWh.
T = ambient temperature (T is a function of
time) , °F.
AkW(T) = loss of capacity at ambient temperature T,
kW.
t = time, hr.
(HP) = cooling system auxiliary power requirement
aux , , w
ar xmax' KW-
HP(T) = cooling system auxiliary power requirement
at ambient temperature T, kW.
The capacity penalty, PI, and the auxiliary power penalty, P3,
Equations (3.1) and (3.3), are first cost penalties. They re-
present the capital expenditure for the generating equipment
needed to supply the extra power, either by the addition of
peaking units (e.g., gas turbine or pumped storage generating
units) or by providing excess capacity from base load units in
the utility system. These penalties are annualized by the
multiplication of an annual fixed charge rate.
The replacement energy penalty, f^i an<^ tne cooling system
auxiliary energy, P4, Equations (3.2) and (3.4), are annual
energy cost penalties. These annual energy costs are evaluated
by integrating the energy costs for a series of time periods,
which add up to a year. Each time period has a constant ambient
dry bulb temperature and a coincident and constant wet bulb
temperature .
3.4 ECONOMIC FACTORS FOR CAPACITY AND ENERGY PENALTY ASSESSMENT
Since the size of the plant heat source is fixed, the loss
of plant capacity and energy will be provided by an outside
source. The source of capacity and energy replacements which
serves as the basis for the assessment of the associated
economic factors K, F, and OAM may include any of the following:
1. High capital cost, low operating cost base load units
2. Low capital cost, high operating cost peaking units
3. A mixture of generating unit types
26
-------
4. Purchased power from another utility system.
The selection of the capacity replacement is dependent on
economics and on the type of duty of the capacity being replaced.
For example, for duties which require relatively constant loads
or large amounts of energy, the replacement choice on economic
grounds should be a base load capacity. Such is the case for the
cooling system auxiliary power and also the capacity loss for dry
and wet/dry cooling systems during most of a year, except at tem-
peratures near the highest ambient temperature(1,2). A portion
of the maximum capacity loss at the highest ambient temperature
for a dry cooled plant should be provided by peaking units, such
as gas turbines.
3.5 OTHER PENALTY COSTS
3.5.1 Water Cost Penalty
The cost of supplying the make-up water to a plant and the
handling of the blowdown disposal consists of the following com-
ponents:
1. Capital cost for the make-up water supply system
a. pumps and associated structures
b. pipelines
2. Pumping cost which includes both the capacity
charge for the power required by the pumps and
the energy charge for pumping the water
3. Water purchase cost
4. Capital cost of water treatment facilities
and operating cost
5. Capital and operating costs for blowdown
disposal.
For specific power plants all these component costs can be sep-
arately estimated. In the absence of the specific information,
a lumped charge for the purchase and treatment cost of make-up
water and circulating water can be used.
3.5.2 Cooling System Maintenance Penalty Cost
The cooling system maintenance penalty is the cost charged
to a cooling system for services which include periodic main-
tenance and replacement parts. Cooling system maintenance cost
mainly consists of:
27
-------
1. Lubrication and general inspection of the motors
and gearboxes
2. Partial replacement of motors and gearboxes
3. Cleaning of the cold water basins of the wet
towers
4. Cleaning and partial replacement of finned tubes
for the heat exchangers, if dry towers are used
5. Condenser tube cleaning and tube replacement.
The maintenance costs of various cooling system components are
generally calculated as a percentage of the capital cost of these
components in the absence of specific cost information for each
of the above components.
3.6 TOTAL EVALUATED COST AND OPTIMUM COOLING SYSTEM
The penalty costs evaluated on an annual basis are capital-
ized over the plant lifetime and added to the capital cost of
the cooling system. The sum of the capital cost and the capital-
ized penalty cost is called the total evaluated cost and is ex-
pressed by the following equation:
N
Ct = C + -J— .^ Pi (3.5)
^ afcr / j ->
where:
Ct = total evaluated cost, $.
C = capital cost of cooling system, $.
afcr = annual fixed charge rate, %/100.
PJ = annual economic penalty for the jth component, $.
j = index for penalty cost component.
N = total number of penalty cost components.
This total evaluated cost represents an effective capital cost
of the cooling system. ^-LVC Capita.!, cost
28
-------
system can be identified as shown in Figure 3.6. This minimum
total evaluated cost system is called an optimum cooling system,
and this cost represents the best trade-off between the capital
and penalty costs.
The figure also shows the general trend of capital cost and
penalty costs. Varying the size and design of a cooling system
will vary the capital cost and penalty costs associated with the
system. For example, a large and, consequently, expensive cool-
ing system will have better performance than a smaller version
of the same system. The smaller system, however, will have a
higher economic penalty.
3.7 ECONOMIC OPTIMIZATION
Economic optimization is the process of selecting the mini-
mum cost cooling system. It includes sizing and costing of a
series of cooling systems, determining their thermal performance,
water consumption, auxiliary power and energy needs, and the re-
sulting economic penalties during a typical annual cycle. The
total evaluated costs of these systems are then determined, and
the system with minimum total evaluated cost is selected as the
optimum system.
Additional criteria or restrictions may be imposed on the
economic optimization. An example is the selection of an optimum
wet/dry system for a specific water consumption requirement
which serves as an additional criterion(2,3).
The cooling systems are generally sized on the basis of
design temperatures using components of standard designs. The
major components of a cooling system include the condenser,
circulating water pump and motor, the pump structure, the ter-
minal heat sink device, and the connecting pipelines.
The most difficult part of the cooling system design is that
of the terminal heat sink device. This is due to the fact that
the performance and cost information of a particular cooling de-
vice usually falls in the realm of proprietary information. Heat
transfer coefficients, pressure drop correlations, and other
operational factors are all necessary to size a cooling system
and to determine the performance of the cooling system but are
difficult to obtain as functions of variables over which a system
designer has control. The recourse is to use the standardized
designs offered by manufacturers.
The design parameters include wet bulb temperature, dry
bulb temperature, approach to wet bulb or dry bulb temperature,
cooling range, wind velocity, and other meteorological variables
pertinent to the particular cooling system under considertion.
29
-------
The design approach, range, and terminal temperature dif-
ference together define the saturated steam temperature in the
condenser and the turbine back pressure. From the turbine heat
rate curve, the turbine-generator output (gross plant output)
and the amount of heat rejected are determined. The heat load,
combined with the given design temperatures, determines the size
of the various cooling system components.
Once a system is designed, the performance of the system can
be evaluated at off-design ambient conditions. The performance
of one component will influence that of the others. Consequently,
the performance of the plant, as a function of the ambient con-
ditions, has to be considered simultaneously with the condenser
and the terminal heat sink device.
The cost and design obtained with this approach is sufficent-
ly accurate for budgeting purposes and economic comparisons with
alternative cooling systems as indicated in Reference 1.
30
-------
OJ
140
120
o
H
1
W
w
9
D
ffl
100
80
40
20
-GROSS OUTPUT
/i:";.V.'<
K'Vy \DRY COOLED PLANT, "FIXED
" DEMAND/SCALABLE PLANT"
NET OUTPUT
GROSS OUT!
DEFERENCE PLANT
NET OUTPUT
.
FANS AND PUMPS
BULB
TEMPERATURE
DRY COOLED PLANT,
"FIXED DEMAND/FIXED
STEAM SOURCE" - NET OUTPUT
EH
I
U
!z
K
1.0
CM
EH
g
0,9
H
o
0
:000
4000
6000
8000
ANNUAL CUMULATIVE DURATION, hours
Figure 3.1. Relative performance of a dry cooled plant
utilizing a high back pressure turbine under
the fixed demand/scalable steam source/scalable
plant approach.
-------
U)
160
140
r
fa
o
w
OJ
D
I
w
w
EH
CQ
1-3
D
W
s
Q
-GROSS OUTPUT
^^^^^'^l^f^^^:^AN.? AN.P. Py.^^^^V^X.l'''"
PLANT, "FIXED
"DEMAND/SCALABLE PLANT"
NET OUTPUT
100 I-
DRY BULB
TEMPERATURE
DRY COOLED PLANT,
"FIXED DEMAND/FIXED
STEAM SOURCE" - NET
OUTPUT
1.0
CM
w
CM
w
«
CM
\
CM
0.9
0
CM
EH
£>
O
OS
CM
H
^
b
52,
0
2000 4000 6000 8000
ANNUAL CUMULATIVE DURATION, hours
Figure 3.2. Relative performance of a dry cooled plant
utilizing a high back pressure turbine under
the fixed demand/scalable steam source/scalable
plant approach with maximum required scaling-
-------
LO
120
100
EH
PQ
CO
Q
REFERENCE PLANT - NET OUTPUT (FIXED DEMAND )\
REDUCED OUTPUT DUE TO
PRESSURE
FANS AND PUMPS
DRY COOLING - NET OUTPUT
DRY BULB TEMPERATURE
REFERENCE PLANT - NET OUTPUT (DERATED)
1.0
P.;
2000
4000
6000
8000
Figure 3.3
ANNUAL CUMULATIVE DURATION, hours
Relative performance of a-dry cooled plant utilizing
a high back pressure turbine under the negotiable
demand/fixed heat source approach with maximum re-
quired derating.
-------
EH
H
U
o
EH
1
ANNUAL TEMPERATURE DURATION CURVE
PLANT FIXED DEMAND
GROSS PLANT OUTPUT
NET PLANT OUTPUT
GROSS OUT-
PUT - COOL-
ING SYSTEM
AUXILIARY
INPUT
CUMULATIVE ANNUAL DURATION, hours
ID
EH
H
EH
EH
H
1 YEAR
Figure 3.4.
Ambient temperature duration and
corresponding plant performance
for fixed demand/fixed heat source
approach.
34
-------
U)
Ul
120
100
EH
£
H
H
EH
9
D
CQ
tH
«
Q
_ft
60
20
PLANT FIXED DEMAND
H
U
1.0
INCREASING COOLING SYSTEM SIZE
2000 4000 6000
ANNUAL CUMULATIVE DURATION, hours
8000
Figure 3.5. Relative performance of different size
cooling systems.
EH
ID
ft
O
o
ft
Q
H
0.9
tr
O
s
-------
TOTAL EVALUATED COST = (CAPITAL
''COST + PENALTY COST)
c/y
o
u
CAPITAL COST
PENALTY COST
0
Figure 3.6
COOLING SYSTEM DESIGN PARAMETER
Schematic diagram of economic trade-
offs and optimum selection of cooling
systems.
36
-------
REFERENCES
1. Hu, M. C. Engineering and Economic Evaluation of Wet/Dry
Cooling Towers for Water Conservation. United Engineers
& Constructors Inc., Philadelphia, PA, UE&C-ERDA-761130,
1976. (Available from National Technical Information Service,
Springfield, Virginia, COO-2442-1).
2. Hu, M. C. and G. A. Englesson. Wet/Dry Cooling Systems for
Fossil-Fueled Power Plants: Water Conservation and Plume
Abatement. United Engineers & Constructors Inc., Philadel-
phia, PA, UE&C-EPA-771130, 1977. (Available from National
Technical Information Service, Springfield, Virginia, EPA-
600/7-77-137).
3. United Engineers & Constructors Inc. Heat Sink Design and
Cost Study for Fossil and Nuclear Power Plants. Philadelphia,
PA, UE&C-AEC-740401, 1974. (Available from National Technical
Information Service, Springfield, Virginia, WASH-1360).
4. Mitchell, R. D. Methods for Optimizing and Evaluating
Indirect Dry-Type Cooling Systems for Large Electric
Generating Plants. R. W. Beck and Associates, Denver, CO,
ERDA-74, 1975.
5. Braun, D. J., et. al. A User's Manual for the BNW-I
Optimization Code for Dry Cooled Power Plants. Battelle
Pacific Northwest Laboratories, Richland, Washington,
BNWL-2180, 1977.
6. Hauser, L. G., K. A. Oleson, and R. J. Budenholzer. An
Advanced Optimization Technique for Turbine, Condenser,
Cooling System Combinations. Proceedings of the American
Power Conference, 33:427-445, 1971.
7. Fryer, B. C. A Review and Assessment of Engineering Economic
Studies of Dry Cooling Electric Generating Plants. Battelle
Pacific Northwest Laboratories, Richland, Washington,
BNWL-1976, 1976.
37
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SECTION 4
DESIGN AND OPERATION OF CONVENTIONAL
COOLING SYSTEMS
4.1 EVAPORATIVE COOLING TOWER SYSTEMS
4.1.1 General Description
In an evaporative or wet cooling tower, most of the waste
heat is dissipated to the atmosphere by evaporation of a small
portion of the circulating cooling water. Heated water from the
plant condenser is pumped to the top of the tower's fill or pack-
ing material. The water then flows or splashes down through the
fill to the water collecting basin while air sweeps through the
fill area. As the water and air come in contact, a small portion
of the water becomes vaporized, thus, carrying with it the latent
heat of evaporation. In the process, air is humidified, and the
remaining unvaporized water is cooled. The water falls by gravi-
ty through the fill, while the air flows either perpendicular to
the flow of water (crossflow) or upward and parallel to the flow
of water (counterflow).
Three different methods are used to provide a continuous
flow of fresh air through the tower, resulting in three major
tower types:
1} Mechanical Draft Cooling Towers
A mechanical draft cooling tower is one which uses a fan to
move the air through the tower. The fan provides a constant
volume of air flow through the tower independent of the ambient
weather conditions. The fans can be either induced draft or
forced draft fans, depending on whether the air is pulled or
forced through the tower. For power plant application, most
mechanical draft towers use induced draft fans. Air flow through
the tower is varied by changing the fan motor speed and/or the
pitch of fan blades. Figure 4.1 shows typical mechanical draft
towers of the counterflow and crossflow types(1).
2) Natural Draft Cooling Towers
A natural draft tower is one that depends on a chimney or
stack to induce air movement through the tower. Instead of a
constant volume of air flowing through the tower as in a mechani-
39
-------
cal draft tower, the natural draft tower has an air flow rate
which is proportional to the density difference between the
ambient air and the warmer humid air in the tower. Figure
4.2 shows typical counterflow and crossflow natural draft cooling
towers(1).
3) Fan Assisted Natural Draft Cooling Towers
A fan-assisted natural draft cooling tower is one that de-
pends on both the chimney effect and the fans to move the ambient
air through the tower. The fans are usually located around the
periphery at the base of the tower. The fans augment the natural
draft and provide a nearly constant volume flow. In addition,
the air flow provided by the fans allows a substantial reduction
of the tower height needed to provide the air flow through natur-
al draft. Figure 4.3 shows typical counterflow and crossflow fan-
assisted natural draft towers(2).
4.1.2 Heat Transfer
The macroscopic approach of Merkel's total heat theory has
been almost universally adopted for the calculation of tower per-
formance. Merkel's theory states that the local heat transfer
taking place in a cooling tower is proportional to the difference
between the enthalpy of air stream and the enthalpy of air sat-
urated at the temperature of the water. In the following dis-
cussion, the derivation of Merkel's equation is given to provide
a better understanding of the operation of a wet cooling tower.
It has been shown that Merkel's equation is sufficiently accurate
for practical application as compared to a rigorous solution(3).
The energy equation for a cooling tower is:
(Cp)wL(AT) = GAHa (4.1)
where:
-------
Equation (4.1) is applicable to any cooling device which uses
the atmosphere as its final heat sink. The simplifying assum-
tion made in Equation (4.1) is that the water flow rate remains
constant in the cooling tower. This is not exactly true, be-
cause of the water loss due to evaporation. However, since the
actual amount evaporated will usually be less than three per-
cent of the circulating water flow, this assumption will intro-
duce very little error.
The driving potential for the sensible heat transfer is
the difference between the water temperature and the tempera-
ture of the air in contact with the water. The driving poten-
tial for evaporation is the difference between the concentration
of water vapor in the saturated air at the water surface and
the concentration of water vapor in the bulk of the air stream.
This relationship can be expressed for a volume element of a
cooling tower packing(3-5) as:
(Cp)wL-dTw = [h(Tw - Ta) + K-Hy |ws(Tw) - W(Ta)|] a-dV (4.2)
where:
(C ) and L are defined under Equation (4.1).
dT = incremental change in water tempera-
ture, °C.
h = heat transfer coefficient, W/m2°C.
w
= temperature of the water in the volume
element, °C.
T = temperature of the air in the volume
element, °C.
K = mass transfer coefficient for water
vapor, Kg/m2.
HV = latent heat of vaporization, J/Kg of
dry air.
W (T ) = specific humidity of saturated air at
the water temperature, Kg of water vapor/
Kg of dry air.
W(Ta) = specific humidity of air stream, Kg of
water vapor/Kg of dry air.
a = water surface area per unit volume
of the cooling tower packing, m"1.
41
-------
dV = increment of tower packing volume, m .
The right side of Equation (4.2) can be rearranged to yield the
following equation:
Cp(Tw"Ta) + Hv W-^V a'dV (4'3>
where :
Cp = specific heat of dry air, J/Kg°C.
The ratio h/CpK (Lewis number) has been experimentally determin-
ed and has been found to be almost equal to one for an air-water
vapor system. Using the value 1.0 for h/C K and rearranging
Equation (4.3) gives:
(Vw^^w = K [{cpTw + VWs(V} - {cpT* + VW}]
The term (CpT + HV'WS(TW)) is the enthalpy of saturated air at the
the water surface temperature; the term (C Ta + Hy.WfT^)) is the
enthalpy of the bulk air stream. Thus, Equation (4.4; can be
written:
(Cp)wL-dTw = K. [HS(TW) - H(Ta)] a-dV (4.5)
where :
HS(TW) = (CpTw + HV-WS(TW))
H(Ta) = (CpTa + Hv-W(Ta))
Rearranging the terms in Equation (4.5) assuming K and a are
constants and integrating over the total cooling tower packing
volume gives: ^
- H(Ta)
(4'6)
The enthalpy of moist air at any dry bulb temperature T anrl
wet bulb temperature, Twb, is approximately equal to the^nthalPY
of saturated air having a temperature eoual ^ tt I. f. entnalpy
oerature- i e H tT ) - H IT \ at"" e<3ual to the wet bulb tern-
L/C-J- dL.Li.LC/ _L • C • / XI I ± I — rl—lJ. .1 T"F TJ rTI \ • _
H(Ta), Equation (4.§) becSme^rkJi-^wb^.J^ substituted for
42
-------
KaV % / WZ (Cn)
W
"a < V - H, (Twb, -
Figure 4.4 illustrates the water and air relationship and the
driving potential which exists in a counterflow tower (4-8). This
figure will be used to explain the tower cooling process and the
meaning of Merkel's equation. The water operating line, AB, is
fixed by the tower inlet and outlet water temperatures; and it
represents the conditions of the air adjacent to the falling
water surface. Since it is generally assumed that the air ad-
jacent to the water surface is saturated at the water surface
temperatures, the line, AB, is a portion of the saturation line
on the psychrometric chart. The air operating line, CD, repre-
sents the bulk air conditions as the air flows through the tower
with the air entering the tower at point C and leaving the tower
at point D. Point C for the bulk air stream corresponds to point
B for the air layer adjacent to the water surface and has an en-
thalpy equal to the saturation enthalpy at the entering air wet
bulb temperature. Similarly point D corresponds to point A and
has an enthalpy equal to the saturation enthalpy at the leaving
air wet bulb temperature. The vertical segment, MN, between the
water and air operating lines represents the enthalpy driving
force (Hs - H) , previously represented as (Hs (Tw - H(Ta)). The
water-to-air ratio (L/G) is the slope of the air operating line
as defined by Equation (4.1). The coordinate axes refer direct-
ly to the temperature and enthalpy of any point on the water
operating line, AB. The corresponding wet bulb temperature of
any point on the air operating line, CD, is found by projecting
the point horizontally to the water operating line, AB, then ver-
tically to the temperature axis. The cooling range is the pro-
jected length of line, CD, on the temperature scale. The cool-
ing tower approach is shown on the diagram as the difference be-
tween the cold water temperature leaving the tower and the am-
bient wet bulb temperature.
The integral of the Merkel's equation (Equation (4.7)) is
inversely proportional to the area ABCD in the diagram. The
term (KaV/L)M", known as the tower characteristic, is proportional
to the relative degree of difficulty to perform a given heat
transfer duty. For a given water flow rate and range, the cool-
ing tower characteristic will decrease as the area between _ lines
AB and CD increases. The area can be increased by increasing
the approach or by "decreasing the enthalpy driving force, Hs - H.
A decrease in Hs - H can be achieved by increasing the air flow
rate. The air flow rate must always be large enough so that
line CD will not intersect line AB.
Equation (4.7) has been graphically represented as a func-
tion of water- to-air ratio (L/G), approach, range, and wet buifc
43
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temperatures. Separate charts have been prepared for each repre-
sentative combination of inlet air wet bulb temperature and
range(9). These charts can be used with experimentally obtained
cooling tower characteristics to size the tower at a given de-
sign condition and estimate the tower performance at off-design
conditions. An example of their use is shown in Section 4.1.4
where they are used to illustrate the procedure for the design
of a mechanical draft tower.
4.1.3 Design and Performance Parameters
The major parameters which influence the size and perfor-
mance of a cooling tower are(6): 1) cooling range, 2) approach
(Figure 4.5), 3) ambient wet bulb temperature, 4) flow rate of
water to be cooled, 5) flow rate of air passing through the
tower packing, 6) performance coefficient of the tower packing,
and 7) volume of the tower packing. The parameters over which
the cooling system user has control are: 1) the cooling range,
2) the approach, and 3) the design wet bulb.
The ambient wet bulb temperature is an important factor in
designing, sizing, and selecting evaporative towers. It is a
controlling factor since it is the lowest temperature to which
water can be cooled by the evaporative method. Selection of a
proper design wet bulb temperature is, therefore, vital in de-
termining the optimum cooling tower size. A design wet bulb
temperature that is too high can result in an oversized tower;
one too low can result in inadequate tower capacity, such that
the power plant it serves would experience severe capacity de-
ficits at high ambient temperatures. Current practice is to se-
lect a wet bulb temperature which is exceeded no more than one
percent of the time during an annual cycle.
Once the design wet bulb temperature is established, the
range and approach determine the size and, consequently, the
cost of the cooling equipment. Thus, in economic evaluations of
wet tower cooling systems, these variables are extensively in-
vestigated for each application. The heat rejection duty of the
tower is equal to the product of the range, circulating water
mass flow rate and the specific heat of water. The typical ef-
fect of range on tower size for constant heat load, ambient wet
bulb, and cold water temperature is shown in Figure 4.6a(l).
With a given heat load, the size of the tower increases as the
range decreases. The increased capital cost for a larger tower
would be compensated by better operating performance in that the
lower range of this tower would achieve a lower back pressure
in the turbine and, consequently, lower operating penalties over
tne lifetime of the plant (see Section 3 for a discussion of
capital and operating costs).
The final and most important temperature consideration is
44
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establishment of the approach, the difference between the cold
water temperature and the wet bulb temperature. Once the de-
sign wet bulb temperature and range have been determined, the
approach fixes the operating temperatures.
The typical effect on tower size of varying the approach
while holding heat load, design wet bulb, and range constant is
shown in Figure 4.6b(l). With a given heat load, the size of the
cooling tower required increases as the approach decreases. Of
all of the variables involved, the approach can have the great-
est effect upon the size and cost of the cooling tower. The
closer the cold water temperature approaches the wet bulb tem-
perature, the greater the increase in cooling tower size. For
example, consider a tower designed for a 15°F (8.4°C) range and
a 15°F (8.4°C) approach to a 76°F (24°C) wet bulb temperature.
Decreasing the approach to 10°F (5.5°C) will increase the tower
size by 50 percent. In comparison, decreasing the range from
15°F (8.4°C) to 100F (5.5°C) will increase the tower size by
only 15 percent.
As in the example described in the discussion on range, in-
creased capital costs for larger size cooling towers are com-
pensated for by better operating performance. In evaluating
the costs of cooling systems, the investigation should include
the trade-off between the capital costs and the operating costs
of each design.
4.1.4 Mechanical Draft Wet Cooling Tower Design
Charts, such as that shown in Figure 4.7, can be used with
experimentally obtained cooling tower characteristics provided
by tower manufacturers to size a tower for a given heat duty.
The empirical characteristic equation describes the relationship
between the tower characteristic, (KaV/L)c, and the water-to-air
ratio, (L/G), for the tower as given in the following functional
form:
where:
. KaV
~)c = characteristic of a particular cooling
" tower or cooling tower module design.
c,n = parametric constants which describe
the line AB on Figure 4.7.
The tower characteristic curve for a particular cooling
tower design is usually determined from test data and perfor-
mance tests conducted at research facilities. The research
data are then related to field performance tests for further
45
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substantiation. The values of "c" and "n" in Equation (4.8) are
a function of packing design. The value of n is the slope of
the characteristic curve for the packing design. Values can
vary from 0-25 to 1.0. The lower values are generally charac-
teristic of splash-type packings, and the upper limits are
usually associated with high heat transfer, film-type packings.
The average value of n for industrial type packings is from
0.5 to 0.6 (10).
To size a tower using standard modules and to determine its
performance, the following parameters in units consistent with
that used to develop the empirical characteristic equation must
be known about the standard module:
Twbs = wet bulb temperature.
TRS = temperature range.
L = water mass flow rate.
s
G = air mass flow rate.
c, n = characteristic equation parameters
at Twbs and TV
HPC = input power to tower fans.
o
The procedure requires that the experimentally determined charac-
teristic (KaV/L)c equals the characteristic (KaV/L)M determined
at the design conditions using Merkel's Equation:
> c (4.9)
With this condition satisfied, the water-to-air flow ratio, (L/G),
needed to reject a given amount of heat with a corresponding range
and approach can be obtained. The water-to-air flow ratio along
with the air flow rate of the standard module can be used to
determine the number of modules needed.
Specific information concerning the tower characteristic
equation must be obtained from the tower manufacturer. This
information is proprietary with each manufacturer. The manu-
facturer's tower characteristic graph is made available to the
utility for evaluating the guaranteed performance of the tower
after it has been purchased.
4-1.5 Natural Draft Wet Cooling Tower Design
The cooling process which takes place in a natural draft
46
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wet tower is identical to the process which occurs in a mechan-
ical draft tower. The equations which describe the heat trans-
fer process in a mechanical draft tower are also applicable to
a natural draft tower. The basic difference between the towers
is the way by which the air flow is established. As indicated
in Section 4.1, a natural draft tower depends on a chimney or
buoyancy effect to induce air movement through the tower.
As stated in Section 4.1.4, specific information concern-
ing the tower characteristic equation is proprietary with each
manufacturer. If, however, the tower characteristic is pro-
vided, the water- to-air flow ratio and the air flow rate can be
determined. Thus, the basic design objective of the natural
draft tower is to achieve the needed air flow rate for heat re-
jection. As the air flows through the tower packing, it is
heated and humidified by evaporation. Both of these processes
reduce the density of the air and produce a driving pressure dif-
ferential called draft which in turn maintains the continuous
flow of air through the tower. The magnitude of the draft is
proportional to both the air density difference and the tower
height and is expressed as:
APd = H a -
where :
AP
-------
/0. = air density, Kg/m3 .
Vi = air velocity, m/s.
i = subscript identifying location of
important air flow resistances in
the tower.
The total resistance to air flow in the tower requires summation
of all the important flow resistances in the tower. These
usually include the resistance of the packing, the frictional
resistance of the internal tower shell, the resistance created
by the water drops, and the resistance of the various obstruc-
tions, such as drift elminators (11-14) . Thus,
Theoretically, as long as a density difference exists, a tower
height can be selected to obtain the required draft; however,
there is a practical limit on tower height due to structural
and economic considerations .
Natural draft towers in the United States are constructed
of reinforced concrete with the shell shaped like a hyperboloid
of revolution. A cylindrical shell would work equally well; how-
ever, to produce the same amount of draft, a hyperboloid shell
provides improved structural strength against wind forces and
requires less material for its construction (14) .
In response to the increased heat rejection required for
the new generation of large electric generating stations, the
manufacturers have provided larger towers. Figure 4.8 shows
the trend in natural draft tower sizes in the United States since
1958. There are more than 120 natural draft towers installed or
planned in the U. S. (15) , mostly in the eastern half of the
country.
4.1.6 Fan-Assisted Natural Draft Cooling Tower Design
In recent years, as the size of power plants increased, the
size of natural draft cooling towers increased proportionally
as shown in Figure 4.8. Cooling tower manufacturers and elec-
tric utilities have been looking for ways to reduce the aesthetic
impact of these tower installations while retaining the advan-
tages of natural draft towers in terms of environmental impacts
of plume and drift (see Section 11). AS a result the fan-assist-
ed natural draft tower evolved; it utilizes a hyperbolic shell
48
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similar to that of the natural draft tower with motor-driven
fans at the periphery of its base. Because it no longer depends
on the stack height to produce all of the needed draft, the
height and diameter of a fan-assisted tower can be tailored to
each site, considering specific limitations of ground area and
height of plume discharge.
Current design and operating experience of fan-assisted
natural draft towers have been developed in Europe. In 1976
there were only 10 such towers in operation or under construc-
tion in Europe and none in the United States (2). The majority
of these towers (nine) are of the conventional forced draft
counterflow towers, and one is of the crossflow induced draft
type.
To take full benefit of the natural draft effect of the
fan-assisted tower, the fans should be controlled such that
their use is minimized. Figure 4.9 shows a typical annual
cycle of fan use. The fans operate at maximum power for a very
short period of the year and operate at or below 50 percent of
capacity for most of the year(2).
4.1.7 Description of Components and Materials of Construction
Used in Wet Cooling Towers(16)
The basic components of the wet towers are: 1) tower frame-
work, 2) water distribution system, 3) fill or packing material,
4) drift eliminators, 5) inlet louvers, 6) water collecting basin,
and 7) fans. The following discussion describes the main func-
tion of each component and the materials used in construction.
4.1.7.1 Tower Framework—
The tower framework for mechanical draft towers is a
structure designed on the basis of aerodynamic, structural,
thermal, and economic considerations. It is designed to support
the weight of the various components in the tower as well as the
weight of the cooling water. The framework may be of wood or
concrete but must be strong enough to withstand winds and seismic
loads.
The tower framework of a natural draft tower or fan-assist-
ed natural draft tower is usually a hyperboloid shell made of
reinforced concrete. The hyperboloid shape is used because of
structural and economic considerations.
4.1.7.2 Water Distribution System—
The function of the water distribution system is to provide
a uniform distribution of the hot water above the fill. The
distribution network can be made of treated redwood, cast iron,
carbon steel, polyvinyl chloride (PVC), fiberglass, or asbestos
49
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cement. All spray nozzles are usually made of plastic.
4.1.7.3 Fill or Packing Material—
The function of the fill or packing material is to break
the water into many small droplets or filaments so as to in-
crease the air-water interface area as well as the contact time.
Two types of fill are in common use: film fill which breaks
the water into thin filaments and splash fill that produces
small droplets. The fill material can be wood, asbestos cement,
or various types of plastics. Several examples of packing con-
figurations are shown in Figure 4.10.
4.1.7.4 Drift Eliminators—
Drift eliminators are located above the fill material.
They serve as a baffle designed to cause a sudden change in the
direction of the air stream. The sudden change in direction
strips the water droplets from the rising air stream, thus
reducing the quantity of water (drift) lost to the atmosphere.
Materals used in the construction of drift eliminators are wood,
asbestos cement, and various types of plastics. Typical drift
eliminator configurations are shown in Figure 4.11.
4.1.7.5 Inlet Louvers—
The inlet louvers provide a uniform air flow into the tower.
Their design includes proper slope, spacing and width to prevent
water losses and to minimize icing problems during the winter.
Construction materials are usually treated redwood, asbestos
cement or plastics.
4.1.7.6 Water Collecting Basin—
The cooled water falls through the fill and is collected at
the bottom of the cooling tower in a basin from which it is
pumped back to the condenser. The basin is constructed from
concrete.
4.1.7.7 Fans—
In mechanical draft cooling towers, a fan provides the de-
sired flow of air through the tower. The fan can be located
at the top of the cooling tower above the drift eliminators or
at the bottom of the cooling tower. In the former case the
induction principle is applied and the fan pulls air through
the fill and the drift eliminators. In the latter case, which
usually applies to small towers, the fan pushes air up the tow-
er through the fill and the drift eliminators. Blades are made
of fiberglass covered with a polyester resin or aluminum coated
with an epoxy or other synthetic resin selected for its cor-
rosion and erosion resistance properties. Blade diameters in
conventional U. S. practice range from 28 to 80 feet?
50
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4.2 COOLING PONDS
4.2.1 General Description of Cooling Ponds
Cooling ponds are man-made bodies of water or natural lakes
used for dissipating waste heat from power plants. Heat dis-
sipation from the pond surface is accomplished by radiation,
conduction, convection, and evaporation. Since a cooling pond
does not have forced air or forced water motion, it is less
efficient than a cooling tower as described in Section 4.1. The
low rate of heat transfer requires that cooling ponds have
large surface areas. The rule-of-thumb values often cited for
pond surface requirements range from 1 to 3 acres per megawatt
of electric output.
Cooling ponds are generally considered economically attrac-
tive for power plants sited in locations where the cost of land
is low and conducive to the construction of the pond, and the
soil is relatively impervious. One of the advantages of a cool-
ing pond worth noting is its potential use for other purposes
which may be incorporated in the design of the pond.
The following list presents the major advantages and dis-
advantages of cooling ponds(17):
Advantages
1. Have reasonable construction costs where land
costs and soil conditions permit
2. Serve as settling basin for suspended solids
3. Need no makeup for extended periods
4. Provide possible recreational area
5. Can be stocked with fish species that are able
to tolerate the warmer waters (Ponds can also
serve as an area for aquaculture or fish farm-
ing. )
6. Serve as river control to minimize flooding or
increase minimum flow
7. Need very little maintenance
8. Have low pumping power requirements
51
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9. Have a high thermal inertia (Water temperature at
the pond intake will not reflect short-term changes
in meteorological conditions or plant loading.)
Disadvantages
1. Require large land area and deny use of this land
for other useful purposes
2. Require soil basin of low permeability or liners
3. Tend to concentrate dissolved solids which may
leach into an underground water source
4. May lead to fogging and icing in adjacent areas
5. Serve as collecting area for wind-blown debris
6. May deny runoff waters to former users below the
pond sites
4.2.2 Classification of Cooling Ponds
Cooling ponds are usually classified by depth as well as
flow pattern(17). A pond is generally considered to, be shallow
if its depth is on the order of 8 to 20 feet (2.4 to 6.1 meters).
Cooling ponds which exceed 20 feet (6.1 meters) are character-
ized as deep ponds. Both types can be further classified ac-
cording to their flow pattern to be described later in this
section.
Cooling ponds can also be classified according to their
intended usage as single purpose (heat rejection primarily) or
multipurpose (heat rejection, recreation, irrigation, etc.).
These classifications are important in the licensing procedure
for power plants designed to use cooling ponds, especially
in the definition of the consumptive water use of the pond (18-21)
4.2.2.1 Shallow Ponds —
Shallow ponds are constructed primarily for heat dissipa-
tion. These ponds are subdivided into "flow through" or "slug
flow" and "completely mixed" types. This distinction depends
heavily on the pond shape and pond outlet design.
Completely mixed ponds are assumed to have a uniform
temperature throughout. Conditions promoting such behavior
are: 1) a sufficient depth to allow wind-induced circulation
as well as circulation induced by plant pumping, 2) a small
,
^Pt£ ^ JVOi? stfatif Cation, 3) a rounded perimeter to
the heated water to mix easily into all of the pond,
52
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4) a discharge located away from the pond shore, and 5) loner re-
tention time. y
Flow-through (or slug flow) ponds are generally long and
slender with inlet and outlet at opposite ends, narrow width
to minimize wind mixing, large width to depth ratio, or low
velocity to minimize vertical velocity gradients. Thus, a flow-
through pond provides more rapid cooling, but it is more expen-
sive to build than the completely mixed pond.
4.2.2.2 Deep Ponds—
Deep ponds are usually constructed for multiple uses or are
natural ponds which have multiple uses. Deep ponds are usually
well-stratified thermally. Deep ponds are further classified
into three categories: 1) horizontally-mixed, 2) flow-through,
and 3) internally-circulating. In the first two, the water
temperature distribution is dominated by the natural hydrological
and meteorological conditions; in the latter, the natural con-
ditions are augmented by the design of the intake and discharge.
As the name implies, the horizontally-mixed ponds exhibit uniform
temperature within each horizontal plane. Reservoirs where the
heat burden is less than 0.25 MWe per acre and the discharge
rate to pond capacity is small will generally approximate a
horizontally-mixed pond.
For discharges with high flow volume outputs relative to
total reservoir capacity, the pond is classified as flow-through.
In this type, horizontal gradients become important.
In internally-circulating ponds, the heat burden is high,
and the effects of meteorological conditions are no longer dom-
inant.
4.2.3 Heat Transfer in Cooling Ponds
4.2.3.1 Mechanisms of Heat Transfer—
The heat transfer mechanisms occurring at the surface layer
of a cooling pond include the following: 1) incoming shortwave
solar radiation, Qs, 2) incoming longwave atmospheric radiation,
Qa, 3) solar radiation reflected from the pond surface, Qsr, 4)
atmospheric radiation reflected from the pond surface, Qar, 5)
longwave back radiation from the pond surface to the atmosphere,
Qbr' 6) heat loss due to evaporation, Qe, and 7) heat loss or
gain due to conduction and convection of air, Qc. These
mechanisms are depicted in Figure 4.12(22).
The intensity of incoming solar radiation striking the
water surface at a given location depends on the altitude of the
sun and on the amount of cloud cover. The longwave atmospheric
radiation comes from the gases, notably water vapor, carbon di-
53
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oxide and oxygen, in the atmosphere and depends on both the
altitude and amount of cloud cover. Not all of the incoming
radiation reaching the water body passes through the water sur-
face. These incoming solar and atmospheric radiations are
independent of water temperature.
The major heat losses at the pond surface are due to back
radiation, evaporation, and conduction-convection. The magni-
tude of these losses is dependent on the water surface tempera-
ture. The back emitted radiation is proportional to the fourth
power of the absolute temperature of the surface. The heat con-
vection to the atmospheric air above the surface is proportional
to the difference of the water temperature and the air tempera-
ture. The heat loss due to evaporation is proportional to the
difference in saturation vapor pressure at the water surface
temperature and the water vapor pressure in the ambient air a-
bove the surface.
4.2.3.2 Net Rate of Heat Transfer Across a Cooling Pond Surface-
The steady state net rate at which heat is transferred
across the water surface to the atmosphere is as follows:
Q = (Qbr + QC + Qe> -
-------
Tg = water surface temperature.
Te = equilibrium temperature of water surface.
The value of K is a function of wind speed and air and water sur-
face temperatures. The equilibrium temperature T is defined
as the surface temperature Tg = T$ for which Q = B under steady
environmental conditions, i.e., without the addition of power
plant waste heat.
In cooling ponds, the forced evaporation loss, i.e., evapo-
ration loss due to the addition of power plant waste heat, ac-
counts for 40 to 80 percent of the waste heat dissipated. The
wind speed and water temperature are the major parameters in
determining what fraction of the total loss is evaporation. The
remaining waste heat, 60 to 20 percent, is lost to the atmo-
sphere primarily by convection and longwave radiation from the
pond surface temperature. One other element in the pond heat
balance is the heat transfer to the ground; it has been esti-
mated to be between 0.5 - 2.5 Btu/ft2-hr-°F(17).
4.2.4 Design and Performance Parameters for Cooling Ponds
The parameters which affect the design and performance
of cooling ponds include those directly affecting heat transfer
and those affecting the circulation pattern of water flows.
The circulation pattern affects the water temperature and in-
directly affects the heat transfer from the pond surface. In
addition to the information presented here, modeling of cooling
pond water consumption is discussed in Section 11.3.
4.2.4.1 Parameters Affecting Heat Transfer—
As was discussed in Section 4.2.3, the parameters which
affect the surface heat exchange of the cooling pond include the
following: 1) latitude, 2) time of year, 3) solar radiation,
4) cloud cover, 5) air temperature, 6) relative humidity, 7)
wind speed, and 8) water surface temperature.
The first four parameters and the last one affect the net
thermal radiation which is absorbed by the water body. The last
four parameters affect the pond surface heat transfer mechanisms
(back radiation, conduction-covection, and evaporation) in the
following manner:
Back Radiation: Qbr~Tg4
Convection: Qc~ (Ts - T&)
Evaporation: Qe~ (&s - ea)
55
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The symbols used in the above proportional (~) expressions are:
T = pond surface temperature, K.
T = air temperature (dry bulb), K.
cl
es = saturation vapor pressure at TS,
mm Hg.
e = water vapor pressure in ambient air,
a mm Hg.
4.2.4.2 Parameters Affecting Water Circulation Patterns-
Based upon actual observation of prototype ponds, Ryan(26,
27) summarized the major parameters affecting pond czrculation
patterns. They are: 1) entrainment of pond water by plant ef-
fluent, commonly called "entrance mixing", 2) pond shape, 3)
configuration of the cooling water intake and water body outlet,
4) wind effects, and 5) density-induced currents. Each factor
will be discussed briefly below.
1) Entrance Mixing
Initial mixing strongly affects pond performance in trans-
ferring heat. This mixing depends mainly on the design of the
outfall from the condenser discharge, the densimetrie Froude
Number of the influent to the pond, as well as the shape of the
pond. The densimetric Froude Number is the criterion by which
the type of flow, tranquil or rapid, is determined. Tranquil
flow occurs when the Froude Number is less than unity and rapid
flow when it is greater than unity. Heat is dissipated more
rapidly from a pond with a higher surface temperature than from
the same pond with a lower temperature. If the outfall promotes
entrance mixing, the pond will have a lower average temperature
and approximate a completely mixed pond. Because of this, a
completely mixed pond requires more surface area than a flow-
through pond to reject the same head load.
2) Shape of the Pond and Effect of Depth
Pond shape is the most significant variable in determining
hydraulic characteristics. A round or square surface pond is
less preferred than a long slender pond due to eddy formation
at stagnation points and possible flow separation. Wind and
density-induced currents always complicate the effect of pond
shape.
Occasionally, stream distribution equipment is used to
increase the active or participating area for cooling. Common
techniques involve modifying the outlet to a fan shape with a
56
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grating across it, or constructing a stream distribution levee
to force the influent to cover a greater pond area.
The deeper the pond, the longer the response time to weath-
er or plant loading changes. Pond storage capacity should at
least equal the volume circulated in 24 hours to take advantage
of night cooling, as well as to even out temperatures resulting
from changes in plant loading. It is commonly accepted that a
depth of 8 to 12 feet is necessary to prevent large diurnal
variations in temperature. For depths less than 5 feet, there
is a tendency for accelerated aquatic growth. If a pond is too
shallow, wind-induced mixing will likely predominate, preventing
the formation of density-induced currents which disperse heat
into outlying regions of the pond. In cases where the cooling
pond acts as a storage reservoir for make-up water, an additional
constraint is generally imposed on pond depth. The normal op-
erating depth should be at least 5 feet (1.5 meters) plus the
maximum expected drawdown to allow the pond to function effec-
tively.
3) Location and Design of Intake and Outfall Structures
In general, the discharge will be located at the surface
with an initial densimetric Froude Number less than unity to re-
duce entrainment. The intake should be located as deep as
practicable to avoid recirculation of influent water and to take
advantage of the pond's cooling capacity as weather and plant
loading conditions change. Ryan recommends building a skimmer
wall, if locating the intake in deep water is not feasible. If
the discharge is directed away from the intake at a reasonable
velocity, i.e., 2 to 3 feet per second (0.6 to 0-9 meters per
second), Kirkwood, et al. (28) estimates that separation of dis-
charge and intake structures by about 40 percent of the pond
length is adequate to prevent recirculation. Local wind ef-
fects should also be considered.
4) Wind Effects
A pond should be designed so that the prevailing wind dur-
ing the summer is directed from the condenser intake to the con-
denser discharge, thus avoiding recirculation during the pond's
most critical season. The most common effect of wind is the
vertical mixing caused by wind-generated waves. Only a very
shallow pond or the topmost layer of a deeper pond is directly
affected. Wind-induced currents are a secondary effect which
forces warmer waters into outlying regions of the pond and'
thereby, increases its effective area. A third effect is the
piling up of warm water by the wind on the pond shore. Tilting
of the heated layer-cold pond water interface may be caused by
the wind and result in increased recirculation problems.
57
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5) Density-Induced Current Effects
Density differences within the warm plume and between the
plume and the pond water will cause lateral spreading. In gen-
eral, wind-induced currents are an order of magnitude greater
than those induced by density disparity. Density-induced cur-
rents are, in turn, an order of magnitude greater than those in-
duced by pumping. As noted above, density-induced currents
assist in improving the active area of a cooling pond.
4.2.5 Design and Size of Cooling Ponds
4.2.5.1 Design of Cooling Ponds—
The design of a cooling pond is affected by the local cli-
matic, topographic, and hydrological characteristics of the
site. The construction of cooling ponds is normally limited to
placing dikes or low dams to take advantage of natural topo-
graphy. Excavation is unrealistic for large ponds; the cost of
excavating an entire pond would normally be prohibitive. Pre-
sently, the design of ponds is still very much of an art. Much
more work remains to be done in defining appropriate criteria
and in selecting design procedures.
One example of pond construction using dikes and dams is
that for the Cholla Plant in Holbrook, Arizona (29). The pond,
shown in Figure 4.13, was formed by placing dikes on three sides.
The dikes have a maximum height of 14 feet (4.2 meters) and re-
quired 265,000 cubic yards (202,619 cubic meters) of fill. The
pond has a surface area of 380 acres (154 H) with an average
depth of 9 feet (2.7 meters) and serves a plant of 125-MWe rated
capacity.
4.2.5.2 Sizing of Cooling Ponds—
Mathematical models which adequately encompass the entire
range of features for the description of pond performance are
not available. Hence, experience and simplified analysis pro-
vide the primary basis for the engineering design of cooling
ponds(29).
The most simplified models are the completely mixed flow
model and the slug flow model. These two flow models, combined
with empirical correlations for surface heat exchange coef-
ficient and equilibrium temperature, give a rough estimate of
the pond size required to reject a given heat load.
1) Completely Mixed Pond
Since the completely mixed pond has a nearly uniform tem-
perature, it follows that the drop in temperature from the plant
^ ?H P2 temperature must take place over a small
of the pond. For such a condition to exist, the size
58
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of the pond must be large and the mixing effective.
The energy balance for the condenser and pond require that:
/>CWW(T - T ) = KA(T - T ) (4.16)
**" C Q
where:
p = density of circulating water.
GW = specific heat of water.
W = volumetric flow rate of circulating water.
1^ = hot water temperature leaving the condenser.
TC = cold water temperature out of the pond
(= pond surface temperature, T in
Equation (4.15)). s
K = surface heat exchange coefficient.
A = pond area.
T = equilibrium temperature of the pond.
From Equation (4.16) the required surface area for a completely
mixed pond is:
_ /OCWW (Th - Tc) 7)
K (Tc - Te)
2) Slug Flow Pond
Most man-made ponds are more closely represented by a slug
flow model. The energy balance for the simplified slug flow
model is:
yoC^-dT = -K (Tw - Te)-dA (4.18)
Integration of Equation (4.18) gives the classical exponential
decay equation for constant TQ,p , Cw, and W:
T - T /
— - - = exp (-
T T \
KA
59
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Solving for the area of the pond gives:
W \ /Th - T
Equations (4.17) and (4.20) must be used in conjunction wit* cor-
relations for the heat exchange coefficient, K, and equilibrium
temperature, Te/ such as those proposed by Brady et al.U3).
Brady's correlations are:
T = TS + Td (4.21)
2
/3= 0.255 - 0.0085T + 0.00204T2 (4.22)
f (U) = 70 + 0.7 u2 (4.23)
K = 15.7 + O+ 0.26) ' f(u) (4.24)
T = Tj + Qs (4.25)
e d K
where:
T = average temperature, °F.
T, = dewpoint, °F.
T - water surface temperature, °F.
5
18 = slope of the saturated vapor pressure
curve, mm Hg/°F.
f (u) = wind speed function,- Btu/f t2-day-mm Hg.
u = wind speed, mph.
*\
Q_ = gross solar radiation, Btu/ft -day.
9
K = surface heat exchange coefficient,
Btu/ft2-day-°F.
To facilitate computation of K, a design chart has been prepared
by Brady et al. and is given in Figure 4.14. This figure al-
lows direct determination of K for the given wind speed and the
average temperature, T. The dew point, gross solar radiation,
and wind speed for different regions of the United States can
be found in the "Climatic Atlas of the United States" (30) .
60
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4.3 SPRAY CANALS
4.3.1 General Description
The power spray ponds or canals are extensions of cooling
ponds and cooling tower technologies. Cooling is obtained pri-
marily by spraying water from a pond or canal into the ambient
air, whereby water is evaporated to effect cooling of the water.
The purpose of spraying the water is to increase the water-to-
air contact area. The result is a significantly increased heat
transfer rate per unit area of pond surface. Thus, the land re-
quirements for spray systems are reduced considerably as com-
pared to those of simple pond systems.
The spray system can be designed as a fixed-pipe pond con-
figuration called a spray pond or as a floating-module canal
system called a spray canal. Spray ponds are generally used for
small heat rejection requirements, such as the ultimate heat
sink for nuclear power stations, whereas spray canals are gen-
erally used for power plant waste heat rejection. An example of
a spray pond system is the ultimate heat sink for the Rancho
Seco Nuclear Power Plant(31). The discussion which follows is
primarily concerned with spray canals.
The floating spray system can use any one of a number of
different, commercially available modules. The spray modules
are anchored in the discharge canal or pond. Each module is
complete with a float-mounted pump and spray heads. One such
module is shown in Figure 4.15. The module consists of four
spray nozzles mounted on a 120-foot length of pipe. The entire
assembly floats in the water with the spray nozzles above the
water surface. The module is equipped with a 75-horsepower motor
and a 10,000-gpm capacity pump. Modules are placed in a canal
with the axis of each module parallel to the stream flow, also
shown in Figure 4.15.
Spray canal cooling is a relatively new cooling concept
which is currently in use at a small number of power plants. The
performance and cost of the spray systems are competitive with
wet cooling towers. The possibility of using them, however,
will depend on the availability of land and the cost at the site,
since the construction of the canal is one of the major cost
components.
4.3.2 Heat Transfer - Performance of Spray Module
Heat transfer from a spray canal is primarily accomplished
through evaporation and convection. Radiation modes of heffc
transfer, such as those affecting a cooling pond, are negligible
because of the small canal surface.
61
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Since the operation of a spray canal is thermodynamically
similar to an evaporative cooling tower, the module performance
can be described by an equation identical to Merkel'a equation.
This performance equation, as applied to spray modules, is
called the Ntu-equation:
/
H(T
W
where:
Ntu = number of heat transfer units,
dimensionless .
Cw = specific heat of water.
TC = sprayed water temperature
(temperature of the sprayed and
cooled water before it re-enters
the canal water body) .
T, = canal water temperature at spray
nozzle intake.
H(TW) = enthalpy of saturated air at water
temperature, T .
H(Twb) = enthalpy of saturated air at local
wet bulb temperature in the spray
field, Twb.
The derivation of Equation (4.26) is given in Reference 32; it
is similar to that given in Section 4 for evaporative towers.
In the derivation of Merkel 's equation for towers, the
energy balance on the air and water for a spray yields:
c (A
ATW Cw — (4
where:
AH = change of air enthalpy per unit mass
of dry air as the air passes through
the spray field.
62
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ATW = cooling range of spray.
g = liquid (water) to gas (air) ratio, dimensionless
In the case of an open spray, however, L/G is not well defined
because there is no control over the air flow. As a result, an
average local wet bulb temperature inside the spray field must
be used in the evaluation of the Ntu.
The number of transfer units can be determined in principle
from the average dynamic and thermodynamic behavior of droplets.
In practice, Ntu is obtained either from experiments on a single
module or by calculations from system performance using the
approximate Ntu equation given below(33,34) :
C
Ntu = - w h " C _ (4.28)
where:
T = local wet bulb temperature of
wb air inside the spray field.
H(Th) = saturation enthalpy of air at Th.
H(TC) = saturation enthalpy of air at Tc.
4.3.3 Design and Performance Parameters
The design parameters to be considered in sizing spray
canal systems for a specific heat load using standard modules
are: 1) cooling range and water flow rate, 2) approach to the
wet bulb temperature, 3) ambient conditions (dry and wet bulb
temperatures, wind speed and wind direction), and 4) number of
modules per pass.
The wet bulb temperature, cooling range, and approach
affect the canal performance in a similar manner as in wet cool
ing towers. The extent to which ambient wind conditions affect
a spray system's performance depends on the volume of air pass-
ing through the spray region. High wind speeds permit more
efficient heat transfer to the atmosphere, whereas low wind
speeds hinder effective interaction of the spray and ambient
air as illustrated in Figure 4.16. These data were obtained
experimentally by Hoffman and are presented in Reference -54.
Wilson(36), using the same experimental_d_ata as Hoffman, touna
a maximum in the performance curve of Ntu versus wind speed in
63
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the 9 to 12 mph range. Wilson suggests that the reduction in
performance at higher wind speed is due to the deformation of
the spray umbrella. The commonly used design wind speed is 5 mph.
For optimum thermal performance, a spray system canal should
be placed perpendicular to the prevailing summer or design wind
direction. A long, narrow canal that minimizes recirculation
will perform better than a wide canal with many spray module
units in the pass. Figure 4.17 shows three possible canal ar-
rangements for spray cooling systems(37).
4.3.4 Spray Canal Design
There are two commonly used design approaches for sizing
a spray canal system and calculating its off-design performance.
A review of the different methods is given by Ryan(35), and
Ryan and Myers (34). Each method is based on a performance model
which consists of:
1. A model for the thermal efficiency of a single
module as a function of water temperature, wet
bulb temperature, and wind speed
2. A model which relates the individual module
performance to the canal performance
4.3.4.1 Canal Design Using System Model—
The system model assumes the water flows in parallel pat-
terns without transverse mixing between each row of modules;
that is, each row of modules is treated as a separate channel.
A fraction of the flow in the channel is pumped through the
nozzles of each module. The water is cooled and remixed with
the remaining flow in the channel. The mixed flow then proceeds
to the next module.
The analysis begins with the condenser discharge end of
the canal where the water temperature, wind speed, and local
wet bulb temperature of the first module in the first row are
known. The air flow is assumed to be perpendicular to water
flow (Figure 4.17). This condition can be accomplished in de-
sign by laying out the canal such that the direction of water
flow is perpendicular to the prevailing wind at the site. The
temperature of the sprayed water is obtained from a module per-
formance model, and the temperature of the water leaving a pass
is obtained from the ratio of pumped flow to channel flow. As
the air flows across the modules, the local wet bulb temperature
increases from the ambient wet bulb temperature as a result of
heat and mass transfer from the upwind modules. An empirical
correction factor, i.e., an increase in wet bulb temperature of
1UF to 2UF, is used to account for this effect.
64
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Referring to Figure 4.18, the steady state canal energy
balance for the ith pass requires that:
L [Ti+l,n - Ti,n] ' HS [] Ti,n + N ^ i,n <4'30)
The temperature (Tc)i/n can be obtained from module performance
correlations provided'by manufacturers. With that, the variables
in the righthand side of Equation (4.30) are known for each_mod-
ule of the first pass, and the canal water temperature leaving
each module of the first pass, T3 n (n=l, 2, N) can be cal-
culated. The average mixed canal'water temperature entering the
second pass is calculated as follows:
N
Tn (4.31)
2 = -±-
n=l
The procedure is repeated until the mixed canal water temperature
-Leaving the last pass is equal to the design cold water tempera-
ture, TC. The design calculations are completed and the number
of passes required is determined.
65
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The above design procedure requires proprietary information
concerning module performance curves and wet bulb temperature
correction factors. To circumvent the difficulty of obtaining
proprietary design information, canal system performance curves
supplied by a manufacturer can be used to construct simplified
design curves, such as the one shown in Figure 4.19. This fig-
ure was developed by the Tennessee Valley Authority and present-
ed in Reference 34.
The use of the design curves in Figure 4.19 for determining
the number of modules required to dissipate a given heat load
is illustrated as follows. Consider a plant with a cooling
water flow of . 5 x 106 gpm, a hot water temperature of 100 F, and
a condenser cooling range of 15°F. Other design conditions are:
cold water temperature is 85°F, wind speed is 5 mph, and wet
bulb temperature is 60°F.
Referring to Figure 4.19, the number of sprays per million
gpm for water temperatures of 100°F and 85°F are_245 and 453,
respectively. Since the design water flow rate is 0.5 x 10
gpm, the total number of modules is equal to: (453 - 245) x
0.5 = 104 modules, for a canal using 4 rows per pass.
4.3.4.2 Canal Design Using Ntu Model —
The same procedure described in the previous section can be
used in the design of a spray canal incorporating the Ntu module
performance model and associated wet bulb temperature correc-
tions. In numerical form, the Ntu model is as follows:
cw
-------
models should be done with caution.
4.3.5 Mechanical Design of Spray Modules(38)
A floating spray module consists of a pump and motor, mani-
fold, floating platform, and nozzles. Continuous exposure to
highly humid conditions requires special design precautions.
The motor is one of the key components in the operation of the
system, and normal fan-cooled motors have been the source of a
major operating problem for spray modules. Even with special
seals and covering shrouds, water entering the motor has
caused difficulties.
Use of a completely sealed water-cooled motor appears to
have solved the problems associated with this highly humid con-
dition. The motor must have a continuous spray of water to as-
sure long life, and the spray pattern from the nozzles should be
designed to provide cooling of the motor. Corrosion resistant
coatings should be used to protect the casing from corrosion
which could lead to leakage into the motor windings or bearings.
Axial flow propeller pumps are used for spray nozzle cool-
ers. These are suitable for spray cooling applications, because
of their relatively high efficiency at low head and high flow
operating conditions. This high efficiency requires that close
tolerances be used throughout the pump design. Also, straight-
ening vanes are used to ensure uniform flow conditions into the
propeller. A typical motor-pump assembly(39) is shown in Figure
4.20.
The manifold system must be designed to distribute the
water to the nozzles effectively while maintaining a low head
loss. As with the pump, the manifold system should be well pro-
tected against corrosion. Fabrication with stainless steel or
other corrosion-resistant materials is recommended in certain
applications; otherwise, effective protective coatings should
be used. A typical manifold system is shown in Figure 4.15.
In addition to supporting the primary structure, the floats
should be sized so that they provide a stable working platform
for maintenance and repair. The float should be completely fill-
ed with a closed-cell polyurethane foam to provide a secondary
flotation system in the event of shell failure. If the float
is made of fiberglass, an internal steel structure must be in-
corporated into the float design to ensure that the fiberglass
is not required to carry the structural loads. Figure 4.20
shows a flotation system attached to the pump-motor system.
67
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4.4 DRY COOLING TOWER SYSTEMS
4.4.1 General Description of Dry TowerCooling Systems
Dry cooling towers generally employ finned-tube heat ex-
changers to reject heat by circulating water inside the tubes
and by passing the atmospheric air over the outside tubes and
fin surfaces. Typical kinds of finned-tube construction are
shown in Figure 4.21(40). In contrast to the wet cooling sys-
tems previously described, the heat transfer mechanism is con-
vective heat transfer rather than heat and mass transfer between
the water being cooled and the cooling air. The absence of
evaporative heat exchange eliminates the make-up water require-
ment and the formation of vapor plumes which constitute the
major disadvantages of wet cooling systems.
Dry towers can be of the mechanical draft or natural draft
type. In a mechanical draft tower, ambient air is induced or
forced by fans to pass over the heat transfer surface. In mechan-
ical draft towers, air flow is controlled by use of either vari-
able fan speeds or variable pitch blades. The natural draft tow-
er depends^on the air density difference in the atmosphere and in
the tower to produce the buoyancy force for inducing the air flow.
The air flow rate can be controlled by the use of louvers or
dampers.
Various studies(41-44) have indicated that dry tower
cooling systems have both high capital cost and severe operating
penalties. The high capital cost results from the need for ex-
tensive finned-tube heat exchanger surface while the operating
penalties result from the high condensing temperatures experi-
enced during peak ambient conditions. Because of the high capi-
tal and operating costs, dry tower systems are not widely used
in the power industry at the present time. Only a relatively
small number of existing or new power plants are currently em-
ploying dry cooling systems as listed in Table 4.1(45,46). How-
ever, it is anticipated that dry cooling, especially in combina-
tion with wet cooling, will become more prevalent in the near
future for power plant application as available water for evapora-
tive cooling systems becomes limited and/or costly(21,41,42 ,44).
4.4.2 Types of Dry Cooling Systems
There are two alternative dry cooling systems which employ
dry cooling towers for power plant applications. These are the
direct dry cooling system and the indirect cooling system.
4.4.2.1 Direct Dry Cooling System—
The direct dry cooling system, alternatively called the
direct condensing dry cooling system, is shown schematically in
68
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Figure 4.22. In this system, the extended surface air-cooled
heat exchangers of the dry tower serve to transfer waste heat
to a heat sink and as a condenser in which the turbine exhaust
steam is condensed directly on the inside tube surface. Large
ducts are used to transport the exhaust steam to the heat ex-
changer coils.
After the steam condenses in the dry tower, the condensate
is pumped back to the boiler feed circuit. The cooling system
components are under vacuum, and provision is made for extrac-
tion of non-condensable gases. To save space and to minimize
the length of exhaust steam ducting, and, consequently, the
pressure drop in the ducts, the air-cooled condenser (dry tower)
for small power plants can be installed on the roof of the tur-
bine building. The present direct dry cooling systems utilize
mechanical draft exclusively to produce the required air flow.
The finned tubes in the dry tower are generally laid out
in chevron (AA-shape) patterns in a parallel-flow, a counter-
flow arrangement or a combination of the two as shown in Figure
4.23(45) .
In the parallel-flow arrangement, the steam flows downward
from the headers at the top. The pressure drop along the inside
of finned condenser tubes is accompanied by a temperature re-
duction in the saturated steam. As the steam condenses in the
tube, continued cooling of the condensate in the lower part of
the tube tends to result in sub-cooling of the condensate. This
increases oxygen absorption with attendant corrosion problems,
and at ambient temperatures below 32°F (0°C) , it can lead to
freezing of the condensate.
In the counterflow arrangement, the exhaust steam enters
at the bottom and flows upward against the downward flowing
condensate. This arrangement eliminates the condensate subcool-
ing problem, but provides reduced heat performance. To combine
the advantages of both arrangements, current designs use a com-
bination of the two, wherein the condensation of the final
fraction of steam takes place in a counterflow section.
The world's largest direct dry cooling system for power
plant application is the one constructed for the 330-MWe mine-
mouth power plant of the Pacific Power & Light Company and the
Black Hills Power & Light Company at Wyodak, Wyoming. The air
cooled condenser arrangement for this station is shown in Figure
4.24(47). This system began operation in 1978.
4.4.2.2 Indirect Dry Cooling System—
There are two variations for the indirect dry cooling sys-
tem. One of the indirect systems utilizes a spray or contact
69
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condenser. This system is often referred to as the Heller Sys-
tem(44,45,48) because it was first proposed by Dr. Lazlo Heller
at the World Power Conference in Vienna in 1956. The other ar-
rangement uses a surface condenser.
The Heller System is shown in Figure 4.25. Here the steam
leaving the turbine is condensed by mixing with cooling water in
a direct contact condenser. A typical direct contact condenser
is shown in Figure 4.26(49). A portion of the condensate/cool-
ing water mixture, equivalent in mass flow rate to the turbine
exhaust steam, is returned to the boiler feed circuit, while the
balance is circulated through the dry tower heat exchanger. The
cold water returning from the dry tower is then sprayed again
into the condenser for the condensation process. The circulat-
ing water flows in a closed circuit so that no water is lost due
to drift and evaporation.
The indirect dry cooling system with a surface condenser
is shown in Figure 4.27. In this system, the cooling water
circuit and the steam/feedwater circuit are completely separated.
Turbine exhaust steam condenses on the outside of the condenser
tubes, and the condensate is pumped back to the boiler feed cir-
cuit without any contact with the cooling water. The cooling
water flows in a closed circuit through the condenser and the
dry tower heat exchanger.
4.4.2.3 Comparison of Direct and Indirect Dry Cooling Systems—
The direct system has a thermodynamic and operating advan-
tage over the indirect system in that it does not require the
use of a condenser and an intermediate loop.
The major disadvantages of the direct system include: 1)
the large-bore exhaust steam pipes which transport the steam to
the heat exchangers are often difficult to accommondate, 2) the
extensive vacuum system is susceptible to air leakages, 3) a
large volume of air must be evacuated during startup, and 4)
the heat exchangers must be located close to the turbine build-
ing in order to limit the pressure drop in the exhaust steam
piping.
Traditionally, it has been stated that direct systems would
be best suited to units not exceeding 200 MWe; however, the
present operation of the 330-MWe Wyodak unit indicates'that
units over 200 MWe are possible using direct dry cooling.
4.4.2.4 Comparison of Spray Condenser and Surface Condenser—
A spray condenser offers the following principal advantages
as compared to a surface condenser:
70
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1. Since the terminal difference is nearly zero,
it is possible to achieve a better vacuum with
the same warm water outlet temperature.
2. The improved heat transfer performance results
in a smaller size and, consequently, lower
cost of the condenser and less required head-
room under the turbine .
3. The omission of condenser tubes reduces first
cost, operational problems (fouling, corrosion),
and eliminates the possibility of raw water
leaking into the feedwater circuit.
The major disadvantage is the fact that feedwater and the
cooling water are mixed in the spray condenser which imposes
the need to use feedwater-quality water in the cooling system.
Since the cooling water flow may be 30 times as great as the
feedwater flow, a large amount of feedwater-quality water is
required .
In nuclear application, however, the use of the surface
condenser is the best and potentially the only choice because
of possible radioactive contamination of the turbine exhaust
steam. The use of the surface condenser also permits greater
flexibility in the heat rejection circuit, e.g., the wet/dry
cooling systems described in Section 5 and the ammonia dry
cooling system described in Section 6.
4.4.3 Heat Transfer in Dry Tower
The heat transfer mechanisms which take place over the
exterior of the finned-tube heat exhanger of a dry tower involve
mainly convection. The overall thermal resistance to heat
transfer from water or condensing 'Steam flowing inside the _ tubes
to the air flowing over the outside tube-and-fin surfaces is
composed of the following series components:
1. The tube-side (water or steam) film resistance, rt
2. The tube-side fouling resistance to the conduction
of heat through fouling deposits on the inside tube
wall,
3. The conduction resistance of the tube wall, r
4. The bond resistance between fin base, and tube
71
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5. The air-side fouling resistance to the conduction
of heat through fouling deposits on the outside
tube wall, r^
6. The air-side convective film resistance, r|
Thus, the overall thermal resistance R is equal to:
R = 4 + r£ + rm + rf + rj + r^ (4.33)
Of the six individual thermal resistances, the air-side
film resistance is the dominant component. The reciprocal of R
is called the overall heat transfer coefficient or overall ther-
mal conductance.
Correlations of friction factor and heat transfer coeffi-
cients are available in open literature for calculating the
corresponding air-side and tube-side film resistances and the
air-side and tube-side pressure drops.
On the water-side, the friction factor can be predicted by
the classical Blasius equation(50) for flow in circular tubes.
The water-side heat transfer coefficient can be calculated by
the Dittus-Boelter correlation for turbulent flow(50). The air-
side performance parameters are not as well established as their
water-side counterparts. A number of correlations are, how-
ever, available. The commonly used ones are those developed by
Robinson and Briggs(51) and Briggs and Young(52) for air-side
pressure drop and heat transfer, respectively.
The metal resistance of the tube wall can be easily calcu-
lated. However, the fouling resistances and the bond resistance
are not generally available and should be obtained from heat ex-
changer manufacturers.
Using the overall heat transfer coefficient, there are two
standard methods used to calculate the heat transfer from the
dry heat exchangers. These two methods are briefly described
below:
1) LMTD Method
The total heat transfer to the air is expressed by the
following formula:
Q = U-(LMTD)-A-F (4.34)
where:
Q = total heat transfer of the exchanger, Btu/hr.
72
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U = overall coefficient of heat transfer
Btu/hr-ft2-°F.
LMTD = logarithmic (natural) mean temperature
difference, °F.
Fg = dimensionless correction factor for flow
arrangement (crossflow usually exists in
a dry tower and F = 0.95 to 1.0) (see
Reference 53).
A = surface area on which U is based, ft2.
The logarithmic mean temperature difference LMTD is the
temperature driving force for the transfer of heat between the
fluid inside the tubes and the air flowing across the tubes.
The LMTD is expressed by the following formula:
LMTD = GTTD - LTTD (4>35)
In
["GTTD"|
[LTTDJ
Figure 4.28 illustrates the basic temperature diagram and
the definitions of GTTD and LTTD as it applies to an indirect
dry cooling tower system with surface condenser.
In evaluating the overall heat transfer coefficient, U,
using the correlations discussed in Section 4.4.3, the fin ef-
ficiency must be taken into consideration as illustrated in
Reference 53. The fin efficiency is defined as the ratio of the
heat transferred across the fin surface to the heat which would
be transferred if the entire fin surface to the heat which would
of the fin base.
Equation (4.34) can be combined with the air energy balance
and water energy balance equations to determine the performance
or the required size of the heat exchanger for a particular
plant heat load requirement. Examples using this procedure to
size dry towers are illustrated in Reference 54.
2) The E-Ntu Method
Calculation of heat transfer in dry heat exchangers can
also be determined using the so called effectiveness-Ntu method.
The method is defined in the following terms: 1) the near ex
changer effectiveness (E), 2) the number of heat transfer units
(Ntu), and 3) the ratio of heat capacity rates of the sneii-
and tube-side fluids (R).
73
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For a given flow arrangement, e.g., crossflow arrangement
which is generally used in a dry cooling tower, the effective-
ness E is a function of Ntu and R(55,56). Tables in terms of
the above mentioned three factors can be found in Reference 56.
These terms are further described below:
1) The Heat Exchanger Effectiveness (E)
This is defined as the ratio of the actual rate of heat
transfer Q to the maximum rate of heat transfer permitted by
the Second Law of Thermodynamics. The equation for the effec-
tiveness of air-water heat exchangers in dry towers under normal
operating conditions, where M C < M C , is:
E =
a pa
w pw
= MwCPW
MaCp
- T . )
a, in'
(4.36)
where:
Ma = mass flow rate of water and air
respectively .
C , C = specific heat of water and air
p pa respectively.
T . TW . = temperature of water in and out
' n/ ' of the heat exchanger respectively
'
= temperature of air in and out of
the heat exchanger respectively.
2) The Number of Heat Transfer Units (Ntu)
This term is a measure of the size of the heat exchanger
from the point of view of heat transfer and is defined as:
Ntu = UA
where:
U
A =
Macpa
overall heat transfer coefficient of the
heat exchanger.
the heat transfer area on which the over-
all heat transfer coefficient is based.
(4.37)
74
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3) Heat Capacity Ratio (R)
R is defined as:
(4'38>
where it is assumed that, under normal operating conditions
Macpa <
Both the LMTD and the effectiveness Ntu methods can be used
in the design and performance calculation for dry cooling towers.
The LMTD method is more convenient to use for the design of heat'
exchangers to given temperature specifications, i.e., when the
inlet and exit temperatures of both fluids are known. The ef-
fectiveness Ntu method, on the hand, is preferrable for sizing
dry towers using standard heat exchanger modules, i.e., the sur-
face area is known, but the fluid exit temperatures must be de-
termined .
4.4.4 Design of Dry Cooling Towers
The design of the dry tower includes the sizing of fin-tube
heat exchanger modules for the plant heat load and air moving
equipment to provide the necessary air flow.
In mechanical draft towers, the air moving equipment con-
sists of large diameter axial-flow fans. The finned tubes are
assembled into modules with common inlet and outlet headers to
form cells. Each cell is served by one or more fans. A suffi-
cient number of cells is sized to satisfy the heat transfer re-
quirement of the power plant. The cells are arranged "in-line"
or "back-to-back" to form towers.
In natural draft towers, the tower stack structure above
the fin-tube modules induces the air flow across the modules.
The tube modules are located at the base of the tower in alter~
native arrangements. Two arrangements are shown in Figure 4.29.
1. Vertically around the bottom of the tower
2. A-frame bundles with tubes in the horizontal
position and placed inside the tower
The mechanical draft tower can also be designed in a
cylindrical arrangement with fans on top of the tower. Tnis ae-
sign is called the circular or round mechanical tower.
75
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4.4.4.1 Sizing of Mechanical Draft Dry Towers—
To size a mechanical draft dry tower used in an indirect
dry cooling system using water with commercially available cells
to perform a required heat duty, the number of cells needed is
determined by the water velocity through the cell tubes, the
number of tubes per cell, the number of tube passes and the tube
size.
The total tube-side cross-sectional area, Aw, for water
flow in a cell is given by:
.
A = 1 • (4.39)
w 4 Np
where :
D^ = inside diameter of tube.
Nt = number of tubes in a cell.
N = number of tube passes for water flow.
The water flow rate per cell, WG, is given by:
Wc = /OAW Vw (4.40)
where:
P = density of water.
Vw = water velocity.
The number of cells required is given by:
N = -— (4.41)
where :
W = total mass flow rate of water for the dry
tower.
To determine the proper Wc and then the number of cells re-
quired, the velocity V is varied such that both the water-side
and air-side energy balances are matched with the heat transfer
equation given by the LMTD method or the Ntu method as dis-
cussed in Section 4.4.3.
76
-------
4.4.4.2 Sizing of Natural Draft Dry Towers —
In sizing a natural draft tower, the heat transfer equation
for the tower (Section 4.4.3) must be solved in conjunction with
the draft equation for the air flow. The draft balance in a
natural draft tower has been treated in Section 4.1.5. A simpli
fied equation developed for the natural draft dry tower by Rozen
man and Pundyk(57) is given below:
2Ti2
'"air •(•>• , -T + (4'42)
where:
c = a constant combining fin-tube module
geometry and air physical properties.
= effective height of the tower.
M . = mass flow rate of air through the
air tower.
a = a constant related to fin-tube module
friction characteristics (1.7 to 1.95).
T,, T2 = entering and exit air temperature.
4.4.4.3 Design Parameters —
In designing dry cooling towers with commercially available
fin-tube modules, the major design parameters are the cooling
range, RA, and the approach temperature, APP, or the initial ter-
minal temperature difference, ITD. This can be seen from the
heat transfer equation given by the Ntu method for sizing dry
towers with fixed design modules and from the definition of ITD,
wherein,
QTower =
ITD = APP + RA
where :
(N)mo^ = number of modules.
ITD = initial temperature difference.
(MCp)mod = heat capacity of the air flow per
module .
77
-------
E = heat exchanger effectiveness.
APP = temperature difference between the
cold water temperature and the dry
bulb temperature of ambient air.
RA = cooling range of the tower.
For fixed module design, the air mass flow rate and the terms
(MCp)mod and (E) are constant. Thus, the ITD determines the
number of modules required for a given heat duty, i.e., the
number of modules is inversely proportional to the ITD value
selected. The variation of ITD can be achieved by varying the
range or approach or both.
4.4-5 High Back Pressure Turbines
The low heat transfer coefficients of the finned surface
require large dry cooling surfaces to effect the required
heat transfer during high ambient temperatures. One method
which can be used to reduce the size of the dry cooling surface
(and, consequently, its capital cost) is the use of a steam-
turbine capable of operating at turbine back pressures up to 15
in. HgA to increase the temperature potential for heat transfer.
The turbine can be either a modification of a conventional tur-
bine or a special design solely intended for dry cooling appli-
cations.
Turbine-generator manufacturers have studied the design
problems associated with the development of high back pressure
turbines specifically for dry cooling. In the United States,
both General Electric (GE) and Allis-Chalmers have completed de-
signs of high back pressure turbines for both fossil and nuclear
applications. However, only GE is offering a 3600-rpm unit com-
mercially, which is capable of operating at 15 in. HgA in sizes
up to 750 MWe for fossil reheat application. As indicated in
Reference 48, Allis-Chalmers has postponed the model testing of
the last stage of its high back pressure turbine. The Allis-
Chalmers designs are shown in Figure 4.30 along with a con-
ventional turbine of approximately the same rating. The dif-
ference in size is considerable.
4.4.6 Operating Experience of Dry Cooling Towers
Although dry cooling has been used for industrial cooling
for many years, it was only recently that the applications were
made to the rejection of heat from steam-electric power plants.
Most of the operating experience, however, was obtained in
Europe or Russia. As indicated in Table 4.1, the first power
plant installation with a dry cooling system having a rated out-
78
-------
put in excess of 100 MWe was the Rugeley station in Enaland
h bean oeration in 1961.
which began operation in 1961.
The Battelle Pacific Northwest Laboratories (58) conducted a
survey of the European dry cooling tower operating experience
under the sponsorship of the U. S. Energy Research and Develop-
ment Administration. The purpose of the study was to provide a
basis of confidence that dry cooling is a reliable technology
applicable to U. S. operating requirements. The study concluded
that dry cooling system represents a mature and reliable tech-
nology and can be readily applied in the United States.
In the United States in 1977, the only operational dry
cooling systems for power plant applications are the two in-
direct dry cooling systems serving two small units of 3 and 20
MWe operated by the Black Hill Power and Light Company and one
direct dry cooling system at Braintree, Massachusetts (25 MWe)
1977(45). However, one large dry cooling system has been pur-
chased in the United States. This dry cooling system will serve
the 330-MWe station built at Wyodak, Wyoming for the Black Hills
Power and Pacific Power and Light Companies and began operation
in 1978.
4.5 DESIGN AND COST OF CONVENTIONAL COOLING SYSTEMS
4.5.1 General Description
As indicated in Section 3 in order to compare alternate
cooling systems on a common economic basis, several penalty
costs must be included besides the capital cost. In general as
the size of a cooling system alternative becomes larger, its
performance improves and the capital cost of the cooling system
increases, but the penalty cost decreases. At some point, a
minimum exists for the combined cost of capital and penalty, and
this minimum represents the best economic trade-off between the
two costs. The minimum combined cost system is called an opti-
mum or optimized system. Economic and environmental comparisons
of cooling system alternatives are then made utilizing the costs
of these optimum systems (see Sections 3 and 11).
One document, Reference 59, contains design, performance,
and cost information obtained through an optimization analysis
using the fixed source and fixed demand method as discussed in
Section 3. These data enable adjustments to be made which re-
flect different economic conditions from those used in tne
original design analysis. In the following subsections, the
costs are adjusted to 1978 economic conditions. In addition,
pertinent design, cost and performance data extracted from tnis
reference are also provided to facilitate adjustments to otner
economic conditions.
79
-------
In all the tables presented in this subsection, the names
of the cooling system alternatives have been abbreviated as
follows:
Abbreviated Name Cooling System Name
Mech. Wet Mechanical draft wet tower cooling
system
Fan Wet Fan-assisted natural draft wet tower
cooling system
Nat. Wet Natural draft we.t tower cooling system
Pond Constructed pond cooling system
Spray Canal Power spray module canal cooling system
Mech. Dry Mechanical draft dry tower cooling
system
Nat. Dry Natural Draft dry tower cooling system
4.5.2 Typical Designs and Costs of Conventional Cooling Systems
The capital, penalty, and total evaluated costs in 1978
dollars of cooling systems for fossil and nuclear power plants
are given in Tables 4.2 and 4.3, respectively. The economic
factors for the capital and penalty cost adjustments are given
in Table 4.4.
The capital cost includes the direct and indirect cost
of the major equipment. The direct cost is the cost for the
purchase of the equipment and its installation. The indirect
cost represents the charges for engineering, construction manage
ment, and contingency; this was taken to be 25 percent of the
total direct cost. The major equipment included: . 1) the cool-
ing device (wet or dry cooling towers, ponds or spray canals),
2) the circulating water system (pipelines, valves, motors,
pumps, and structures), and 3) steam condensers.
The penalty cost includes five components which are common
to all the systems. These five components include the costs
assessed to account for the generating capability and energy
losses associated with the ambient effect on cooling system
operation, the generating capability and energy required for
operating the fans and pumps,, and the maintenance requirements
for the cooling system. The penalty costs for making up the
generating capability represent costs for generating equipment
elsewhere in the utility system. For the costs lis?ed il
80
-------
4.2 and 4.3 this generation equipment is assumed to be similar
base load units, either fossil or nuclear units, as the re-
ference plant. The penalty costs for making up the energy loss-
es represent the capitalized costs which will accrue over the
lifetime of the reference plant. The cooling system maintenance
cost represents charges to a cooling system for services which
include periodic maintenance and replacement of parts, calculat-
ed as percentages of direct capital costs of the major equipment.
Although prepared specifically for nominal 1000-MWe power
plants, these costs on a dollar per kilowatt basis are approxi-
mately correct for stations varying in size from 400 to 1200 MWe.
The design conditions and size of the cooling system for 1000-
MWe plants are given in Tables 4.5 and 4.6. A brief description
of the major equipment is given in Table 4.7.
4.5.3 Adjustment of Capital and Penalty Costs
The costs given in the previous section have been adjusted
to 1978 dollars and a particular set of economic factors from
the data given in References 41 and 42. These costs, given in
dollars per kilowatt and mils per kilowatt-hour, can be used
to give quick and rough estimates of the costs of different
cooling systems for specific power plants. To obtain more
accurate estimates, the capital and penalty cost components
should be adjusted from the base values given in Reference 59
to the specific economic and operational factors applicable to
that particular plant and should include additional capital or
operating cost components, such as the make-up water supply,
purchase and treatment costs, blowdown disposal costs, etc.(41,
60). The capital cost elements taken directly from Reference 59
are provided in Tables 4.8, 4.9, and performance data derived
from this reference are given in Tables 4.10 and 4.11.
81
-------
TABLE 4.1. POWER PLANTS OVER 100 MWe USING DRY COOLING
SYSTEM(46,48)
Dry Cool-
ing Sys-
tem Type
INDIRECT
DIRECT
Power
Station
Gyongyos 1
(Hungary)
Rugeley
(England)
Ibbenburen
(West
Germany)
Gyongyos 2
(Hungary)
Razdan
(USSR)
Grootvlei V
(South
Africa)
Schmehausen
(West
Germany)
USTAUtrillas
(Spain)
Wyodak
(USA)
Rating
MWe
100
100
120
150
220
220
220
220
220
220
220
220
200
360
160
330
Heat Re-
jection
106 Btu/hr
425
425
575
645
905
905
956
956
956
956
956
956
1139
1500
667
1694
Maker
Hoterv
Hoterv
EE/Heller
GEA/Trans-
elektro
Koterv
Hoterv
Transelektro
Transelektro
Transelektro
Transelektro
Transelektro
Transelektro
M.A.N./GKN
GEA/BO
GEA
GEA
Commis-
sion
Date
1969
1970
1962
1967
1971
1972
1970
1971
1972
1974
1975
1976
1971
1976
1970
1978
82
-------
TABLE 4.2. COSTS OP TYPICAL CONVENTIONAL COOLING
SYSTEMS FOR FOSSIL POWER PLANTS (1978
DOLLARS)*
Cooling System
Once-through
Mech . Wet
Nat. Wet
Fan Wet
Pond
Spray Canal
Mech. Dry
Nat. Dry
Capital
Cost,
$/kW
15.16
21.57
26.96
27.77
38.50
23.99
34.29
37.87
Penalty
Cost,
$/kW
6.36
27.72
21.02
22.73
32.74
25.63
125.04
115.98
Total Evaluated
Cost
$/kW
21.52
49.29
47.98
50.50
71.24
49.62
159.33
153.85
Mills/kWH
0.60
1.35
1.31
1.38
1.95
1.36
4.37
4.22
*See page 78 for full name of cooling system which
is abbreviated in this table.
83
-------
TABLE 4.3. COSTS OF TYPICAL CONVENTIONAL COOLING
SYSTEMS FOR NUCLEAR POWER PLANTS (1978
DOLLARS)*
Cooling System
Once-through
Mech. Wet
Nat. Wet
Fan Wet
Pond
Spray Canal
Mech. Dry
Nat. Dry
Capital
Cost,
$/kW
21.03
27.53
29.83
32.36
50.72
25.45
46.89
57.34
Penalty
Cost,
$/kW
5.90
29.18
29.25
25.50
32.10
35.10
164.64
141.84
Total Evaluated
Cost
$/kW
26.93
56.71
59.08
57.86
^82.82
60.55
211.53
199.18
Mills/kWH
0.74
1.55
1.62
1.58
2.27
1.66
5.80
5.46
*See page 78 for full name of cooling system which
is abbreviated in this table.
84
-------
TABLE 4.4. ECONOMIC FACTORS
Cost Year
Plant Capacity Factor
Annual Fixed Charge Rate
Plant Life
Capacity Penalty Charge
Rate* (For capacity loss
at the peak ambient tem-
perature and auxiliary
power)
Energy Cost*
Escalation rate for mater-
ial and labor costs
Cooling System Maintenance
Charge
1978
75%
18%
40 years
$563/kW (nuclear)
$450/kW (fossil)
10 mills/kWh (nuclear)
15 mills/kWh (fossil)
7% per year
0.5% of direct capital cost
*These values were adjusted for 1978 from information given in
References(40,41).
85
-------
TABLE 4.5. DESIGN CONDITION AND SIZE OF TYPICAL CONVENTIONAL COOLING SYSTEMS FOR A
1000-MWe FOSSIL POWER PLANT(-S)
Base Plant Condition: Gross Output = 1043 MWe, Heat Rate = 7365 Btu/kWh, Exhaust Pres-
sure = 1.5 in.HgA
Design Ambient Condition: Dry Bulb Temperature = 93°F, Wet Bulb Temperature = 74°F,
Wind Speed = 5 mph
Variable Name
General
Design Cold Water
Temperature , °F
Design Approach, °F
Design Range, °F
Plant Capacity at Cooling
System Design Point, MWe
Design Turbine Back
Pressure, In.HgA
Maximum Turbine Back
Pressure, In.HgA
Design Heat Load, 109
Btu/hr
Condenser
Surface Area, 103 sq ft
Number of Tubes, 103
Tube Length, ft
Once-
Through
57.0
-
15.0
1043
1.50
2.14
4.12
396
37.0
41.0
Mech.
Wet
90.0
16.0
21.0
1020
3.17
3.22
4.20
627
53.8
44.5
Fan
Wet
84.0
10.0
24.0
1026
2.91
2.98
4.18
595
46.9
48.4
Nat.
Wet
90.0
16.0
24.0
1014
3.45
3.66
4.22
590
47.3
47.7
Pond
103.0
29.0
16.0
1000
3.95
4.00
4.27
715
71.8
38.1
Spray
Canal
94.0
20.0
17.0
1020
3.16
3.17
4.20
688
66.5
39.5
Mech.
Dry
131.0
38.0
25.0
938
10.12
11.89
4.48
608
48.2
48.1
Nat.
Dry
131.0
38.0
28.0
932
10.86
12.80
4.50
576
43.3
50.9
CO
CTl
(continued)
-------
TABLE 4,5 (continued).
oo
-j
Variable Name
Coolitig Watar Pump
Circulating Water Flow
Rate.103 gpm
Number of Pumps
Pumping Head, ft. of Water
Pumping Power Requirement,
bph/pump
Rated Pump Motor Size,
hp/pump motor
Terminal Heat Sink
Total Power Requirement,
103 bhp
Terminal Heat Sink Size:
Number of Cells
Tower: Number of Towers
Base Diameter, ft
Tower Height, ft
Fan: Number of Fans/Tower
Fan Diameter, ft
Canal: Number of Modules
Canal Width, ft
Canal Length, ft
Pond Area, Acres
Once-
Through
549
4
23.7
924
1250
_
-
-
-
-
-
-
-
-
-
-
•
Mech.
Wet
400
3
78.1
2952
3500
4.28
-
_. 23
-
-
-
-
28
-
-
-
—
Fan
Wet
348
2
79.2
3915
4500
5.24
-
-
2
226
250
20
28
-
-
-
—
Nat.
Wet
352
2
91.6
4570
5000
.
-
-.
1
385
500
-
-
-
-
-
•
Pond
533
3
33.3
1679
2000
_
-
-
—
~
~
-
-
-
---
-
432
Spray
Canal
494
3
33.2
1555
2000
8.55
-
-
•
••
—
-
-
114
256
3340
—
Mech.
Dry
358
2
44.2
2245
2500
17.77
-
94
™
~
-
28
-
-
-
—
Nat.
Dry
321
2
63.8
2908
3500
_
-
-
1
443
446
-
-
-
-
-
~
-------
TABLE 4.6. DESIGN CONDITION AND SIZE OF TYPICAL CONVENTIONAL COOLING SYSTEMS FOR A
1000-MWe LWR POWER PLANT(59)
Base Plant Condition: Gross Output = 1096 MWe, Heat Rate = 9760 Btu/kWh, Exhaust
Pressure = 1.5 in.HgA
Design Ambient Condition: Dry Bulb Temperature = 93°F, Wet Bulb Temperature = 74°F,
Wind Speed = 5 mph
CO
us
Variable Name
General
Design Cold Water
Temperature, °F
Design Approach
Design Range, °F
Plant Capacity at Cooling
System Design Point, MWe
Design Turbine Back
Pressure, In.HgA
Maximum Turbine Back
Pressure, In,HgA
Design Heat Load, 10
Btu/hr
Condenser
Surface Area, 10^ sq ft
Number of Tubes, 10^
Tube Length, ft
Once-
Through
57.0
-
15.0
1096
1.50
2.13
6.96
670
62.4
41.0
Mech.
Wet
91.0
17.0
27.0
1075
3.85
3.90
7.03
925
70.1
50.4
Fan
Wet
87.0
13.0
29.0
1078
3.64
3.71
7.02
898
65.2
52.6
Nat.
Wet
92.0
18.0
29.0
1069
4.17
4.39
7.05
892
65.5
52.0
Pond
108.0
34.0
17.0
1059
4.65
4.69
7.09
1157
112.0
39.4
Spray
Canal
100.0
26.0
26.0
1056
4.77
4.78
7.10
944
73.5
49.1
Mech.
Dry
135.0
42.0
29.0
933
12.20
14.29
7.52
944
69.8
51.7
Nat.
Dry
129.0
36.0
32.0
940
11.38
13.32
7.49
893
63.0
54.1
(continued)
-------
TABLE 4.6 (continued1
CXI
Variable Name
Cooling Water Pump
Circulating Water Flow
Rate, 103 gpm
Number of Pumps
Pumping Head, ft of Water
Pumping Power Requirement,
bph/pump
Rated Pump Motor Size,
hp/pump Motor
Terminal Heat Sink
Total Power Requirement,
10 bhp
Terminal Heat Sink Size:
Number of Cells
Tower: Number of Towers
Base Diameter, ft
Tower Height, ft
Fan: Number of Fans /Tower
Fan Diameter, ft
Canal: Number of Modules
Canal Width, ft
Canal Length, ft
Pond Area, Acres
Once-
Through
928
7
22.2
835
1000
«
_
_
—
_
_
..
_
_
-
-
—
Mech.
Wet
521
3
79.0
3892
4500
6.07
_
33
-
-
-
-
28
-
-
-
-
Fan
Wet
484
3
75.6
3462
4000
6.66
_
_
2
257
250
24
28
-
-
-
•
Nat.
Wet
486
3
90.3
4153
4500
-
—
_
1
407
527
-
-
-
-
-
™
Pond
834
5
33.7
1594
2000
-
_
-
-
_
-
-
-
—
-
-
565
Spray
Canal
546
4
36.7
1422
1750
8.55
—
-
-
-
-
-
-
114
256
3340
"
Mech.
Dry
518
3
42.4
2077
2500
26.40
-
141
-
-
-
-
28
-
-
-
*
" Nat.
Dry
468
3
51.0
2259
3000
-
-
-
2
397
416
—
-
-
-
~
-------
TABLE 4.7. LIST OF MAJOR EQUIPMENT(59)
Item
Description
Condensers
Each cooling system has three field-
tubed main surface condensers with
fabricated steel water boxes and
steel shell. Each condenser has 1-
inch o.d., 20 BWG gauge, 304 stain-
less steel tubes and a design water
velocity of 7.0 ft/sec. The condenser
has one tube pass for the once-through
cooling system and two tube passes
for the closed cooling systems.
Circulating Water
Pumps and Motors
The circulating water pumps are each
of the vertical, wet pit, motor-
driven type with 4160 volts, 3-phase,
60-hertz motors. The pumps have
carbon steel casings with chrome steel
shaft and bronze impeller.
Terminal Heat Sink
The following are the description of
alternative cooling devices.
A) Mechanical Draft
Rectangular Wet
Cooling Tower
The mechanical draft wet tower cells
or modules are the induced draft,
cross-flow type of concrete construc-
tion with 41 feet fill height. Each
cell has a fan; the fan has a diame-
ter of 28 feet and is driven by a
200-horsepower motor. The cell di-
luent nns ars 71 f00+ ^^ 36 feet
(continued)
90
-------
TABLE 4.7 (continued)
Item
Description
Terminal Heat Sink
(Cont'd)
long, and 54 feet high.
B) Natural Draft
Wet Cooling
Tower
The natural draft wet towers are the
counterflow type with a maximum base
diameter of 500 feet. The hyperbolic
shell is made of reinforced concrete
with a minimum thickness of six inch-
es .
C) Fan-assisted
Natural Draft
Wet Tower
The fan-assisted natural draft tow-
ers are the counterflow type with a
minimum height of 250 feet. The
hyperbolic shell is made of rein-
forced concrete with a minimum thick-
ness of six inches. The maximum num-
ber of fans is 24, with a fan dia-
meter of 28 feet. The fans are
driven by 150-horsepower motors.
D) Power Spray
Modules
Each spray module has four nozzles
mounted on a 120-foot length, 10-
inch diameter carbon steel pipe.
Each is complete with floats and
a pump at the center of the pipe.
(continued)
91
-------
TABLE 4.7 (continued)
Item
Description
Terminal Heat Sink
(Cont'd)
The pump can deliver 10,000 gpm and
is driven by a 75-horsepower motor.
E) Mechanical Draft
Dry Tower
The mechanical draft dry tower cells
are the induced flow type. The cells
are arranged back-to-back to form
towers. Each cell has 776 tubes ar-
ranged in two passes and is equipped
with a 150-horsepower motor and 28-
foot diameter fan. The cell dimen-
sions are 41 feet wide, 61 feet long
and 65 feet high. The tubes are of
1-inch outside diameter admiralty
tubes with aluminum fins.
F) Natural Draft
Dry Tower
The natural draft tower has a hyper-
bolic concrete shell with a maximum
base diameter of 500 feet and a min-
imum thickness of six inches. The
finned-tube heat exchanger modules
are arranged vertically around the
tower base. Each module has 176
tubes in two passes. The tubes are
of 1-inch outside diameter admiralty
tubes with aluminum fins.
92
-------
TABLE 4.8.
CAPITAL COST ELEMENTS OF TYPICAL CONVENTIONAL COOLING SYSTEMS FOR A
1000-MWe FOSSIL PLANT ($106, 1973 DOLLARS)(59)
Equipment *
Item
Circulating (M
Water Structure (L
(T
Circulating Water (E
Pumps & Motors (M
(L
(T
Concrete Pipe (M
(L
(T
Terminal Heat Sink (M
Basins and (L
Foundations (T
Terminal Heat Sink (E
(M
(L
(T
Once-
Through
0.582
1.964
2.546
0.920
0.010
0.080
1.010
0.640
0.699
1.339
-
-
-
—
Mech.
Wet
0.424
0.286
0.710
0.957
0.010
0.063
1.030
0.540
0.560
1.100
0.470
0.710
1.180
1.891
0.019
1.030
2.940
Fan
Wet
0.411
0.283
0.694
0.793
0.009
0.042
0.844
0.540
0.622
1.162
0.280
1.120
1.400
4.128
0.042
2.780
6.950
Nat.
Wet
0.409
0.281
0.690
0.829
0.009
0.042
0.880
0.539
0.621
1.160
0.270
1.060
1.330
5.346
0.054
1.350
6.750
Pond
0.414
0.272
0.686
0.895
0.010
0.061
0.966
0.824
0.864
1.688
-
-
0.650
12.950
13.600
Spray
Canal
0.445
0.301
0.746
0.914
0.010
0.062
0.986
0.829
0.869
1.698
-
-
2.257
0.023
1.880
4.160
Mech.
Dry
0.330
0.220
0.550
0.623
0.007
0.040
0.670
0.800
1.120
1.920
0.180
0.370
0.550
9.821
0.049
1.010
10.880
Nat.
Dry
0.320
0.210
0.530
0.692
0.008
0.040
0.740
0.480
0.560
1.040
0.280
0.900
1.180
8.278
0.042
5.750
14.070
vo
(continued)
-------
TABLE 4,8 (continued)
Equipment
Item
Condensers, Installed (E
(M
a
(T
Electrical Work (E
(M
CL
(T
Sub-Total for the (E
Complete Cooling (M
System (L
(T
Indirect Charges
L
Total Capital
Investment
Once-
Through
2.358
0.012
1.340
3.710
0.124
0.067
0.139
0.330
3.402
1.311
4.222
8.935
2.334
11.269
Mech.
Wet
3.333
0.017
1.600
4.950
0.283
0.213
0.429
0.925
6.464
1.693
4.678
12.835
3.209
16.044
Fan
Wet
3.143
0.016
1.550
4.709
0.233
0.175
0.352
0.760
8.297
1.473
6.749
16.519
4.130
20.649
Nat.
Wet
3.134
0.016
1.540
4.690
0.157
0.130
0.253
0.540
9.466
1.427
5.147
16.040
4.010
20.050
Pond
3.840
0.020
1.740
5.600
0.135
0.073
0.152
0.360
4.870
1.991
16.039
22.900
5.725
28.625
Spray
Canal
3.681
0.019
1.700
5.400
0.392
0.295
0.593
1.280
7.244
1.621
5.405
14.270
3.568
17.838
Mech.
Dry
3.203
0.017
1.560
4.780
0.322
0.242
0.486
1.050
13.969
1.625
4.806
20.400
5.100
25.500
Nat.
Dry
3.043
0.017
1.520
4.580
0.146
0.079
0.165
0.390
12.159
1.226
9.145
22.530
5.633
28.163
vo
L Labor
E Equipment (pump, cooling tower, etc.)
M Material (pipe, cable, etc.)
T Total (L+M+E)
-------
TABLE 4.9. CAPITAL COST ELEMENTS OF TYPICAL CONVENTIONAL COOLING SYSTEMS FOR A
lOOQ-MWe LWR POWER PLANT ($105, 1973 DOLLARS)(59)
Equipment *
Item
Circulating Water (M
Structure (L
(T
Circulating Water (E
Pumps & Motors (M
(L
(T
Concrete Pipes (M
(L
(T
Terminal Heat Sink (M
Basins and (L
Foundations (T
Terminal Heat Sink (E
(M
a
(T
Once-
Through
0.833
2.811
3.644
1.553
0.017
0.140
1.710
1.040
0.999
2.039
-
-
-
Mech.
Wet
0.504
0.344
0.848
1.201
0.014
0.063
1.278
0.798
0.716
1.514
0.670
1.010
1.680
2.713
0.027
1.470
4.210
Fan
Wet
0.514
0.344
0.848
1.150
0.014
0.064
1.228
0.658
0.596
1.254
0.320
1.280
1.600
4.782
0.048
3.220
8.050
Nat.
Wet
0.514
0.334
0.848
1.201
0.014
0.063
1.278
0.338
0.316
0.654
0.280
1.130
1.410
5.930
0.060
1.500
7.490
Pond
0.509
0.339
0.848
1.490
0.016
0.102
1.608
1.246
1.508
2.754
-
-
0.850
16.950
17.800
'•' ''•;, "i;V."
Spray
Canal
0.496
0.340
0.836
1.040
0.012
0.084
1.136
0.924
0.924
1.848
-
-
2.257
0.023
1.880
4.160
Mech.
Dry
0.380
0.250
0.630
0.930
0.010
0.060
1.000
1.190
1.270
2.460
0.270
0.560
0.830
14.726
0.074
1.520
16.320
Nat.
Dry
1 0.360
0.240
0.600
0.979
0.011
0.060
1.050
.0.640
0.580
1.220
0.380
1.230
1.610
14.557
0.073
10.030
24.660
Ul
(Continued)
-------
TABLE 4,9 (continued)
Equipment
Item
Condensers, Installed (E
(M
a
(T
Electrical Work (E
(M
(L
(T
Sub-Total for the (E
Complete Cooling (M
System (L
(T
Indirect Charges
Total Capital
Investment
Once-
Through
3.572
0.018
1.670
5.260
0.184
0.099
0.207
0.490
5.309
2.007
5.827
13.143
3.285
16.425
Mech.
Wet
4.517
0.023
1.910
6.450
0.375
0.282
0.568
1.225
8.806
2.318
6.081
17.205
4.301
21.506
Fan
Wet
4.368
0.022
1.870
6.260
0.303
0.228
0.459
0.990
10.603
1.804
7.823
20.230
5.058
25.288
Nat.
Wet
4.348
0.022
1.860
6.230
0.214
0.176
0.345
0.735
11.693
1.404
5.548
18.645
4.661
23.306
Pond
5.803
0.027
2.270
8.100
0.225
0.122
0.253
0.600
7.518
2.770
21.422
31.710
7.928
39.638
Spray
Canal
4.617
0.023
1.940
6.580
0.413
0.311
0.626
1.350
8.327
1.789
5.794
15.910
3.978
19.888
Mech.
Dry
4.577
0.023
1.920
6.520
0.476
0.358
0.721
1.555
20.709
2.305
6.301
29.315
7.329
36.644
Nat.
Dry
4.328
0.022
1.850
6.200
0.191
0.104
0.215
0.510
20.055
1.590
14.205
35.850
8.963
44.813
L Labpr
E Equipment (pump, cooling tower, etc.)
M Material (pipe, cable, etc.)
T Total (L+M+E)
-------
TABLE 4.10- PLANT PERFORMANCE DATA OP A 1000-MWe FOSSIL PLANT
USING CONVENTIONAL COOLING SYSTEMS(59)
SITE: MIDDLETOWN, U.S.A. (BOSTON, MA. METEOROLOGY)
Cooling
System
Once-
through
Mech. Wet
Nat. Wet
Fan Wet
Pond
Spray
Canal
Mech. Dry
Nat. Dry
Capacity
Loss at
the High-
est Ambi-
ent Temp . ,
kW
5,440
23,500
34,050
18,560
44,240
22,380
118,560
125,750
Annual
Energy
Loss
x 10 7
kWH
0.19
5.79
4.42
2.68
9.67
4.64
66.64
67.18
Capacity (kW)
Required by
Pumps
3,063
7,341
7,576
6,490
4,174
3,867
3,722
4,821
Fans
0
3,485
0
3,909
0
6,378
13,256
0
Annual Energy
(x 10~7 kWH)
Required by
Pumps
2.68
6.43
6.64
5.69
3.66
3.39
3.26
4.22
_— — — — — — •
Fans
0
3.05
0
3.42
0
5.59
11.32
0
—
97
-------
TABLE 4 11 PLANT PERFORMANCE DATA OF A 1000-MWe NUCLEAR PLANT
USING CONVENTIONAL COOLING SYSTEMS(59)
SITE: MIDDLETOWN, U.S.A. (BOSTON, MA. METEOROLOGY)
Cooling
System
Once-
through
Mech . Wet
Nat. Wet
Fan Wet
Pond
Spray
Canal
Mech. Dry
Nat. Dry
Capacity
Loss at
the High-
est Ambi-
ent Temp . ,
kW
1,590
22,460
31,290
19,300
38,370
40,830
180,210
172,300
Annual
Energy
Loss
x 1
-------
VD
VD
till UW ^^PB'FT IjV
/////////////. %• ELIMINATORS \ h
\l i 111 111 1111 Ij *s Mil!
(a) Counterflow Tower
(b) Crossflow Tower
Figure 4.1.
Typical mechanical draft wet cooling towers(1)
Reprinted from Cooling Tower Fundamentals and
Application Principles, 1969, with permission
of The Marley Company.
-------
WATER OUTLET
(a) Counterflow Tower
(b) Crossflow Tower
Figure 4.2,
Typical natural draft wet cooling towers(1).
Reprinted from Cooling Tower Fundamentals
and Application Principles, 1969, with per-
mission of The Marley Company.
REINFORCED
CONCRETE SHELL
RIBS
G.L
ELIMINATORS
(a) Counterflow Forced
Draft Tower
(.b) Crossflow Induced
Draft Tower
Figure 4.3. Typical fan-assisted natural draft wet cooling tow-
ers(4) .
100
-------
Hs (AT HOT WATER TEMP.)
WATER
OPERATING
LINE
H (AIR OUT)
>•
&
Hs (AT COLD WATER TEMP . )
H (AIR IN)
pa
j
D
CQ
SATURATION
CURVE
APPROACH
H
8
(Xt
s
13
«
H
EH
rtj
W
OPERATING
LINE
RANGE
g
§
S
W
EH
TEMPERATURE
Legend:
wb
'
cw
h
»
Hg
L/G
Figure 4.4.
wet bulb temperature, C.
cold water temperature, °C.
hot water temperature, °C.
enthalpy of moist air, J/Kg of dry air.
enthalpy of saturated air, J/Kg of dry air,
liquid/gas mass flow rate ratio,
dimensionless.
Representation of the wet bulb temperature,
range, approach, operating line, and driving
force on an enthalpy-temperature diagram for
a fresh water tower(8).
101
-------
STE
1
1AM T
© 1 1 AIF
/ \
CONDENSER ^ / \
C^
CONDE1*
^- CIRCULATE
Range
Approach
<^V "^ / \
r© / TOWER \
SATE J k
( M
G WATER V_ y"/^
7^^ v£/
AIR
Evaporative Dry
Cooling Cooling
T3 - T2 T3 - T2
T9 - TA (wet bulb) T0 - T, (dry
Initial Temperature
Difference
Terminal Temperature
Difference
(Sat.) - T3
T3 - T4 (dry bulb)
(Sat.) -
Figure 4.5. Cooling Tower Nomenclature.
102
-------
REFFERENCE
CONDITION
60 80 100 120 140 160
RANGE VARIANCE, %
180 200
Figure 4.6a. Effect of varying range on tower size(l).
DC
O
O
3.0
2.5
2 2.0
UJ
N
™ 1.5
REFERENCE
CONDITION
APPROACH, "F
Figure 4.6b. Effect of varying approach on tower sized)
Figures 4. 6a and 4.6b are reprinted fro. Cooling Tower
Fundamentals and Application Principles, 1969,
permission of The Marley Company.
103
-------
65°F WET BULB
22UF RANGE
Figure 4.7. Typical performance curves of a wet cooling tower(9)
104
-------
Figure 4.8. Trend in tower size for natural draft
wet cooling towers.
105
-------
100
50
tr
FULL
CISC
PEAK:
HR/T
NG c;
EAR)
PABI1
ITY
P!
INAL
AK K3
?ONER
&ER
2,000 4,000 6,000 8,000
TIME, fa
*-l YEAR
4.9. Fan power requirements for fan-
assisted natural draft cooling
tower(2).
106
-------
SPLASH-TYPE PACKING
FILM-TYPE PACKING
I I
I I
NARROW EDGE BARS
REDWOOD BATTENS
SQUARE BARS
ROUGH BARS
WATER
FLOW
AIR
FLOW
CELLULOSE SHEET
ASBESTOS-CEMENT
XI
X1
/
PLASTIC GRIDS
WAVEFORM SHEETS
Figure 4.10.
Typical packing configurations for
wet cooling towers (16).
107
-------
WOOD
K-x
Figure 4.11.
Typical drift eliminators for wet
cooling towers (16).
108
-------
Qs = Shortwave solar radiation
Qa = Longwave atmospheric radiation
Qbr = Longwave back radiation
A Qe = Evaporative heat loss
Qc = Conduction-convection heat loss
"sr
or gain
= Reflected solar radiation
Qar = Reflected atmospheric
radiation
Water surface
Figure 4.12. Mechanisms of heat transfer across a
water surface(22).
109
-------
WIND ROSE
N
16X W.S.VJ.
10 MPH
41X S.E.
7.7 MPH
4)* S.W
10 MPH
LITTLE \ \
COLORADO \ \
RIVER * *
LAKE ASH DISPOSAL AREA
73.530.000 CU. FT. OF WATER
Figure 4.13. Cholla site development plan(29).
-------
100
\ V *° N
68 10
WIND SPEED (raph)
12
14
Figure 4.14. Design surface heat exchange coefficient for cooling ponds (23)
-------
Figure 4,15. Typical power spray canal system with power spray module
details(39). * *
-------
0.6
0.4
0.2
10
Figure 4.16,
WIND SPEED (mph)
Ntu determined from tests on a single spray
module (34). Reprinted from American Power
Conference, 1976, by P. J. Ryan and D. M.
Myers with permission of the American Power
Conference.
113
-------
WIND
HOT WATER
COLD
WATER
HOT
WATER
COLD HOT
WATER WATER
WIND
IND
Figure 4.17.
Possible spray cooling
system configuration(37)
SPRAY MODULES
FLOW DIRECTION
i + 2
CANAL BOUNDARY
Figure 4.18. Control volume for sizing spray canal systems.
114
-------
Wind Speed = 5 mph
6 rows/pass
4 rows/Dass
50
200 400 600 800
NUMBER OF SPRAYS/MILLION GPM
1000
1200
Figure 4.19.
Design Curves for Sizing Spray Canal
Systems(34). Reprinted from American
Power Conference, 1976, by P. J. Ryan
and D. M. Myers with permission of the
American Power Conference.
115
-------
OOUH1 RAOML 1 TMUfT UAWlG*
MKNANOU CUEAU UAL ON lOTTOM.
men SIM ON TOT
Figure 4.20. Typical pump-motor-float assembly for
spray modules(39).
116
-------
(a) GEA ELLIPTICAL FINTUBE
(b) L-SHAPE
FOOTED FIN
(c) EMBEDDED
FIN
(d) EXTRUDED
FIN
(•) OVERLAPPED
FOOTED FIN
(f ) HELLER- FORGO
SLOTTED PLATE FINS
Figure 4.21. Types of fin-tube constraction(40).
117
-------
STEAM
HEADER
CONDENSATE
HEADER
CO
CONDENSATE
POLISHERS
TO FEEDWATER
CIRCUIT
CON DEN SATE
/RECEIVER
COOLING
COILS
CONDENSATE
HEADER
STEAM TURBINE
'CONDENSATE
PUMP
EXHAUST
STEAM
STEAM SUPPLY
Figure 4.22. Direct, dry cooling tower condensing system
with mechanical draft tower.
-------
steam
condensate
air
counterflow
condenser
standard fin spacing
warm air
uniflow
condenser
warm air
GEA fin spacing
(German patent)
cold air
steam
cold air
standard fin spacing
condensate
steam
uniflow condenser
condensate
air extraction
condensate
counterflow
condenser
Figure 4.23. Condenser elements for direct dry
cooling system(45).
119
-------
PLAN VIEW
Figure 4.24. Wyodak air-cooled condenser arrangement(47)
120
-------
FAN
COOLING
COILS
to
H1
STEAM
TURBINE
EXHAUST
STEAM
WATER
RECOVERY *
TURBINE \
/fj$i
^b
r A A A
Vj/i'aViV1
STEAM
SUPPLY
CIRCULATING WATER PUMP
CONDENSATE POLISHERS
DIRECT-CONTACT
CONDENSER
CIRCULATING PUMP
MOTOR
CONDENSATE TO
FEEDWATER
CIRCUIT
Figure 4.25.
Indirect, dry cooling tower system with direct
contact (spray) condenser (Heller system).
-------
STEAM
WATER INLET
ANNULAR
HEADER
DRIP -f.
PLATES
HOT WELL
NOZZLE
TREES
CONCEN.
RING
BAFFLES
INNER
RING
HEADER
A.H.
DISTRIB
PIPES
OUTLET
Figure 4.26. Typical spray condenser(49)
122
-------
to
LJ
COOLING
COILS
CIRCULATING WATER
PUMP
STEAM STEAM SUPPLY
TURBINE
f T
^> T
V
SURFACE
PrtMHCMCFD
LUNUtNbLK >
-* — •
6 6 & t t> *
• 1- —
•-
•UiiJL-i^iJ
A\ <
0 a
1 i
:ON
EXHAUST
STEAM
CONDENSATE PUMP
FEEDWATER
CIRCUIT
Figure 4.27. Indirect, dry cooling tower system with
surface condenser.
-------
CONDENSER
PIPING
DRY TCWER
SAT
TTD
WATER
T = turbine exhaust temperature.
TID = terminal temperature difference.
ITD = initial temperature difference.
TA - ambient dry bulb design temperature.
LTTD = lesser terminal temperature difference
between water and air.
GTTD = greater terminal temperture difference
between water and air.
Figure 4.28. Temperature diagram of indirect dry
tower.
124
-------
heat exchanger elements
Figure 4.29. Schematic tower designs
with horizontal and verti-
cal tube layouts.
<3F W
Conventional
Figure 4.30.
High back pressure
Size comparison between high back pressure and
conventional turbine of approximately equal
power rating (48) - Reprinted from Power Engi-
Seering, 1977, by M. O. Surface with permission
of Technical Publishing Company.
125
-------
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plication Principles. Mission, Kansas, 1969.
2. LeFevre, M. R. and J. Gilbert. Operating Experiences with
Fan-Assisted Natural Draft Cooling Towers. Proceedings
of the American Power Conference, 38:771-777, 1976.
3. Yadigaroglu, G. and E. J. Pastor. An Investigation of the
Accuracy of the Merkel Equation for Evaporative Cooling
Tower Calculations. ASME Paper No. 74-Ht-59.
4. Fraas, A. P. and M. N. Ozisik. Cooling Tower. In: Heat
Exchanger Design, Chapter 6. John Wiley and Sons, Inc.,
New York, 1965.
5. Lichtenstein, J. Performance and Selection of Mechanical
Draft Cooling Towers. Trans. ASME, 65:779, 1943.
6. Stanford, W. and G. B. Hill. Cooling Tower - Principles
and Practice, Second Edition. Carter Thermal Engineering
Ltd., England, 1970.
7. Fan, L. T. and D. F. Aldis. Optimal Synthesis of a Power
Plant Cooling System. Nuclear Technology, 32(3):222-238,
1977.
8. Perry, J. H., C. H. Chilton, and S. D. Kirkpatrick, eds.
Chemical Engineering Handbook, 4th Edition. McGraw-Hill
Book Company, Inc., New York, 1977.
9. Cooling Tower Institute. Cooling Tower Performance Curves.
Cooling Tower Institute, Houston, Texas, 1967.
10. Hallett, G. F. Performance Curves for Mechanical Draft
Cooling Towers. ASME Paper No. 74-WA/PTC-3.
11. Baker, D. R. and H. A. Shryock. A Comprehensive Approach
to the Analysis of Cooling Tower Performance, Journal of
Heat Transfer. Trans. ASME, August, 1961, pp. 339-350.
12. Winiarski, L. D., B. A. Tichenor, and K. V. Byram. A
Method for Predicting the Performance of Natural Draft Cool-
ing Towers. Environmental Protection Agency, National
Thermal Pollution Research Program, 16130 GKF 12/70, 1970.
126
-------
13. Lowe, H. J. and D. G. Christie. Heat Transfer and Pres-
sure Drop Data on Cooling Tower Packings, and Model Studies
of the Resistance of Natural Draft Towers to Air Flow
International Heat Transfer Conference, Boulder, Colorado,
1962, pp. 933-950. '
14. Gardner, B. R. The Development of the Assisted-Draught
Cooling Tower. Combustion, pp. 15-22, October, 1976.
15. Haggerty, D. and M. LeFevre. Growing Role of Natural Draft
Cooling Tower in U.S. Plants. Power Engineering, 80(6)-
60-63, 1976. y .
16. Roffman, A. State of Art of Salt Water Cooling Towers for
Steam Electric Generating Plants. Westinghouse Electric
Corporation, ERDA Report No. WASH-1244, 1973.
17. Policastro, A. J. Thermal Discharges into Lakes and Cooling
Ponds. Argonne National Laboratory, Argonne, Illinois,
1973.
18. Hu, M. C. , G. F. Pavlenco, and G. A. Englesson. Water
Consumption and Costs for Various Steam Electric Power
Plant Cooling Systems. Final Report, United Engineers &
Constructors Inc., Philadelphia, PA. Prepared for U.S.
Environmental Protection Agency. UE&C-EPA-780501, 1978.
19. Espey, Huston & Associates, Inc. Consumptive Water Use Im-
plications of the Proposed EPA Effluent Guidelines for
Steam-Electric Power Generation. Austin, Texas, Document
No. 7407, 1974.
20. Espey, Huston & Associates, Inc. The Use of Surface Water
Impoundments for Cooling of Steam-Electric Power Stations.
Austin, Texas, Document No. 7775, 1977.
21. Peterson, D. E. and J. C. Sonnichsen. Assessment of Re-
quirements for Dry Cooling Towers. Hanford/Engineering
Development Laboratory, Richland, Washington, HEDL-TME
76-82, 1976.
22. Edinger, J. E. and J. C. Geyer. Heat Exchange in the En-
vironment. Edison Electric Institute, New York, EEI
Publication No. 65-902, 3rd Printing, 1971.
23. Brady, D. K. , W. L. Graves, Jr., and J. C. Geyer. Surface
Heat Exchanger at Power Plant Cooling Lakes. Edison
trie Institute, New York, EEI Publication No. 69-901,
127
-------
24. Hogan, W. T., A. A. Liepins, and F. E. Reed. An Engineer-
ing - Economic Study of Cooling Pond Performance. U.S.
Environmental Protection Agency, 1613130 DFX 05/70, 1970.
25. Thackston, E. L. and F. L. Parker. Effect of Geographical
Location on Cooling Pond Requirements and Performance.
U.S. Environmental Protection Agency, 16130 FDQ 03/71, 1971.
26. Ryan, P. Cooling Ponds: Mathematical Models for Tempera-
ture Prediction and Design. In: Engineering Aspects of
Heat Disposal from Power Generation, Chapter 12, D. R. F.
Harleman, ed., R. M. Parsons Laboratory for Water Resources
and Hydrodynamics, Massachusetts Institute of Technology,
Cambridge, MA, 1971.
27. Ryan P. Temperature Prediction and Design of Cooling Ponds.
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28. Kirkwood, J., et al. Power Station Cooling Ponds. Research
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29. Sonnichsen, J. C., Jr., S. L. Engstrom, D. C. Kolesar, and
G. C. Bailey. Cooling Ponds - A Survey of the State-of-
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30. U.S. Department of Commerce. Climatic Atlas of the United
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Washington, D. C., 1968.
31. Hebden, W. E. and A. M. Shah. Effects of Nozzle Performance
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32. Porter, R. W., U. M. Yang, and A. Yanik. Thermal Perfor-
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33. Hoffman, D. P. Spray Cooling for Power Plants. Proceed-
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35. Ryan, P. J. Heat Dissipation by Spray Cooling. Progress in
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37. Elgawhary, A. W. Spray Cooling System Design. Chemical
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38. Shell, G. L. and R. C. Wendt. Spray Cooling: An Alter-
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39. Frohwerk, P. A. Power Spray Module: A New Concept in
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40. Henderson, M. D. Feasibility Study for a Direct Air-Cooled
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for Fossil-Fueled Power Plants: Water Conservation and
Plume Abatement. United Engineers & Constructors Inc.,
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National Technical Information Service, Springfield,
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131
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SECTION 5
NEAR HORIZON COOLING SYSTEMS
5.1 INTRODUCTION
Through the years, many different types of systems have
been developed and used for dissipating waste heat from steam-
electric power plants. The systems in current use are classified
in this manual as conventional closed-cycle cooling systems and
have been described in Section 4. In practice, it has been
advantageous to combine some of these systems to lessen or elimi-
nate the environmental impacts of the component systems while
maintaining the performance and cost of the new system at an
acceptable level.
The integration of wet towers and dry towers to form a com-
bined system is especially attractive. These combinations,
called wet/dry cooling towers, can be used either for plume
abatement or for water conservation(1-7). Although there are no
major operating power plants using these wet/dry systems, one
wet/dry tower system for plume abatement has been purchased
by the Baltimore Gas & Electric Company for the Brandon Shore
Station(8), and two wet/dry tower systems for water conservation
have been purchased by the Public Service Company of New Mexico
for its San Juan Units No. 3 and 4(9).
In a wet/dry tower for plume abatement, the wet section is
the basic heat rejection device. The dry section is needed to
reduce the relative humidity of the air leaving the wet tower,
thereby reducing the probability of fogging when ambient tempera-
tures are low and humidity conditions are high. The current de-
sign of wet/dry towers for plume abatement has a small dry sec-
tion positioned above the wet section within a single structure.
These wet/dry towers have been designated in the cooling tower
industry as "hybrid" wet/dry towers.
In a wet/dry tower for water conservation, the dry section
is the basic heat rejection device. The wet section is needed
to augment the heat rejection capability of the dry tower at high
ambient conditions, thereby reducing the turbine back pressures
to levels where existing steam turbines can be used.
The current design of wet/dry towers for water conservation
has wet and dry towers joined by a circulating water circuit-
133
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The component wet and dry towers can be structurally and function-
ally separated, such as the wet/dry towers evaluated in Reference
10 and 11. They also can be structurally integrated but func-
tionlly separated, such as the wet/dry towers designed by the
Marley Company for the San Juan Units Ho. 3 and 4(9). Since the
wet and dry towers are functionally separated, the wet tower can
be removed from service when the ambient temperature falls, and
the dry tower can reject all the plant waste heat.
Two studies performed for the Federal Government have
evaluated these two concepts in significant detail(10,11). The
information provided in the next two sections is based on these
two studies.
5.2 WET/DRY TOWERS FOR PLUME ABATEMENT
5.2.1 General Description
The wet/dry mechanical draft cooling tower for plume abate-
ment is schematically depicted in Figure 5.1. These towers have
been designated hybrid wet/dry towers. The cooling tower con-
sists of a conventional wet fill section with finned dry heat
exchangers positioned above the fill. The dry heat exchangers
can be either the film type in which water flows inside of the
tube walls in a thin film(2) or the full flow type in which
water fills the tube(l). The air flows through the wet and dry
sections in parallel, whereas the water flows through the two
sections in series. The hot water from the condenser passes
through the dry section first, and then falls through the
evaporative fill. In most cases, only a portion of the total
circulating water travels through the dry section, while at all
times during tower operation, the entire flow of water is in the
wet section. The air flow through both the dry and wet sections
is varied by means of dampers in both sections.
The purpose of using the hybrid parallel path (air flow)
wet/dry tower is to decrease the tower-induced fog. Fog is a
condition when the water vapor in the tower plume or atmospheric
air condenses and reduces the visibility to about a quarter mile
(11) or less. The dry section functions to decrease the rela-
tive humidity of the air leaving the tower by adding warm, un-
saturated air to the saturated or near saturated exhaust air
from the wet section. The principles of operation of wet/dry
towers for plume abatement are described psychrometrically in
the next section.
5-2.2 Principles of Wet/Dry Tower Operation for Plume Abate-
ment (8) ~ ——
A wet mechanical tower is schematically depicted in Figure
134
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5.2; its operation is depicted on the psychrometric chart, Fig-
ure 5.3. The ambient air absorbs heat and moisture via evapora-
tive heat transfer as it contacts the water in the fill section
of the tower. The air leaves the fill section and exits from
the fan discharge stack at state 2. The air leaving the tower
mixes with the ambient air along the linear process line 1-2
shown on the psychrometric chart. Depending on the condition
of the ambient air, the process line from state 2 to state 1 can
pass through the supersaturation region as shown in Figure 5.3.
When this occurs and mist or water droplets are formed, the plume
leaving the cooling tower is visible and will not be dissipated
until the plume entrains sufficient ambient air to make the plume
unsaturated and invisible.
When a mechanical draft wet tower is located in an area in
which the ambient air is frequently not able to readily absorb
the additional moisture added by the cooling tower, potential
fogging problems occur. This ambient condition, coupled with
the fact that the air leaves a mechanical draft wet tower at
heights of only 40 to 60 feet (12.2 to 18.3 meters) above the
ground, increases the risk of fogging at ground level.
A hybrid mechanical draft wet/dry cooling tower with film-
type dry section is shown schematically in Figure 5.4; its
operation is shown on the psychrometric chart, Figure 5.5.
The hybrid wet/dry towers have finned-tube heat exchanger
modules in the dry section mounted atop the conventional wet
section. The air flow through the wet and dry sections is in
parallel, while the water flow is in series. Hot water is de-
livered to the manifold atop the tower, which in turn distri-
butes the water to the tubes. The water flows through the dry
section and then into the wet section. The air flow through
both sections is varied by means of dampers in each section.
As shown in Figures 5.4 and 5.5, ambient air .at state 1 is
taken into the tower through both the wet and dry sections
(assuming dampers in both sections are open) . The ambient air
entering the wet section absorbs heat and moisture as in a con-
ventional wet tower. The air leaves the wet section at state 2.
The ambient air entering the dry section, state 1, absorbs heat
(no moisture) as a result of sensible heat transfer and leaves
the dry section at state 3. The air streams leaving both sec-_
tions mix in the plenum chamber to achieve state 4 before leaving
the fan discharge stack. The air leaving the tower at state 4
mixes with the ambient air along a process line between state 4
and state 1. The condition of the air at state 4 depends on tne
mass flow rates of air flowing through the wet and dry sections
and the temperatures at states 2 and 3. If more of the total
mass flow rate of air is put ,through the dry section, state
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will be closer to state 3 than to state 2 and conversely.
During ambient conditions conducive to fogging, enough air must
be put through the dry section such that the mixing line between
state 4 and state 1 falls to the right of the supersaturation
region on the psychrometric chart. Under these circumstances,
the fogging potential for the plume is decreased or eliminated.
In general, the wet/dry operating mode of the tower will be
limited to only those occasions when the ambient conditions are
conducive to fogging, since operation in the wet/dry mode is
less efficient than operation in the wet mode. The controlled
operation can be accomplished through the use of meteorological
monitoring and control systems which are connected to the plant's
computer system. A monitoring and control system designed for
this purpose is described in Reference 8.
5.2.3 Plume Temperature and Moisture Content of the Wet/Dry
Tower Plume
As discussed in Section 5.2.2, the purpose of the wet/dry
tower is to exhaust a mixture of air and water vapor to the
atmosphere at a temperature and relative humidity which are low
enough, so that upon cooling, the vapor which condenses will not
cause any fog-related problems in the near vicinity of the tow-
er. For control of fog-related problems, the maximum allowable
moisture content of the exhaust air will change as the ambient
condition changes. A criterion on the time limit of fogging
must be established in order to determine the relative sizes
of the wet and dry sections of the cooling tower.
The condition of the exit air can be given by the air tem-
peratures across the wet and dry sections and the air flow
rates through each section. The air and vapor mixture coming
through each section mixes in the plenum chamber underneath the
fan and as it passes through the fan. A mass balance on the
vapor and the dry air and an energy balance on the mixing air
streams are required before determining the relative humidity
of the exit air stream. For steady state flows, the mass balance
for dry air is:
where:
Qw ^a'w = Q (/?a) (5.1)
Qd = volumetric flow rate of the air-
vapor mixture entering the plenum
chamber from the dry section, m-^/s
Qw = volumetric flow rate of the air-
vapor mixture entering the plenum
chamber from the wet section, nr/s
136
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Qp = volumetric flow rate of the air-
vapor mixture leaving the plenum
chamber and passing through the
fan, mj/s.
(/>a)w = density of dry air leaving the
wet section. Tfrr/m-J
wet section,
(/^d = densitY of dry air leaving the
dry section, Kg/nr .
(/°a^r> = densitY of dry air leaving the
p plenum chamber, Kg/m .
Assuming the air leaving the wet section is saturated, a mass
balance on the water vapor entering and leaving the plenum
chamber under steady state operation gives:
W + QW ^a'w Ww = Qp a>p wp (5.2)
where :
W = specific humidity of the ambient
air, Kg of water vapor/Kg of dry air.
Ww = specific humidity of the air leaving
the wet section, Kg of water vapor/
Kg dry air.
W = specific humidity of the mixed streams,
Kg of water vapor/Kg dry air.
Assuming that the mixing process which takes place in the plenum
chamber is adiabatic, an energy balance gives:
Hd + QW a>w Hw = Qp ^a'p Hp (5'3)
where:
Hd, Hw, and H are the enthalpies (Kj/Kg of dry air)
of the air-vapor streams leaving the dry section,
the wet section, and the plenum area, respectively.
The kinetic and potential energies of the air-vapor streams are
neglected since the velocities and elevation changes remain re-
latively small.
The enthalpy of the air-vapor mixture entering the plenum
chamber will depend on the relative performance of the wet and
dry sections. Knowing the performance of each section, the
137
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specific humidity and the enthalpy of the mixture are found from
Equations (5.1) through (5.3). Once the specific humidity leav-
ing the plenum chamber and the enthalpy of the mixture in the
plenum chamber are known, the wet and dry bulb temperatures can
be found on a psychrometric chart.
5.2.4 Design of Wet/Dry Towers for Plume Abatement
As previously indicated, the hybrid wet/dry tower is oper-
ated in a wet/dry mode only at ambient conditions conducive to
fogging or icing by the tower plume. The ambient conditions
which fall in this category are low dry bulb temperature, high
relative humidity, and low wind speed. As a result, the hybrid
wet/dry tower modules are generally designed with 'regular wet
tower modules as the base. On top of each wet section, a dry
heat exchanger is added to form a hybrid wet/dry tower module.
A detailed design and cost study of the hybrid wet/dry tow-
er gives the following design procedure for sizing wet/dry tower
systems(11). In the first step, different wet tower systems are
designed to handle the plant heat load by varying the wet tower
approach and the cooling range. The tower systems are then
evaluated for thermal performance, capital and penalty costs, as
well as fogging potential. Using these wet tower systems, all
of the systems with the same fogging potential are identified,
and the minimum cost system is selected as the optimum system
for each specified fogging potential. An optimized wet tower
system selected solely on the basis of economics is referred to
as the reference system. The fogging potential is defined as
the number of hours the cooling tower plume may interact with
the ambient air and cause ground level fog which limits visibi-
lity to less than 0.25 miles. (An ambient condition with visibi-
lity less than 0.25 miles is considered to be heavy fog). The
fogging potential can be determined by various plume analysis
models(11) .
In the second step, the cooling systems using hybrid wet/
dry towers with varying dry section sizes are evaluated in a
similar manner, with the exception that the plume abatement
analyses should be performed for the wet/dry operating mode.
The minimum cost hybrid wet/dry system is then identified for
each specified fogging potential.
In the third and final step, the minimum cost systems ob-
tained in the above two s'teps for wet and wet/dry systems for
each specified fogging potential are compared, and the minimum
cost system is identified as the optimized system for the speci-
fied fogging potential.
138
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5.2.5 Typical Size, Performance and Cost of Wet/Drv Tower
Systems for Plume Abatement ~—'
Typical size, performance and cost of the hybrid wet/dry
tower systems designed for plume abatement are shown in Table
5.1 and in Figure 5.6. The size, performance, and costs are
given in terms of number of modules and dry section height,
number of ground fogging hours, and the capital, penalty and
total evaluated costs, respectively. (Full flow dry heat ex-
change modules were used). These data were taken from Reference
11. The conclusions drawn from these data are:
1. Although the hybrid tower system does provide an ef-
fective means for reducing ground fogging from low pro-
file mechanical towers, ground fogging can also be re-
duced by simply increasing the wet tower size.
2. In most circumstances, a hybrid tower system is more
costly than a comparable wet tower system with equal
fogging potential (Figure 5.6). As such, the use of a
hybrid wet/dry tower system is not recommended in these
cases. However, special site consideration, e.g., ex-
isting sites which are to be backfitted to closed-cycle
cooling, may require the use of hybrid wet/dry towers
because of space constraints.
5.3 WET/DRY TOWERS FOR WATER CONSERVATION
5.3.1 General Description
A number of possible arrangements exist for combining
separate wet and dry towers into wet/dry towers which can con-
serve make-up water while rejecting the power plant waste heat.
Many of these wet/dry towers have been described in the litera-
ture (3-5). Two designs which have been proposed by manufac-
turers are:
1) Mechanical Series Wet/Dry Tower
This system combines separate mechanical draft wet and dry^
towers into an operational unit by means of a cooling water cir-
cuit which flows through the dry and wet towers in series (Fig-
ure 5.7) .
2) Mechanical Parallel Wet/Dry Tower
This system combines separate mechanical draft wet and dry
towers into an operational unit by means of a cooling w^ter cir-
cuit which flows through the wet and dry towers in parallel
(Figure 5.8).
139
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Analyses(10,11) have indicated that mechanical series and
mechanical parallel wet/dry cooling for water conservation have
approximately the same total evaluated cost and are similar in
operation. For this reason and because the first commercial
purchase has a series flow tower, only the series flow wet/dry
system is discussed in this section.
5.3.2 Design and Operation of Series Flow Wet/Dry Towers for
Water Conservation
The series wet/dry towers are usually designed such that
water flows first to the dry tower and then to the wet cooling
tower as shown in Figure 5.7.
The dry tower is designed to reject the entire heat load
at a low ambient temperature while maintaining the turbine back
pressure within specified limits. The performance of the dry
tower is then evaluated at the peak ambient temperature condi-
tion to determine the maximum heat rejection capacity of the dry
tower without exceeding the specified limiting back pressure.
This information is then used to size the wet helper tower need-
ed to reject the remaining heat load at this ambient temperature.
For this cooling system, the dry cooling is the basic heat
rejection mechanism, and the wet cooling is used to provide
supplementary heat rejection when necessary. The dry tower is
designed to operate continuously during the year and provisions
are included to shut down wet cells, if they are not needed at
low ambient temperatures, depending on the wet/dry operating
mode under which the system is designed to operate. Two dif-
ferent modes of operation analyzed in References 10 and 11 are
described below:
1) Mode SI
The first mode is termed the SI mode (S for series). The
main objective of this mode is to operate the wet helper tower
as little as practically possible. This mode of operation is
illustrated schematically by means of a turbine back pressure
characteristic of a wet/dry system operated in this mode (Figure
5.9). At the peak summer ambient temperature, both the wet and
dry towers are operating at full capacity as indicated by point
1. As the ambient temperature falls, the wet cells are turned
off xn succession to maintain the turbine back pressure essential-
ly constant at the wet tower design value. When point 2 is reach-
ed, all of the wet cells have been shut down, and the dry tower
handles the entire heat load. The back pressure curve between
points 1 and 2 is of a saw-tooth shape because a discrete number
f ^ Cmi are ta*en out of service as the ambient temperature
falls. This operational mode requires continuous feedback con-
140
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trols for the operation of the wet towers. Most new stations
are being designed with sufficient computer capacity to provide
for this additional measure of station control.
2) Mode S2
The second mode of operation represents a system operating
with much less control of the wet tower. The turbine back pres-
sure characteristic resulting from the operation of a wet/dry
system in this mode is illustrated in Figure 5.10. in this mode,
all the wet cells are operated continuously until the dry tower
design temperature is reached (point 2). As the ambient tempera-
ture decreases, the turbine back pressure is allowed to fall.
When the ambient temperature drops to the point where the dry
tower is sized to reject the entire heat load, the wet tower is
turned off completely (point 2). As the ambient temperature
passes through the dry tower design point, an apparent instantan-
eous jump in back pressure occurs (typically 0.5 to 2 in.Hg (13~
50 mm Hg)). However, in reality, this transition would occur
over a long enough time span so as not to create any damaging
thermal shock to the turbine and associated equipment. Turbine
manufacturers have indicated that changes in back pressures of
this magnitude occur daily during the operating life of the tur-
bine.
Wet/dry cooling systems operating in the SI mode are more
water conservative at the expense of greater energy consumption
than the same system operating in the S2 mode. Conversely,
systems operating in the S2 mode are more energy conservative
at the expense of higher water consumption.
5.3.3 Design, Economics^ and Plant Performance of Wet/Dry^
Tower Systems for Water Conservation
5.3.3.1 Design and Cost—
The designs and costs of wet/dry tower systems for water
conservation have been reported in Reference 10 to 19. Typical
designs and costs of wet/dry tower systems sized for various
water make-up requirements and the reference wet and dry tower
systems for nominal 1000-MWe coal-fired plants are shown in
Tables 5.2 and 5.3(11). The make-up requirement is expressed
as a percentage of the annual make-up required by a comparable
wet tower system in terms of heat rejection capability.
Table 5.2 shows a summary of these major design data for
the wet/dry cooling systems. Included in this table are the
tower size and operating mode, the maximum operating back pres-
sure, the gross generator output, the condenser or tower heat
load at the maximum back pressure, the heat load distribution
between the wet and dry towers at the maximum back pressure, ana
141
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the annual water make-up for the tower systems. All of the sys-
tems operate in Mode SI.
These data indicate that dry cooling tower systems of
manageable size can be designed for utility application by peak
shaving the heat load with evaporative helper towers. The num-
ber of cells needed for the wet/dry option are comparable to
or less than that required for the dry cooling system using the
high back pressure turbine. The data also show that the capaci-
ty deficit incurred with the use of the high back pressure tur-
bine (119 MWe) can be reduced more than 69 MWe, even with the
wet/dry system requiring two percent make-up.
Table 5.3 shows that the costs of wet/dry systems range
between the dry and the wet systems; the costs of the wet/dry
systems decrease monotonically as the make-up requirement in-
creases. The total evaluated costs for all of the wet/dry
systems are significantly higher than that for the wet system,
but significantly lower than the dry system.
The results of a comparable economic evaluation for typical
wet/dry systems designed for a nominal 1000-MWe nuclear power
station are shown in Tables 5.4 and 5.5(14). These data show
characteristics similar to those presented in Tables 5.2 and 5.3
for a fossil plant.
5.3.3.2 Plant Performance—
An example of the plant performance of a wet/dry system for
a nominal 1000-MWe nuclear power plant is shown in Figure 5.11
for a 10 percent make-up wet/dry tower system operating in the
Si mode(10,19). The performance shown includes the gross and
net plant output (gross output-cooling auxiliary power require-
ment) , turbine back pressure, and make-up flow rate over an
annual cycle.
When the wet and dry towers are operating together, the
turbine back pressure is maintained near its design value of
4.5 in. HgA (114.3 mm HgA), and the gross plant output (MWe) is
at its lowest value. The wet tower modules are gradually taken
out of service as the ambient temperature decreases. The dry
tower takes over completely when it is able to carry the plant
heat load while maintaining the turbine back pressure at or be-
low the design value of 4.5 in. HgA. At this point, all the wet
towers are out of service, and no water is required as shown
by the make-up curve. When the dry tower operates alone and in
response to the falling dry bulb temperature, the capacity of
the dry tower system increases, resulting in lower back pressure
and greater gross and net plant outputs. The gross plant out-
put in Figure 5.11 reflects the back pressure variation as de-
scribed above.
142
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The comparisons of the gross and net plant outputs for the
wet/dry and reference tower systems are shown in Figures 5 12
and 5.13, respectively. The corresponding ambient temoerature
at which the cooling system and plant performance were^deter-
mined is shown superimposed on the figures.
The difference in gross plant output (Figure 5.12) between
the 1 percent and 10 percent or between the 10 percent and 40
percent make-up wet/dry tower systems at the peak ambient tem-
perature reflects a back pressure difference of 0.5 in. HgA
(12.7 mm HgA) and approximately 11 MWe difference in gross plant
output. Although the lower fraction make-up systems suffer
larger capacity reductions, operations of the larger dry systems
result in shorter durations of combined wet and dry tower opera-
tion where the maximum capacity deficit occurs.
Integration of the capacity deficit over the annual cycle
determines the amount of replacement energy required for the
wet/dry and the reference systems. The amount of replacement
energy is represented in Figure 5.12 by the area bound between
the constant base generator output line and the gross output
curve for each cooling system. Thus, the figure also represents
the relative magnitude of the replacement energy needed by the
wet, wet/dry, and dry systems. It further shows that the higher
percentage make-up wet/dry systems require more replacement
energy than the lower percentage make-up systems. This is
obvious between the 1 and 10 percent systems and also between
the 20 and 40 percent systems.
Figure 5.13 shows the influence of pump and fan capacity
requirements on the capacity deficits relative to the base plant
output.
5.3.3.3 Water Usage and Costs—
One of the criteria used in the design of an optimum wet/dry
tower is the annual make-up requirement. The annual make-up is
the summation of the water usage during each increment of an
ambient temperature cycle. Since most streams generally have a
low stream flow in summer or fall when the cooling tower make-up
requirements are the highest, it is important to determine the
water usage requirements on a monthly or a daily basis during the
annual cycle.
Figure 5.14 shows the total amount of make-up required for
each month during a typical annual cycle for cooling systems de-
signed to serve a nuclear power plant at San Juan, N. M. Figure
5.15 shows the maximum make-up flow rate during each month
Although the annual percentage make-up is small, the maximum flow
rate can be large. For example, even for the one percent make-
up system, the maximum make-up flow rate is almost one-third of
that required by the wet system, because the system requires
143
-------
about a third of the wet cells needed for the wet tower. The
total monthly requirement, however, is less than 10 percent of
the wet system requirement. The information given in Figures
5.14 and 5.15 can be used to determine whether stream flow con-
ditions match the make-up requirements, or to size the reservoir
or impoundment necessary for station operation. Figures 5.16 and
5.17 show make-up requirements for a comparably sized fossil
power plant at the same location.
The water penalty is of special significance when making
cost comparisons of wet and wet/dry cooling system alternatives.
The water penalty costs are listed as separate items in Tables
5.3 and 5.5, (San Juan fossil and Sundesert nuclear, respective-
ly) . Excluding these costs from the total evaluated cost of the
cooling system would significantly increase the cost differential
between the wet and the wet/dry cooling systems. The water penal-
ty cost includes: 1) the water purchase cost, 2) the capital
cost of water treatment facilities, such as clarifiers and water
treatment chemicals, 3) the capital and operating cost of water
supply which includes make-up (intake structure) pumps, pipelines
and associated structures, and 4) the cost of blowdown disposal.
The capital cost components of the water supply penalty for these
plants includes a 25 percent indirect cost component. The Sun-
desert water penalty includes the cost of a solar evaporation
pond for blowdown, whereas at San Juan blowdown disposal costs
were assumed to be negligible.
5.3.4 Economic Feasibility of Wet/Dry Tower Systems for
Water Conservation
Studies sponsored by ERDA(IO), EPA(ll) and the California
State Energy Commission(14), from which the data on wet/dry sys-
tems for water conservation have been cited, have concluded:
1. Wet/dry cooling systems can be designed to provide a
significant economic advantage over dry cooling yet
closely match the dry tower's ability to conserve
water. A wet/dry system which saves as much as 99 per-
cent of the make-up required by a wet tower can main-
tain that economic advantage. Therefore, for power
plant sites where water is in short supply, wet/dry
cooling is the economic choice over dry cooling. Even
where water supply is remote from the plant site, this
advantage holds.
2. Where water is available, wet cooling will continue to
be the economic choice in most circumstances. Only if
resource limitation or environmental criteria make
water costs excessive can wet/dry cooling become
economically on par with wet cooling.
144
-------
3. The economic advantage of wet/dry cooling over dry
cooling reduces the need for further development of
high back pressure turbines for nuclear power plant
applications.
4. The dry surface areas needed for wet/dry options are,
in general, less than that required for the dry cooling
systems using the high back pressure turbines, but
remain large in size. Therefore, the development of
improved dry surfaces should be continued for use in
wet/dry cooling.
145
-------
TABLE 5.1. TYPICAL SIZE, PERFORMANCE AND COSTS OF HYBRID WET/DRY TOWER SYSTEMS
FOR PLUME ABATEMENT* (ID
Ground fogging (hr)
Dry Section
Height (ft)
Number of Wet/Dry
Tower Modules
Total Capital Cost
$106
Total Penalty Cost
$105
Total Evaluated Cost
$106
5
0
43
56.41
23.77
80.18
5 ft
35
54.74
24.15
79.89
10 ft
31
54.08
24.30
78.38
15 ft
29
53.92
25.35
79.27
10
0
41
55.59
23.06
78.65
20
0
37
51.84
24.40
76.24
30
0
33
50.25
22.85
73.10
60
0
26
44.82
25.70
70.52
*Power Plant: 1000-MWe Fossil
Site: Seattle, Washington
Cost Year: 1985
-------
TABLE 5.2. DESIGN DATA OF TYPICAL WET/DRY COOLING TOWER SYSTEMS FOR A FOSSIL PLANT(11)
SITE: SAN JUAN, NEW MEXICO BASE OUTPUT: 1039 MV,'e WET/DkY TYPE: MECHANICAL SERIES (SI)
Item
Number of Tower Cells,
Wet Tower/Dry Tower
Maximum Operating Back
Pressure tmsiv, in. HgA
„ » \ wax
(.ram HgA)
Gross Plant Output at
ptnax> MWe
Heat Load at ?mK, 109
Btu/hr (1012 J/hr)
Heat Load Distribution
at Pmax. (Wet Tower/Dry
Tower) , 7,
Annual Make-up Water
for Wet Towers, 108 gal
(106 m3)
Mech.
Dry (H)*
0/112
12.60
(320.0)
920.4
4.86
(5.13)
0.0/100.0
• o.o
(0.0)
Mech.
Dry (L)'
0/274
5.03
(127.8)
989.0
4.62
(4.87)
0.0/100.0
0.0
(0.0)
Percentage Make-up Requirement
Mechanical Series Wet/Dry
2
7/161
5.0
(127.0)
989.5
4.62
(4.87)
38.7/61.3
0.625
(0.237)
10
11/117
4.5
(114.3)
999.1
4.59
(4.84)
60.9/39.1
2.90
(1.10)
20
13/98
4.0
(101.6)
1009.5
4.55
(4.80)
73.2/26.8
5.97
(2.26)
30
15/84
3.5
(88.9)
1019.1
4.52
(4.77)
82.2/17.8
8.85
(3.35)
40
17/70
3.5
(88.9)
1019.1
4.52
(4.77)
85.0/15.0
11.90
(4.50)
i
Mech.
Wet
21/0
3.12
<79.2)
1025.6
4.50
(4.75)
100.0/0.0
29.53
(11.18)
* H-High Back Pressure Turbine
* L-Conventional Low Back Pressure Turbine
-------
TABLE 5.3. COST COMPONENTS ($106) OF TOPICAL WET/BRY COOLING SYSTEMS FOR A FOSSIL PIANT(ll)
SHE: SRN JURN, NEW MEXICO YEAR: 1985 WET/DRY TYPE: MECHANICAL SERIES (SI)
Capital Cost:
Cooling Tower
Condenser
Circulating Hater System
Electric Bjiipnent
Indirect Cost
Total Capital Cost of
Base Cooling Systan**
Penalty Cost:
Capacity loss
Power for Tower &
Circulating Water Pumps
Replacement Energy
Fan Energy & Circulating
Water Purtping Energy
Cooling Systan Maintenance
Total Penalty Cost of
Base Cooling System**
Make-up Mater Penalty Cost:
Make-up Hater Purchase &
Treatment Cost
Capital Cost of Make-up
Water Supply Facilities
Power and Energy Cost for
Pumping Make-up Hater
Total Make-up Water Penalty
Cost
Total Evaluated Cost of the
Crmplete Cooling Systan
Mech.
Dry (H)*
39.07
11.26
7.86
5.36
15.88
79.43
57.54
11.16
29.62
9.23
3.91
in. 46
0.00
0.00
0.00
0.00
190.89
Mech.
Dry (LH
95.58
14.46
12.51
12.45
33.75
168.75
24.27
23.37
0.49
17.45
8.15
73.73
0.00
0.00
0.00
0.00
242.48
Percentage Make-up Requirementl
Mechanical Series Wat/Dry
2%
60.20
12.07
11.70
9.81
10%
47.27
10.81
10.26
7.60
23.45 18.98
|
117.23 ! 94.92
24.01
15.18
19.37
12.17
i
4.48 ; 8.04
12.19
5.64
61.50
0.10
5.50
0.18
5.78
184.51
9.52
4.71
53.81
0.48
7.00
0.30
7.78
156.51
20%
41.84
10.12
9.16
6.62
16.92
84.66
14.30
11.22
8.54
8.62
4.19
46.88
1.00
7.76
0.38
9.14
140.68
30%
38.11
10.14
9.40
6.01
15.91
79.57
9.64
10.99
7.00
8.51
4.04
40.18
1.47
8.32
0.45
10.24
130.00
40%
34.43
9.66
8.82
5.29
14.55
72.75
9.64
9.82
7.98
7.82
3.75
39.01
1.98
8.59
0.50
11.07
122.83
Mfich.,1
Met
12.39
10.03
6.50
1.52
7.63
38.17
6.48
5.12
2.23
4.23
1.81
19.87
4.92
9.46
0.74
15.12
73.16
* H - High Back Pressure Turbine
+ L - Low Back Pressure Turbine
# Percentage of annual make-nip required by optimized wet tower
** Base Cooling System - Cooling
system without make-up and
water treatment facilities
148
-------
TABLE 5.4. DEISGN DATA OP TYPICAL WET/DRY TOWER SYSTEMS FOR A NUCLEAR POWER
PLANT(14)
SITE: Blythe, Calif. MAKE-UP INTAKE SITE: OTO BASE OUTPUT: 1023.10 MWe at 2.5 HgA
Tower System
Annual Make-up Quantity
Number of Tower Cells,
Ket Tower /Dry Tower
Surface Area of Tower,
Acres
Maximum Operating Back
Pressure Pmax. in»>HgA
Gross Plant Output at
Heat Load at Pmax» !°9
Btu/hr*
Heat Load Distribution
at pmax» (Wet Tower/Dry
Tower), 7.
Annual Make-up Water for
Wet Towers, 10^ acre-feet
Wet/Dry
5%
13/221
9.90
5.00
962.8
6.65
51.3/48.7
0.76
10%
17/203
9.43
4.50
975.3
6.60
63.3/36.7
1.55.
20%
21/178
8.63
4.00
988.2
6.5*6.
75.4/24.6
2.77
30%
25/145
7.50
4.00
988.2
6.56
79.4/20.6
4.19
40%
28/115
6.44
4.00
988.2
6.56
82.8/17.2
5.78
Wet
100%
43
2.60
3.17
1009.2
6.49
100.0/0.0
14.18
* A constant auxiliary.heat load of 2.16 x 108 Btu/hr must be added to each indicated value.
-------
TABLE 5.5. COST COMPONENTS ($106) OP TYPICAL WET/DRY COOLING
SYSTEMS FOR A 1000-MWe NUCLEAR PLANT(14)
SITE: Blythe, Calif.
MAKE-UP INTAKE SITE: OTO
YEAR: 1985
Tower System
Annual Make-up Quantity
Capital Cost:
Cooling Tower
Condenser
Circulating Vater System*
Electric Equipment
Indirect Cost
Total Capital Cost of Heat
Rejection System
Penalty Cost:
Capacity loss
Power for Tower Fans and
Circulating Water Pumps
Replacement Energy
Fan Energy & Circulating
Water Pulping Energy
Cooling System Maintenance
Total Penalty Cost of Heat
Rejection System
Water Penalty:
Make-up Water Purchase Cost
Make-up Hater Treatment Cost
(Capital & Operation)
Make-up Water Supply Cost
(Facility, Pumping Power &
Energy)
Blowdown Cost
(Solar Evaporation Pond)
Total Hater Penalty Cost
Total Evaluated Cost of the
Complete Cooling System
5%
84.611
20.135
23.374
13.854
35.493
177.467
60.290
43.657
21.849
30.225
12.564
168.585
0.323
10.202
8.061
0.926
19.512
305.564
107.
80.295
19.094
22.070
13.142
33.651
168.252
47.790
42.403
21.741
28.559
12.240
152.733 -
0.655
13.449
8.622
1.858
24.584
345.569
Wet/Dry
207.
73.458
19.094
22.969
12,160
31.920
159.601
34.890
41.864
18.738
27.859
12.287
135.638
1.172
17.986
9.481
3.340
31.979
327.219
301,
63.820
17.021
15.712
9.980
26.633
133.166
34.890
35.217
25.097
24.081
10.237
129.522
1.773
22.565
9.675
4.991
39.004
301.692
40%
54.732
16.227
14.437
8.498
23.474
117.368
34.890
31499
25.754
21.836
' 9.479
123. X58
2.447
27.662
11.367
8.526
50.002
290.528
Vet
1007.
21.688
19.088
14.975
3.004
14.689
73.444
13.906
19.126
-3.018
13.616
6.488
50.118
.
6.000
53.873
12.588
16.487
88.948
212.510
150
-------
WARM DRY
EFFLUENT
INTAKE
LOUVERS
Figure 5.1.
Schematic of hybrid wet/
dry tower for plume abate-
ment with film-type dry
section (2).
151
-------
Ul
AMBENTAIR1
Figure 5.2. Conventional mechanical
draft wet cooling tow-
er (9).
MO
Figure 5.3. Psychrometric process
for a mechanical draft
wet cooling tower(9).
-------
01
co
Figure 5,4.
Wet/dry mechanical
draft cooling tow-
er(9).
50 60 TO 80 90 WO HO SO
Figure 5.5. Psychrometric process
for a mechanical draft
wet/dry cooling tower(9)
-------
85
8
75 -
170 •
Wet/Dry Tower
(10-foot exchanger)*
Wet/Dry Tower
(S^foot exchanger) *
Wet Tower-
*Dry heat exchanger
tube length
+
10
Figure 5.6,
20 30 40 50 60
Enhanced and Man-Made Ground Fogging (hr/yr)
70
Total evaluated cost as a function of ground fogging for
various wet and wet/dry tower systems (Seattle site, 1985
dollars) (11).
-------
CONDENSER
DRY TOWER
WET
TOWER
CELLS
Figure 5.7.
Series water flow wet/dry tower system
for water conservation(10).
155
-------
CONDENSER
<7
DRY TOWER
WET
r- TOWER
\ CELLS
8
Figure 5.8
Parallel water flow wet/dry tower
system for water conservation(10).
156
-------
Wet Tower Design Back Pressure
UJ
-------
1100--
1080 - -
1060
>
o
< 1040
1020 - -
1000 - -
BASE GENERATOR OUTPUT
GROSS GENERATOR OUTPUT
NET GENERATOR OUTPUT
1000
2000
3000
4000
5000
6000
7000
8000
9000
CUMULATIVE DURATION, HRS.
Figure 5.11.
Performance curves for a 10% wet/dry
cooling system at Middletown site(10,19).
158
-------
1100
1080
BASE GENERATOR OUTPUT
MECHANICAL DRY (H)
940
— 100
— 80
- 60
— 40
h- 20
tr
LU
1000 2000 3000 4000 5000 6000 7000
CUMULATIVE DURATION. MRS.
8000 9000
Figure 5.12. Plant performance characteristics (gross out-
put) using wet/dry cooling systems(10,19).
159
-------
iioo r
1080 I-
BASE GENERATOR OUTPUT
MECHANICAL DRY (H)
1000 2000
3000 4000 5000 6000 7000
CUMULATIVE DURATION, MRS
8000
9000
Figure 5.13.
Plant performance characteristics (net out-
put) using wet/dry cooling systems(10,19).
160
-------
5 --
' 2.0
• 1.5
vo
o
1.0
3
01
^
to
s
0.5
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Figure 5.14. Total monthly make-up requirements of wet/dry cooling syster.s
for water conservation: 1000-MWe nuclear plant at San Juan,
New Mexico(10).
NOTE: Curves are drawn through the discrete points to facilitate visual
observation.
-------
16000
ISJ
Jan Feb Mar
Figure 5.15.
Apr May Jun Jul Aug Sep Oct
Nov Dec
Maximum monthly make-up requirements of wet/dry
cooling systems for water conservation: 1000-MWe
nuclear plant at San Juan, New Mexico(10).
NOTE: Curves are drawn through the discrete points to facilitate
visual observation.
-------
3 .-
co
C
O 2
CTl
CO
oo
o
a.
p
0)
I I-
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Figure 5.16. Total monthly make-up requirements of wet/dry cooling
systems for water conservation: 1000-MWe fossil plant
at San Juan, New Mexico(11).
NOTE: Curves are drawn through the discrete points to facilitate
visual observation.
-------
CFi
9000 -•
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Figure 5.17: Maximum monthly make-up requirements of wet/dry
cooling systems for water conservation: 1000-MWe
nuclear plant at San Juan, New Mexico(10).
NOTK:
Curves are drawn through the discrete points to facilitate
visual observation.
-------
REFERENCES
1. The Marley Company. The Parallel Path Wet/Dry Cooling
Tower. Mission, Kansas, 1972.
2. Ecodyne Corporation. Selecting Design Criteria for Wet/Dry
Foglimitor System Operation. Santa Rosa, California, Re-
search Report No. 10, 1974.
3. Von Cleve, H. H. Comparison of Different Wet and Dry Cool-
ing Towers. ASME Paper No. 75-WA/Pwr-10.
4. Loscutoff, W. V. Preliminary Evaluation of Wet/Dry Cooling
Concepts for Power Plants. Battelle Pacific Northwest
Laboratories, Richland, Washington, BNWL-1969, 1975.
5. Larinoff, M. W. and L. L. Forster. Dry and Wet-Peaking
Tower Cooling Systems for Power Plant Application. Journal
of Engineering for Power, Transactions of the American
Society of Mechanical Engineers, Series A, 98:335-348, 1976.
6. Li, K. W. Analytical Studies of Wet/Dry Cooling Systems
for Power Plants. In: Dry and Wet/Dry Cooling Towers for
Power Plants. American Society of Mechanical Engineers,
New York, NY, 1973.
7. Li, K. W. Combined Cooling Systems for Power Plants.
Northern States Power Company, Minneapolis, Minnesota,
1972.
8. Snyder, D. T. and R. E. Haid. Wet/Dry Cooling Tower
Damper Instrumentation and Control Scheme. Baltimore Gas
and Electric Company, Baltimore, Maryland, Progress Report,
1974.
9. The Marley Company. Project Description for San Juan Units
No. 3 and No. 4 of the Public Service Company of New Mexico.
Mission, Kansas, 1975.
10. Hu, M. C. Engineering and Economic Evaluation of Wet/Dry
Cooling Towers for Water Conservation. United Engineers
& Constructors Inc., Philadelphia, PA, UE&C-ERDA-761130,
1976. (Available from National Information Service,
Springfield, Virginia, COO-2442-1).
165
-------
11. Hu, M. C. and G. A. Englesson. Wet/Dry Cooling Systems for
Fossil-Fueled Power Plants: Water Conservation and Plume
Abatement. United Engineers & Constructors Inc., Philadel-
phia, PA, UE&C-EPA-771130, 1977. (Available from National
Technical Information Service, Springfield, Virginia,
EPA-600/7-77-137) .
12. Larinoff, M. W. Performance and Capital Costs of Wet/Dry
Cooling Towers in Power Plant Service. In: Proceedings of
the Waste Heat Management and Utilization Conference. De-
partment of Mechanical Engineering, University of Miami,
Miami, Florida, May, 1977.
13. Zaloudek, F. R., R. T. Allemann, D. W. Faletti, B. M. John-
son, H. L. Parry, G. C. Smith, R. D. Tokarz, and R. A.
Walter. A Study of the Comparative Costs of Five Wet/Dry
Cooling Tower Concepts. Battelle Pacific Northwest Labora-
tories, Richland, Washington, BNWL-2122, 1976.
14. Englesson, G. A. and M. C. Hu. Wet/Dry Cooling Systems
for Water Conservation. Prepared Testimony for the State
Energy Resources Conservation and Development Commission
of the State of California, Sundesert Nuclear Project, 1977.
15. Croley, T. E., II, V. C. Patel, and M. S. Cheng. Economics
of Dry/Wet Cooling Towers. Journal of the Power Division,
Proceedings of the American Society! of Civil Engineers,
102 (P02):147-163, 1976.
16. General Electric Company. Future Needs for Dry- or Peak-
Shaved Dry/Wet Cooling and Significance to Nuclear Power
Plants. Electric Power Research Institute, Palo Alto,
California, 1976.
17. Larinoff, M. W. Look at Costs of Wet/Dry Towers. Power,
122(4):78-81, 1978.
18. Tormey, M. T., Jr. and D. S. Holmes. Wet/Dry Cooling
Alternatives. Prepared Testimony before the State Energy
Resources Conservation and Development Commission of the
State of California, Docket Number 76-NOI-2, 1977.
19. Englesson, G. A., M. C. Hu, and W. F. Savage. Wet/Dry
Cooling for Water Conservation. In: Proceedings of the
Waste Heat Management and Utilization Conference. Depart-
ment of Mechanical Engineering, University of Miami, Miami/
Florida, 1977.
166
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SECTION 6
ADVANCED COOLING SYSTEMS
6.1 INTRODUCTION
Although the present state of knowledge indicates that dry
cooling systems have the smallest environmental impact of all the
conventional cooling systems, the high cost of electricity from
dry cooled generating plants has deterred the wide acceptance
of dry cooling by power utilities. Considerable effort has
been directed towards reducing these costs. The near-term ap-
proach through the use of wet/dry cooling has been described in
Section 5. Approaches using advanced concepts which are re-
ceiving the most attention are briefly described in the follow-
ing subsections. The advanced cooling systems are defined as
those systems which utilize either evolutionary or revolutionary
design approaches, but have not yet been applied to power plants
for commercial use. These include the following systems, all of
which are evolutionary: 1) ammonia dry cooling systems, 2)
Curtiss-Wright integral-fin dry cooling systems, 3) fluidized
bed dry cooling systems, 4) rotary (periodic) heat exchanger dry
cooling systems, 5) deluge wet/dry cooling systems, and 6) MIT
wet/dry cooling systems. The first four are all-dry systems;
the last two are advanced wet/dry systems.
6.2 AMMONIA DRY COOLING SYSTEM
6.2.1 System Description and Principle of Operation
The ammonia dry tower system is a dry cooling system which
utilizes ammonia as an intermediate cooling fluid which undergoes
a phase change during the cooling process (1-5). This dry cool-
ing system is physically an indirect system. It is, however,
functionally similar in many respects to the direct system where
exhaust steam is ducted directly to an air-cooled condenser.
Figure 6.1 is the process flow diagram. Exhaust steam from
the last stage of the turbine is condensed in the condenser/
reboiler located directly below the turbine. Instead of water
circulating through the tubes, liquid ammonia is boiled as it
is pumped through the tubes under pressure set by the operating
temperature in the condenser. The ammonia quality emerging
from the tube varies from 50 percent to 90 percent. This two-
Phase mixture is passed through a vapor-liquid separator from
167
-------
which the vapor is sent to the air-cooled heat exchangers and
condensed while the liquid is combined with the ammonia con-
densate from dry heat exchangers and recycled back through
the condenser/reboiler.
The ammonia vapor from the vapor-liquid separator flows to
the dry tower under the driving force of the vapor pressure
difference between the condenser/reboiler and the dry towers.
In the dry tower, the ammonia vapor is condensed. The condensed
ammonia is pumped back to the condenser/reboiler. Isolation
valves at the inlet and outlet manifolds of a tower section pro-
vide a means of removing sections of the tower from service as
may be required for maintenance or reduced cooling capability.
6.2.2 Advantages and Disadvantages of the Ammonia Dry Cooling
System (1-5)
The significant advantages of the ammonia system include
the following:
1. Isothermal condensation occurs in the dry tower;
consequently, a larger temperature differential
for heat transfer occurs in an ammonia system
than that in an indirect air-water system, so
that less dry heat exchanger surface area is
required.
2. The much lower volumetric flow rate and specific
volume of the ammonia vapor results in smaller
transfer lines between the plant and the tower
than would be1required for steam in a direct
dry system.
3. No problems with freezing occur in the dry tower
and, consequently, there is no requirement for
louvers, drain valves or other low temperature
safety systems.
4. No pumping is required to move ammonia vapor to
the dry tower, and very little pumping is re-
quired to pump the liquid ammonia back to the
condenser/reboiler.
The major disadvantages are as follows:
1. The higher operating pressure of the ammonia
system requires the use of heavier and more
costly piping.
168
-------
2. Since the condensation of steam and boiling
of ammonia in the condenser/reboiler are
both isothermal processes, the fixed tempera-
ture difference provides a temperature po-
tential (i.e., the log mean temperature dif-
ference) that is lower than that which is
available in the condenser of a conventional
dry system. Thus, for the same overall heat
transfer coefficient, more surface is required
for the condenser/reboiler.
3. Ammonia vapor is toxic and somewhat flamable.*
4. There is considerable uncertainty in the
operational characteristics and licensing
requirements of the large ammonia systems
needed for power plant use.
6.2.3 Current Development Status of the Ammonia Concept
The ammonia dry cooling system is currently being developed
at Battelle-Pacific Northwest Laboratories under the sponsorship
of the Department of Energy (DOE) and the Electric Power Research
Institute (EPRI). Also actively engaged in the development of
this system is the Linde Division of the Union Carbide Corpora-
tion under the sponsorship of EPRI. Cost studies performed by
Union Carbide for EPRI indicate a substantial reduction in total
cooling system cost for the ammonia concept as compared with an
optimized dry cooling system of conventional design(5). These
results are confirmed, by and large, by an independent study per-
formed by Battelle-Pacif ic Northwest for ERDA (DOE) . The use of
improved heat transfer surfaces, such as that developed by
Curtiss-Wright and presently under study by Union Carbide, can
be used to further optimize the system.
It appears that the final system design proposed for test-
ing in an experimental facility may use both deluge wet cooling
and advanced heat transfer surfaces. Work is presently being
performed by both Battelle-Pacific Northwest and Union Carbide
toward the development of the design of a demonstration dry cool-
ing system of this type.
6.3 CURTISS-WRIGHT DRY COOLING SYSTEM
The advanced aspect of the dry tower developed by the Cur-
tiss-Wright Corporation lies in the high performance and low
cost heat transfer surface of this unique fin-tube geometry(6,7) .
The Curtiss-Wright dry tower otherwise would operate exactly
as the conventional fin-tube dry tower.
*Author comment-explosive in 16 to 25 percent air mixture.
169
-------
6.3.1 Description of Curtiss-Wright Integral-Fin Tubes
The Curtiss-Wright fin-tubes are called integral-fin tubes.
These fin-tubes are fabricated by a special manufacturing pro-
cess; namely by machining the fins from the surface of a pre-
formed extrusion. This patented process is accomplished on a
modified, high-speed punch press by essentially lifting a chip
from the tube surface to form the fin without creating any scrap
material. This process is applicable for forming integral fins
on round tubes, single-port, and multi-port flat tubes. Figure
6.2 shows a typical multi-port integral-fin flat tube.
Test results(6) have demonstrated superior performance com-
pared to conventional round, fin-tube geometries. The contri-
buting factors include the following:
1. The integral-fin concept eliminates bonding
resistance to heat transfer.
2. The fin interruptions inhibit fin boundary
layer buildup and increase localized air
turbulence, resulting in improved heat
transfer performance compared to continu-
ous fins.
3. The fin and tube geometry can be varied over
a wide range to optimize performance for
specific requirements.
Since the integral^-fin tubes are fabricated from a preformed ex-
trusion, the fin and tube geometries can have wide variation and
are limited in size only by the capacity of extrusion. Current
development is centered in the multi-port flat tubes (Figure
6.2) using aluminum.
6-3.2 Development Status of the Curtiss-Wright Dry Tower System
The Curtiss-Wright integral-fin heat exchangers have been
successfully used in large industrial applications. For power
plant applications, it has been under active development by the
Curtiss-Wright Corporation with partial sponsorship from the
U. S. Department of Energy (DOE). These studies have shown a
substantial savings in capital and operating cost relative to
the conventional round finned-tube dry tower systems(6).
6.4 FLUIDIZED BED DRY COOLING SYSTEMS
6.4.1 General Description
The fluidized bed heat exchanger consists of a shallow bed
170
-------
of small particles which are caused to float or fluidize by
forced air passing through the bed(8). A fluid bed system
patented by Seth(9) is shown in Figure 6.3. Uniformly spaced
tubes containing heated water from the plant are placed hori-
zontally in the fluidized bed. Heat is transferred from the hot
fluid through the tube walls into the fluidized bed where the
air is sensibly heated before being exhausted to the atmosphere.
The fluidized bed permits higher transfer of heat than that of
a standard design where air is passed over finned tubes. Heat
transfer augmentation ;is realized mainly by the destruction or
reduction of the boundary layer around the tubes through the
presence of particles; thus the rate of heat conduction is
increased (8,9) .
The most significant attraction of the fluidized bed heat
exchanger is its high overall heat transfer coefficient, due to
the presence of the fluidized bed. If this enhanced coefficient
sufficiently reduces the cost of heat rejection without creating
significant technical problems, the fluidized bed concept should
be seriously considered as an alternative to standard dry cool-
ing techniques and conventional wet cooling methods.
Several variations on the fluidized bed heat exchanger are
being considered for application to dry cooling heat rejection.
Both finned and smooth tubes can be used in the bed. Also, the
fluidized bed can be operated partially wet to dissipate heat
both by sensible heating of the air and evaporation of water (8).
Current results indicate that two factors are important to
the success of the fluidized bed heat exchanger. The first is
the design of a system which yields a high overall heat transfer
coefficient. The second is the reduction of fan power require-
ments for the air. Optimization of these two factors may pro-
vide a promising heat rejection system which is technically
feasible and economically competitive to conventional dry cool-
ing systems.
6.4.2 Development Status
Although bench testing of this concept has been performed
at the Massachusetts Institute of Technology (MIT), there is
no industrial development of this concept at the present time.
6.5 ROTARY (PERIODIC) HEAT EXCHANGER DRY COOLING SYSTEM
6.5.1 System Description and Principle of Operation(10)
Conceptually, the periodic cooling tower represents a com-
promise between the dry cooling tower and the wet cooling tower.
Figure 6.4 shows the proposed design for the periodic exchanger.
A tower consists of a number of rotary heat exchangers as snown
171
-------
in Figure 6.5. The heat transfer surface is made of a number
of coaxial parallel discs which rotate from the hot water to the
cooling air flowing parallel to the disc surfaces.
As the heat exchanger rotates, the surfaces of the discs are
heated by the hot water and then cooled by the air stream, thus
continually transferring heat from the hot to the cold stream.
A thin layer of oil is kept on the water surface so that the
discs are coated by the oil as they leave the water. Thus,
there is little direct air-water interface and little evapora-
tion. Tests on a scale model have shown that an oil film can
suppress evaporation to less than 0.4 percent. Under either
condition, the oil can be removed and the discs operated as an
evaporative tower.
6.5.2 Advantages and Disadvantages of Periodic Cooling Tower
Concept
The potential advantages of the periodic cooling tower in-
clude the low cost of the discs and the ability of the tower
to operate wet or dry. A periodic tower could be significantly
less expensive than a conventional dry tower, and with the
ability to operate wet, the high capacity losses incurred by
conventional towers during periods of high ambient temperatures
could be minimized.
The potential disadvantages include operational problems
for a large number of rotating heat exchanger elements, high
power consumption, large number of fans, and potential fouling
by and emulsification of the oil film.
6.5.3 Development Status
Although bench-scale testing of this concept has been per-
formed, there has been no industrial development of the periodic
cooling tower.
6.6 PLASTIC TUBE DRY COOLING SYSTEM
6.6.1 General Description
The plastic tube heat exchanger has been developed in Italy
in conjunction with the development of a low profile natural
draft tower. The low profile natural draft arrangement results
in low air flow and, consequently, low heat transfer coefficients
which, in turn, result in the requirement of very large but in-
expensive surfaces. From these considerations emerged a design
using fin-less plastic tube heat exchangers (11) .
The specific advantage claimed for this new design is the
172
-------
reduced cost of material and labor for construction. AS cur-
rently envisioned, the heat exchanger would be field-assembled
by connecting 50-meter-long sections of plastic tube to metallic
tubeplate headers with specially developed plastic spacers and
leakproof neoprene rings. The finished product would be an
air-cooled heat exchanger module in the shape of a dihedron.
Several of these dihedrons would be assembled side-by-side
along with feeding and connecting pipes, and suspended on steel
legs inside a rectangular, low profile, natural-draft tower.
A proposed design is shown in Figure 6.6.
The hydraulic design of the coils promotes low air-side and
water-side pressure drops. The low air-side pressure drop al-
lows the heat exchanger to be used inside a low profile natural-
draft cooling tower. The rectangular tower proposed for use with
the heat exchanger assembly would be 40 meters high and would be
constructed using a modular steel structure supporting an alumi-
num, galvanized steel or fiberglass skirt.
The dry tower of the plastic heat exchanger design is said
to be competitive with the dry tower using conventional heat ex-
changers, and the dry system is suitable for use with conven-
tional turbines operating at a maximum back pressure of five
inches of mercury. The plastic tubes are designed to have a 30-
year service life under the most extreme combinations of operat-
ing temperature and pressure.
6.6.2 Development Status
A full-scale demonstration dihedron module has been con-
structed and operated in Italy. After two years of testing, the
thermal and hydraulic advantages of the proposed design have been
verified, and the durability of the plastic materials has been
demonstrated. After operation at maximum temperature, pressure,
and exposure to the elements for two years, the external sur-
faces of the tubes were untarnished and no problems of deterio-
ration or leaks were encountered(12). In this country the
plastic fin-less tube dry cooling concept is presently being
investigated on a conceptual design basis by the Battelle-Paci-
fic Northwest Laboratories(13).
6.7 DELUGE WET/DRY COOLING SYSTEM
6.7.1 General Description
Deluge cooling is a method of augmenting thi*capabilities
of a dry cooling tower by flushing the dry surfaces with water
and utilizing the heat rejection driving force of water evapora-
tion to aid a dry cooling system to handle heat loads at elevated
temperatures.
173
-------
In one method, the delugeate (water) is "sprayed" on a
plate-fin dry heat exchanger as shown in Figure 6.7 such that
water runs in a thin film down each side of the vertical fin
plates oriented transversely to the air flow. The thin deluge-
ate film allows sufficient passages for this air flow to pass
between the wetted fins and carries away the evaporated water
plus any sensible heat that it picks up by being in close con-
tact with the delugeate warmed by the tubes and fins. The sur-
face is designed so that the film is unbroken; thus, there,is
no dry surface on which scale or corrosion can build. Figure
6.8 shows the general layout of a proposed system(14).
Another proposed method of deluging applies to finned-tubes
which are vertical (or near vertical)(14). The air flow is
directed across the tubes which may have extended surfaces (fins,
spines, wire, etc.). The fluid is distributed by a header sys-
tem, individual or manifolded, to the top of each tube where
it is ejected or spilled on top of or axially down the perimeter
of the heat exchange surface. The fluid flows down the tube
surfaces (if smooth), spirals between spiral fins or the extend-
ed surfaces, essentially covering the entire surface. The fluid,
upon reaching the bottom of the tube, is collected by means of
funnels, troughs, tanks, headers, or basins and pumped back to
the top of the same exchanger surface or directed to another
exchanger.
6.7.2 Development Status
Deluge cooling has been successfully tested in plate-fin
towers in the Soviet Union. Tests that were made at the Bat-
telle-Pacific Northwest Laboratories (PNL) showed that water
will flow smoothly and neatly down a finned tube, presenting
a water surface to the air and completely covering all the fin
surface with water.
A program sponsored by the Department of Energy and the
Electric Power Research Institute is currently underway at PNL
to deluge an ammonia dry system with Heller-Forgo plate-fin
tube surfaces. Under this program, a six-MWe demonstration sys-
tem will be constructed and tested(15).
6.8 MIT WET/DRY TOWER SYSTEM
6.8.1 General Description
The advanced wet/dry cooling tower design proposed by the
Massachusetts Institute of Technology and bench tested is in-
tended for water conservation(16). The tower utilizes a new dry
heat transfer surface of sheet metal which is similar in design
to a film type wet tower packing. The metal plate has concave
174
-------
channels running down the plate in which hot water flows and the
rest of the plate is kept dry as shown in Figure 6.9. As the
hot water flows down the channels, it heats the plate which then
dissipates heat to the air flowing over both sides of the plate
by convection in the dry portion of the surface, while evapora-
tion takes place only at the exposed air-water interface.
The tower packing of the proposed wet/dry tower design is
composed of a number of these plates spaced parallel to one an-
other; each plate is separated from the adjacent plates to pro-
vide a passage for the air flow. The plates are held at a small
angle to the vertical, and water flows down the troughs by
gravity after being distributed to the troughs (Figure 6.10). A
fan induces air flow between the plates where heat transfer takes
place.
The MIT wet/dry towers can be designed to save varying
amounts of water relative to a wet tower designed for the same
heat load. A design and cost study(17) of this tower concept
has indicated a potential cost savings (as compared to the separ-
ate wet/dry tower systems discussed in Section 5.3) for the MIT
wet/dry tower systems designed to save about 50 percent of water
use of a wet tower system. At very high water savings, e.g.,
70 percent or higher, the MIT wet/dry tower systems are not com-
petitive with the separate wet/dry tower systems.
6.8.2 Development Status
Although bench demonstration of this concept was performed
at MIT under the sponsorship of the U. S. Energy Reserach and
Development Administration, there has been no industrial develop-
ment of this advanced wet/dry tower.
175
-------
VCNT LINt
f NH
SIOKACC
SHAM CONOCNSfR
AND
AMMONIA RtBOl UK
Jt
VAPOR StPAKATOR \
> 1-f
CANO
itsoiUR SUPPLY TAMK^/-*^
Rtaoius mjtenoN
PUMPi
MAIM ANO Fill PUMP
VAPOR LINE
TRAP
I LIOUIOUNC
CONUCNSAU ftETUKN
PUMPS
COOIINC TOtVCR
Figure 6.1. Process flow diagram for a proposed ammonia dry tower system(2)
-------
r—H = FIN HEIGHT
(VARIED FROM
.40 TO 1.0 INCHES)
W = FINNED DEPTH
(VARIED TO SATISFY HEAT LOAD.)
-n = NUMBER OF FINS IN W
-h
SHELF HEIGHT
(VARIED WITH
WITH GEOMETRY)
•N =
FIN PITCH (VARIED)
FROM 6 TO 14 FINS
PER INCH)
JUUUUUli
•«= FIN WIDTH
(VARIED WITH
FIN HEIGHT)
WEB THICKNESS
(VARIED TO
SATISFYAP
WATER AND MIN
METAL VOLUME)
WALL THICKNESS
(VARIED FOR
MINAP WATER
AND MIN METAL
VOLUME)
PORT WIDTH
(VARIED FOR MIN. WATER
AND MIN. METAL VOLUME)
TUBE THICKNESS
(VARIED FROM
4.0 TO I.00
INCHES)
8 = FIN THICKNESS
(VARIED FROM
.008 TO .020
INCHES)
Figure 6.2. Typical Curtiss-Wright integral-fin multi-port tube (7).
-------
OUTER CASING OF THE
DRY TOWER ' »
HEAT EXCHANGER TUBES"n
INLET HEADER
HEAT EXCHANGER
SCREEN
DISTRIBUTOR PLATE
,0-OUTER CASING OF THE
DRY TOWER
-OUTLET HEADER
is—BLOWERS AND MOTOR
Figure 6.3. Fluidized bed dry tower(9).
178
-------
Figure 6.4. Periodic dry cooling tower schematic(10)
PERIODIC
ELEMENTS
Figure 6.5. Cross section of a dry cooling tower using
periodic cooling elements(10).
179
-------
^**'!r'tJ!'-]rrrj-e-e-«-,Le-a- e--o-e-*l
1 •:' ?• • !"' li ' ' ! e
I „ ^ ^Jjl*.*-. V. ^ ^--o-,,- ^
1 'I- ;ljj_ ' 1 _' ' ^_ ' '
I'TT'"^"**"*! *"
fjv-j J'J—o-« -e.va-e-6-
aii^L _-J L_a._n. n1!n
"(TTTnT-
^r'HH
B- - S
•!;B-B-0—0-B-B B
-0-O-_ ^
.\—_^.\ B - - - 8-
r'U i :
fl—*-«•«—el fB-0—*-
' , ' ' !-)!: :
-J.hr'-I •'-*-«—Q~s~B^tB-0-0-_ _ .
Ls's! i . ; : 9 °
W^^-9 _ _ - -1
far^'-S-
i^i
tiii
•o—a—s o o- o e-
03 o o a—a—n-
LEGEND
Q DIHEDRONS
/5\ LEGS SUSTAINING THE
^ DIHEDRONS
(3) MAIN
@ STRUCTURE SUSTAINING SKIRT
(D PERIMETRAL SKIRT
i? g qi p 9 y
Figure 6.6.
Proposed design of low profile natural draft
dry tower using plastic tubes for a 1100-MWe
nuclear power plant(11). Reprinted from
American Power Conference, 1973, by C. Roma
with permission of the American Power Con-
ference.
180
-------
DELUGE
CONTINUOUS
SURFACE
TUBE
WATER
FILM"
PLATE.
FIN
/
•/ ..
-t=5
RECYCLE
Figure 6.7. Plate-fin deluge detail (14)
181
-------
Legend:
1. Water tubes
(horizontal pipes)
2. Water distribution
main
3. Water collecting
basin
4. Sprinkler heads
5. Protective plates
(air flow baffle)
6. Basin partition
7. Cooler water sec-
tion of base
8. Lower protective
Dlates (air flow
baffle)
Figure 6.8. Plate-fin deluge tower arrangement(14).
182
-------
HOT
WATER
I
HOT
WATER
LARGE
DRY PLATE
AREA
SMALL
AIR-WATER
INTERRACIAL
AREA
* I I I
"DRY AMBIENT AIR"
-CHANNELLED
WATER FLOW
DRY FIN-LIKE
SURFACE FOR
CONVECTIVE
HEAT TRANSFER
Figure 6.9
Conceptual design of the new wet/dry surface
(16).
183
-------
TURBINEEXHAUST'STEAM
PUMP
HOT WATER
WATER FLOW,
ON PLATES
Figure 6.10.
Schematic diagram of the
MIT advanced wet/dry tow-
er packing arrangement(16)
184
-------
REFERENCES
1. Allemann, R. T., B. M. Johnson, and G. C. Smith. Ammonia
as an Intermediate Heat Exchange Fluid for Dry Cooled
Towers. Battelle Pacific Northwest Laboratories. Richland
Washington, BNWL-SA-5997, 1976.
2. Fryer, B. C. , D. W. Falletti, Daniel J. Braun, David J.
Braun, and L. E. Wiles. An Engineering and Cost Comparison
of Three Different .All-Dry Cooling Systems. Battelle
Pacific Northwest Laboratories. Richland, Washington,
BNWL-2121, 1976.
3. Johnson, B. M. , R. T. Allemann, D. W. Falletti, B. C. Fryer,
and F. R. Zaloudek. Dry Cooling of Power Generating Sta-
tions: A Summary of the Economic Evaluation of Several
Advanced Concepts Via a Design Optimization Study and a
Conceptual Design and Cost Estimate. Battelle Pacific
Northwest Laboratories. Richland, Washington, BNWL-2120,
1976.
4. Ard, P. A., C. H. Henager, D. R. Pratt, and L. W. Wiles.
Costs and Cost Algorithms for Dry Cooling Tower Systems.
Battelle Pacific Northwest Laboratories. Richland, Wash-
ington, BNWL-2123, 1976.
5. Pratt, D. R. Compatibility of Ammonia with Candidate Dry
Cooling System Materials. Battelle Pacific Northwest
Laboratories. Richland, Washington, BNWL-1992, 1976.
6. Haberski, R. J. and J. C. Bentz. Conceptual Design and
Cost Evaluation of a High Performance Dry Cooling System.
Curtiss-Wright Corporation, Wood-Ridge, New Jersey, ERDA
Report No. COO-4218-1, 1978.
7. Haberski, R. J. and R. J. Raco. Engineering Analysis
and Development of an Advanced Technology Low Cost Dry
Cooling Tower Heat Transfer Surface. Curtiss-Wright Cor-
poration, Wood-Ridge, New Jersey, ERDA Report No. COO-2774-
1, 1976.
8. Dickey, B. R., E. S. Grimmett, and D. C. Kilian. Waste
Heat Disposal Via Fluidized Bed. Chemical Engineering
Progress, 70(1), 1974.
185
-------
9. Seth, R. G. U.S. Patent for a Fixed-Fluidized Bed Dry
Cooling Tower. Patent Number 3814176, June, 1974.
10. Robertson, M. W. and L. R. Glicksman. Periodic Cooling
Towers for Electric Power Plants. In: Dry and Wet/Dry
Cooling Towers for Power Plants, Edited by R. L. Webb and
R. E. Barry, The American Society of Mechanical Engineers,
New York, 1973.
11. Roma, C. An Advanced Dry Cooling System for Water from
Large Power Station Condensers. Proceedings of the 35th
American Power Conference, 1973.
12. DeSteese, J. G. and K. Simhan. European Dry Cooling Tower
Experience. Battelle Pacific Northwest Laboratories,
Richland, Washington, BNWL-1955, 1976.
13. Fryer, B. C., D. J. Braun, D. J. Braun, L. E. Wiles, and
D. W. Falletti. An Engineering and Cost Comparison of Three
Different All-Dry Cooling Systems. Battelle Pacific North-
west Laboratories, Richland, Washington, 1976.
14. Allemann, R. T. , W. A. Walter, and H. L. Parry. Position
Paper on Deluge Augmentation of Dry Cooling Towers. Bat-
tel!3 Pacific Northwest Laboratories, Richland, Washington,
Unpublished Report, 1976.
15. Battelle-Pacific Northwest Laboratories. Conceptual De-
sign Report—A Facility for the Study and Demonstration of
a Wet/Dry Cooling Tower Concept with Ammonia Phase-Change
Heat Transport System. Richland, Washington, 1977.
16. Curcio, J. , M. Giebler, L. R. Glicksman, and W. M. Rohsenow.
Advanced Dry Cooling Tower Concept. Massachusetts Insti-
tute of Technology, Cambridge, Massachusetts, MIT-EL75-023,
1975.
17. United Engineers & Constructors Inc. Design and Economic
Evaluation of the MIT Advanced Dry Cooling Concept.
Philadelphia, PA, COO-2477-014, 1977.
186
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SECTION 7
AN OVERVIEW OF CLOSED-CYCLE COOLING WATER TREATMENT
7.1 INTRODUCTION
In light of the national goal of zero discharge and the re-
gulatory limitations on once-through cooling systems, many utili-
ties have turned to closed-cycle cooling for the heat rejection
from nuclear- and fossil-fueled power plants(1). Figure 7.1 de-
picts the basic elements of a typical recirculating cooling tow-
er system. Also shown in this figure are the locations where
water treatment may be required for the tower system.
Water is lost from the cooling system through evaporation,
drift, and blowdown. Drift is defined as the mechanical entrain-
ment of water droplets in the rising air exhausted from the top
of the tower. The term windage has also been used to designate
the drift losses. In order to restore the water lost through
evaporation and drift, a continuous quantity of make-up water
must be added to the recirculating water system.
As water evaporates from a closed-cycle cooling system, dis-
solved and suspended substances gradually build-up and remain in
the recirculating cooling water. In order to control this build-
up to reasonable levels, a quantity of the recirculating water is
purposely discharged on a continuous basis. The cooling water
discharged is called blowdown, and it must be replendished by
make-up water to maintain the water balance. Thus, neglecting
minor losses, the rate of make-up for a cooling system in the
form of evaporation, drift, and blowdown rates can be expressed
as:
Make-up = Evaporation + Drift + Blowdown (7.1)
The ratio of the concentration of a constituent in the re-
circulating cooling water to its original concentration in the
make-up water is defined in cooling water treatment as the num-
ber of cycles of concentration, C. Operation with high cycles
of concentration will reduce both the make-up and blowdown flow
rates. However, high cycles of concentration also create or
aggravate the problems associated with the cooling water systems,
because the increased concentration of dissolved solids torces
extensive water treatment to enable the system to operate satis
f actorily.
187
-------
In this and the ensuing three sections (Sections 7 through
10), descriptions and/or discussions are provided for the fol-
lowing areas concerning water treatment in the closed-cycle
cooling systems: 1) problems associated with the operation of
cooling water systems, 2) restrictions on blowdown, 3) the cur-
rent, near-horizon and future technologies for water treatment,
and 4) the typical costs of water treatment.
7.2 RELATIONSHIPS BETWEEN CYCLES OF CONCENTRATION AND THE
FLOW RATES OF MAKE-UP AND BLOWDOWN
The relationship between cycles of concentration and the
flow rates of make-up and blowdown of a wet cooling tower can be
derived from the mass balances of water and the dissolved solid
constituents in the water entering and leaving the tower (Figure
7.2):
Water Balance:
i
M = E + B + D (7.2)
Mass Balance of Dissolved Solid Constituents:
MCM = BCB + DCB (7.3)
where :
M = make-up flow rate.
E = evaporation rate.
B = blowdown flow rate.
D = drift rate.
CM = concentration of dissolved solids in the
make-up stream.
CB = concentration of dissolved solids in the
circulating water.
Solving Equations (7.2) and (7.3),
~
and
M _ _C __ D
E C-l E (?'5)
188
-------
where:
C = CB/CM' *s the number of cycles of concentration
OT total dissolved solids in the circulating
water as defined in Section 7.1.
Equations (7.4) and (7.5) are plotted in Figure 7.3. The
figure shows that when the evaporation rate is constant the flow
rates of both the make-up and blowdown from the cooling tower
decrease as the number of cycles of concentration increases.
Thus, in some existing cases or to meet future requirements,
it may be desirable to operate recirculating systems at a high
number of cycles of concentration if the ultimate objective is
to operate at as low a make-up water requirement and/or at as
low a blowdown rate as possible. The reduction of the make-up
requirement is an objective where water is scarce; the reduc-
tion of blowdown is an objective where there may be strict limits
on the discharge allowed or where no discharge is allowed to a
receiving stream. In the latter case, a reduction of blowdown
is important in reducing the size and cost of blowdown treatment.
7.3 PROBLEMS ASSOCIATED WITH COOLING WATER SYSTEMS
Generally, the major objectives of water quality control in
cooling tower systems are to ensure that the water: 1) does not
degrade the thermal efficiency and 2) does not reduce the life
expectancy of major pieces of equipment, such as towers, pumps,
condenser tubes, etc. It is usually more economical to maintain
water quality within certain limits than to face frequent equip-
ment maintenance and replacement.
The three major types of problems associated with cooling
tower systems are scaling, fouling, and degradation of materials
in contact with the recirculating cooling water. Scaling is the
result of chemical precipitation and deposition of dissolved
salts. Fouling can result from the deposition of suspended and
entrained solid materials and biological growth. Degradation
problems are largely confined to corrosion of the metal surfaces
and deterioration and decomposition of the internal components
used in cooling towers. A brief discussion of each of these ma-
jor areas of concern follows.
7.3.1 Scaling
Scaling results when dissolved salts are allowed to concen-
trate beyond their solubility limits and begin to precipitate
and form deposits on the walls of pipelines and heat exchange
surfaces. Scaling can result in a loss in heat transfer etrec-
tiveness and eventual clogging of the condenser tubes. Ta&ie
189
-------
7.1 presents a typical analysis of scales from a power plant con-
denser (3) .
The most common type of scaling results from the precipita-
tion of calcium carbonate. Calcium carbonate is formed by the
conversion of bicarbonate to carbonate at the elevated tempera-
tures reached in the condenser. High concentrations of calcium
bicarbonate are found in many freshwater sources in the United
States and are the prime sources of calcium carbonate resulting
in scale formation. Table 7.2 depicts the maximum and minimum
concentrations of selected chemical constituents observed from
samples of 98 rivers in the United States(4).
In general, most scale deposits are formed by the combina-
tion of the "hardness" cations of calcium and magnesium with the
bicarbonate, sulfate, and silicate anions. In some instances,
the iron and manganese cations can also participate in scale
formation. Several of the scale deposits, such as calcium car-
bonate and sulfate, exhibit decreasing solubility with increasing
temperature. Figure 7.4 depicts the relationship between solu-
bility and temperature for several types of scale deposits(5).
The silicates are more frequently encountered in the western
portions of the United States and, when associated with magnesium,
can form dense scales.
7.3.2 Fouling
The term fouling is normally used to describe the accumula-
tive formation of types of deposits other than scales within
the recirculating water system. As in the case of scaling, foul-
ing can reduce heat transfer effectiveness and can eventually
clog condenser tubes. Fouling is usually the result of physical
or biological processes rather than chemical reactions. Some
of the more frequent sources of materials which contribute to
fouling include (5,6):
1. Silt, sand, clay, metal oxides, detritus, micro-
organisms, and debris introduced with the make-
up water
2. Atmospheric contaminants, such as dust, soot,
pollens, spores, and insects introduced through
the cooling system
3. Biomass sloughed off the cooling surfaces and
entrained in the cooling water
4. Oil from leaks and present in make-up water
190
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5. Corrosion products, precipitates, and loosened
scale from the cooling system itself
6. Biological growth of algae, fungi, bacteria,
and slimes within the cooling system.
In cooling water systems using sea water, additional higher order
organisms (such as barnacles, bryozoans, sponges, and tunicates)
can produce fouling problems, particularly at the intake struc-
tures. Table 7.3 lists some of the more common organisms respon-
sible for biological fouling(S).
Biological fouling can be caused by microorganisms generally
classified as algae, bacteria, fungi, and molds(7). The algae
require light to survive, so they are usually confined to the ex-
posed areas of cooling towers and ponds. Bacteria, however, can
survive and flourish within the recirculating water piping and
condenser tubes under either aerobic or anaerobic conditions.
Both algae and bacteria can produce slimes, which can serve as
points of attachment for the inorganic forms of fouling. One
family of anaerobic bacteria is capable of reducing sulfates to
hydrogen sulfide. The hydrogen sulfide in turn can react with
the steel to produce a deeply pitted form of corrosion. These
anaerobic conditions can exist at the bottom of cooling ponds or
beneath fouling deposits.
Some of the principal factors which influence the rate of
microbial growth include the dissolved oxygen concentration, the
dissolved organic content of the water, water velocity, tempera-
ture, and sunlight.
7.3.3 Corrosion
Corrosion is an electro-chemical reaction which results when
electrical cells, which consist of anode and cathode surfaces,
are formed on the metal surfaces in contact with the cooling
water. The cooling water and the metal itself act as the path-
ways for completing the circuit for a galvanic electrical cell.
Although corrosion can also result from the dissolution of metal
by free mineral acidity, this is an exception which requires
special consideration. Here, only galvanic cell types of cor-
rosion are considered.
Figure 7.5 schematically depicts the first stage of a corro-
sion reaction involving iron and dissolved oxygen. At the anode,
iron is dissolved to produce a ferrous ion and two electrons.
The ferrous ion goes into solution. The two electrons migrate
to the cathode through the metal conductor and complete tne cir-
cuit at the cathode. The electrons interact with dissolved oxygen
and water to form hydroxyl ions. The hydroxyl ions react witn
191
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the excess ferrous ions dissolved from the anode to form and de-
posit ferrous hydroxide at the cathode. In actuality, the anode
and cathode are often at the same physical location. The cor-
rosion reaction proceeds in several stages, corresponding to the
various oxidation states of the metal. These stages can be ob-
served by differences in color of the corrosion products.
Of the various possible corrosion reactions which can occur
at the anode, the reactions having the highest half cell poten-
tial will prevail. Similarly, at the cathode, the cathode re-
actions having the lowest potential will occur. The combined
potential for a given reaction can be computed by subtracting
the half cell potential for the cathode from that of the anode.
The corrosion cell illustrated in Figure 7.5 is greatly
simplified. In reality several competing reactions occur during
corrosion. The corrosiveness of water is dependent upon the
metal ions present, the other molecules and ions present which
can enter into the oxidation-reduction reaction, and the films
covering the metal surface. Certain metals and alloys, such as
aluminum, form a protective layer during corrosion, which tends
to deter further corrosion. Iron, on the other hand, when cor-
roding may experience significant surface degradation before a
protective layer is formed. For other materials, no protective
layer may be formed, and the reaction may continue until the me-
tal is wasted. Such materials are frequently used as a sacrifi-
cial material in corrosion protection systems.
Most corrosion originates because of irregularities in the
metal surface due to impurities in the metal, joints, metal
alloying, deposition of scale or fouling deposits, and tempera-
ture and dissolved oxygen gradients. Some of the major waste
characteristics which influence the rate of corrosion include
pH, dissolved solids, alkalinity, temperature, velocity, dis-
solved oxygen concentration, and the presence of other oxidants.
Dissolved oxygen plays a dual role in metallic corrosion(8).
In several of the half cell reactions which occur during corro-
sion, hydrogen ions are reduced to elemental hydrogen at the
cathode. If left undisturbed, this elemental hydrogen would form
a protective coating at the cathode which would limit the rate
of corrosion. The presence of dissolved oxygen prevents this
accumulation, since hydrogen reacts with the elemental oxygen to
form water. On the other hand, high concentrations of dissolved
oxygen can lower the probability of corrosion by forming anodic
films at the anode. In most instances, cathodic reactions con-
trol the early stages of corrosion. Thus, the presence of dis-
solved oxygen or some other oxidizing agent is required in order
to initiate the early state of corrosion.
192
-------
In closed-cycle cooling systems, dissolved oxygen is usually
present, especially in a cooling tower system. Consequently cor-
rosion protection is an important consideration in these systems.
7.3.4 Deterioration of Wood and Asbestos Cement Components
The internal components of a cooling tower have been fabri-
cated from a variety of materials, such as asbestos-cement, plas-
tics, ceramics, and wood. The internal components of most of the
wet towers presently in use are made of wood or asbestos-cement.
In the past, wood has been used as a structural element in many*
small mechanical draft cooling towers. Wood deterioration in
wet cooling towers can occur by a combination of chemical, biolog-
ical, and physical mechanisms(7).
Chemical action can cause delignification of the wood. The
extent of delignification is primarily influenced by the alkalin-
ity of the recirculating cooling water. Wooden material usually
exhibits a white fibrous appearance as a result of this form of
deterioration(9).
Fungus attack can cause a reduction in the cellulose con-
tent of the wood and produce a crumbly surface in the areas af-
fected. Physical factors, such as high temperatures, high dis-
solved solids content, and alternating freezing and thawing,
can cause wood splitting and general deterioration. Consequently,
the material most commonly used in large natural draft cooling
towers is asbestos-cement or asbestos paper. This material is
highly resistant to breakdown due to freeze-thaw cycles, biolog-
ical attack, and chemical deterioration. However, breakdowns do
occur, particularly'if a highly corrosive water is used for cool-
ing. Salt water can also cause deterioration of the asbestos-
cement fill if this fill is wetted on one side only; casings
and louvers are particularly susceptible. Microorganisms can
also cause damage when attached to the asbestos-cement compo-
nents.
7.3.5 Scaling and Corrosion Indices
Since calcium bicarbonate is the major source of scale for
most cooling tower applications, two indices based on the bicar
bonate equilibrium equations are commonly used. The Langelier
Index, defined as the difference between the actual pH of the
water and its saturation pH, is a measure of the relative scaling
and corrosion potential of a given water. Thus,
Langelier Index = pH - pHs (7-6>
where pH_ is defined as the saturation pH at which the water
would be in equilibrium with the calcium carbonate.
193
-------
Thus, if the pH is greater than the saturation value, (i.e.,
a positive Langelier Index), there will be a tendency to deposit
calcium carbonate, while at negative values of the Langelier
Index there will be a tendency to dissolve existing carbonate
deposits.
The saturation pH is a function of the calcium ion concen-
tration, the total alkalinity, the temperature, and the disasso-
ciation constants for the carbonate-bicarbonate equilibrium. In
its complete form(7),
K
pH = log -S. - log(Ca++) - log A + 6.301 + S (7.7)
s K2
where:
K = solubility constant of calcium carbonate and
S
= (Ca++) (C03=)
s CaCO3
K2 = disassociation constant of calcium bicarbonate
and
K = (H+) (C03=)
2 (HC03-)
A = total alkalinity.
2 N
S = salinity term =
1 + N
N = ionic strength = 2.5 x 10 C_.
S
Cs = salinity concentration.
and Ca , CO.,", H , and HCO3~ are ionic concentrations of the
various constituents.
The Ryznar Stability Index is similar to the Langelier Index
in that it is also derived from the actual pH and the saturation
pH.
Ryznar Index = 2(pHg) - pH (7.8)
The Ryznar Index was empirically derived from a study of
operating data for waters of various saturation indices. Values
of the Ryznar Index below 6.0 indicate increasing corrosion po-
tential. Figure 7.6 presents a typical nomograph for determina-
tion of the Langelier and Ryznar Indices (10). Both the Langelier
194
-------
and Ryznar Stability Indices do not provide absolute criteria for
design and operation, but constitute guidelines to develop and
achieve treatment objectives.
Many recirculating cooling water systems operate at a slight-
ly scaling condition (11) . The objective of this type of operation
is to develop a calcium carbonate film on the metal surfaces to
prevent or retard corrosion. This film breaks the circuit of
galvanic corrosion cells by electrically insulating the water
from the metal (12). However, care must be exercised so that the
film does not become so thick that it reduces heat transfer sig-
nificantly or clogs condenser tubes. While calcium carbonate
deposition for corrosion control is widely practiced, the develop-
ment of corrosion resistant alloys and chemical inhibitors now
makes it possible to operate at slightly corrosive conditions in
some systems(11).
7.4 CIRCULATING WATER QUALITY LIMITATIONS
In order to minimize the amount of blowdown and make-up
water required and their associated treatment costs, it is de-
sirable to operate the system at the highest cycles of concen-
tration possible. This will become increasingly important for
the "zero discharge" goal to become a reality. As the number
of cycles of concentration increases, the concentration of the
chemical constituents in the recirculating water increases by the
same factor. In order to maintain these constituents within ac-
ceptable limits to minimize scaling and corrosion, certain guide-
lines have been proposed by Grits and Glover(13). Table 7.4
summarizes these guidelines.
The "conventional low pH" values in Table 7.4 are based on
traditional operating concepts. The higher values noted under
the "high pH, high cycles of concentration" column are those
attainable through the use of organic additives or dispersants.
It should be noted that a lower guideline of 500,000 for the sol-
ubility product of calcium and sulfate has been cited by others
(14). As the demand for operation at higher cycles of concen-
tration becomes necessary, pilot plant operation early in the de-
sign stage may become useful to establish design and operating
parameters.
In order to compute the maximum number of cycles of concen-
tration allowable without exceeding any of the limits noted in
Table 7.4, the initial quality of the make-up must be kn°wn-
For example, if the initial silica concentration in the blowdown
water is 20 mg/1, the 150 rag/1 limitation would be reached after
150/20 or 7.5 cycles of concentration.
Various types of treatment can be applied to reduce the con-
195
-------
centration of the limiting constituent in order to achieve high-
er cycles of concentration. However, the cost of providing the
treatment must be compared to the benefits of reduced make-up or
blowdown. The environmental impact of the additional chemicals
and the disposal of the resulting residue must also be factored
into this comparison. The various treatment processes available
for cooling water treatment are described in Section 9.
7.5 RESTRICTION ON BLOWDOWN
Current Federal Regulations place restrictions on blowdown
temperature and combined chlorine residual as part of the 1977
"Best Practical Technology Currently Available" (BPTCA) limita-
tions (15). The "Best Available Technology Economically Achiev-
able" (BATEA) limitations for 1983 place limitations on free and
combined chlorine residuals, zinc, phosphorus, and chromium,
and provide for a case by case evaluation of other corrosion in-
hibiting materials. The 1974 Guidelines, which delineated BPTCA
and BATEA limitations, are under court remand. Revised Federal
Guidelines are in preparation and are expected to be promulgated
in 1979. Regulations for the discharge of other contaminants
or residues resulting from treatment of the recirculating cool-
ing water are primarily controlled by state and local regulations
concerning sludge disposal and the water quality criteria for
specific water bodies.
In the past, blowdown quantities were largely determined by
the circulating water quality limitations discussed in the pre-
vious section. If the cost to treat make-up water was low, the
system was operated at low cycles of concentration to minimize
the build-up of suspended and dissolved solids. If the cost
to treat make-up water and adding treatment chemicals to the
circulating water was high, the system was operated at as high
a cycles of concentration as possible in order to minimize treat-
ment cost while maintaining the quality of the recirculating
water within the limits presented in Table 7.4. In the future,
water quality limitations and treatment of blowdown waste must
be included in this determination.
For example, consider a make-up having a high initial phos-
phorous level. This phosphorous could concentrate beyond the
5 mg/1 level allowed for cooling tower blowdown (1983 BATEA),
if the cycles of concentration is set at a high level based on
the circulating water quality limitations. This would require
blowdown treatment to remove some of the phosphorous or operation
of the system at a reduced value for the cycles of concentration.
Future bans on the discharge of some of the chemicals used for
corrosion, scaling, and wood deterioration control may also im-
pact the number of cycles of concentration at which circulating
cooling systems can be operated. Trends toward zero discharge
196
-------
will encourage the use of very high cycles of concentration to
reduce blowdown quantities.
In some power plants it may become practical to reuse cool-
ing tower blowdown for other purposes, such as ash sluicing water,
In such cases, the water quality limitations of the ash handling
sluicing water may also influence the cycles of concentration and
optimum blowdown quantities. As the emphasis on improving the
environment places more stringent controls on blowdown disposal,
the increasing cost of blowdown treatment and residue disposal
will have a major impact on the specification of blowdown quan-
tities.
197
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TABLE 7.1. TYPICAL ANALYSIS OF SCALES FROM
POWER PLANT CONDENSER SYSTEMS(3)
Percent of
Source Total Product
Calcium as CaO 49.79
Magnesium as MgO 2.42
Iron as Fe203 0.61
Aluminum as AlpO, 0.21
Carbonate as CO 39.00
Sulfate as S03 1.29
Silica as Si02 0.15
198
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TABLE 7.2. MAXIMUM AND MINIMUM VALUES OF SELECTED WATER
QUALITY PARAMETERS FOR 98 RIVERS(4)
Parameter
Hardness as CaCO-j
Calcium as CaC03
Magnesium as CaCO-
Sodium and Potassium as CaCO,
Bicarbonate as CaC03
Chlorides as CaCO.,
Sulfates as CaCO.,
Nitrates as CaCO.,
Iron as Fe
Silicate as SiO0
Minimum
Concentration
(mg/1)
Maximum
Concentration
(mg/1)
15
11
3
4
14
1
4
0.1
0.02
8
589
408
181
774
256
702
473
10
3
48
199
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TABLE 7.3.
TYPES OF BIOLOGICAL GROWTH AFFECTING OPERATION OF
RECIRCULATING COOLING WATER SYSTEMS(5)
Growth Type
Green algae
Blue/green algae
Diatom algae
Mold-type
filamentous
fungi
Yeastlike
fungi
Higher fungi
(Ba s idiomycetes)
Aerobic
capsulated
bacteria
Aerobic
spore-forming
bacteria
Sulfur
bacteria
(aerobic)
Sulfate
reducing
bacteria
(anaerobic)
Examples
Chlorella
Ulothrix
Spirogyra
Anacystis
Phormidium
Oscillatoria
Flagiaria
Cyclotella
Diatoma
Aspergillus
Pencillium
Mucor
Fusarium
Alternaria
Torula
Saccharomyces
Poria
Lenzites
Problems Caused
Heavy growths in spray
ponds and cooling towers
can interfere with water
distribution, plug
screens, and restrict
flow in pipelines and
pumps. Algae can accel-
erate pitting-type cor-
rosion when they adhere
to metal. Massive
growths handicap micro-
biological control by ab-
sorbing biocides.
Promote surface rot of
cooling tower wood; pro-
duce bacteria-like slimes
Discolor cooling water
and wood
Cause severe internal rot
in cooling tower wood
Aerobacter Promote the growth of
Flavobacterium several bacterial slimes
Proteus
Pseudomonas
Serratia
Bacillus
Thiobacillus
Desulfovibrio
(.continued)
Produce bacterial slimes;
spores difficult to kill
Produce sulfuric acid
from oxidized sulfur or
sulfides
Grow under aerobic slime,
causing corrosion; form
hydrogen sulfide
200
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TABLE 7.3 (continued)
Growth Type Examples Problems Caused
jron Crenothrix Produce bulky slime de-
bacteria Leptothrix posits; precipitate fer-
Gallionella ric hydroxide
201
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TABLE 7.4. CONTROL LIMITS FOR COOLING TOWER CIRCULATING WATER
COMPOSITION(14)
PH
Suspended solids (mg/1)
Carbonates, CO., (mg/1)
Bicarbonates, HC03 (mg/1)
Silica, SiO2 (mg/1)
Mg x Si02(a) (mg/1)
Ca x SO (a) (all as CaCO-J
4 (mg/1)
Ca x C03 a'(all as CaCO^)
(mg/1)
Ca x Mg x (C03)2(mg/l)
Chlorides, Cl
COD, BOD, NH3
Conventional
at Low pH
6.5 to 7.5
±0.5
200-400
5
50-150
150
35,000
1,500,000 to
2,500,000
1,200
No limit
(c)
Suggested at High
pH with High Cycles
of Concentration
with Dispersants
7.5 to 8.5
±0.3
300-400
300-400
150-200
60,000(b)
2,500,000 to
8,000,000
6,000
(b)
2,000,000 to
4,000,000
No limit
(c)
Limit depends on type of biocide
used.
(a) Solubility product, e.g., (Mg , m/g) x (SiO2, mg/1)
(b) More data are needed to confirm this value.
(c) For stainless steel in the cooling system, chlorides must
be below 3,000 mg/1.
202
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EVAPORATION
:ONDEN-
SATE
O
OJ
SIDE STREAM
TREATMENT
STEAM
COOLING
TOWER
DRIFT
CONDENSER
RECIRCULATING WATER
SLOWDOWN
TREATMENT
SLOWDOWN
MAKEUP
TREATMENT
MAKEUP
CHEMICAL
ADDITIVES
Figure 7.1. Locations for potential water treatment in a wet tower system.
-------
EVAPORATION
t
M
MAKE-UP
TOWER
D
DRIFT
B
SLOWDOWN
Figure 7.2
Mass balance for an evaporative
cooling tower.
204
-------
• - RATIO OF MAKE-UP RATE TO
EVAPORATION RATE (M/E)
X - RATIO OF SLOWDOWN RATE TO
EVAPORATION RATE (B/E)
5 7 9 11
CYCLES OF CONCENTRATION
13
Figure 7.3.
Ratio of make-up or blowdown rate to evaporation rate
versus cycles of concentration.
205
-------
100,000 -
10,000
Cn
e
>H 1,000
EH
H
PQ
ID
^
O
cn
500
100
50
10
CALCIUM BICARBONATE
HEMIHYDRITE (CaS04•1/2H2 0)
_'GYPSUM (caso4-2H2o)
ANHYDRITE (CaSO.)
•CALCIUM CARBONATE (CaC03)
32 50 68
212
104 140 176
TEMPERATURE (°F)
Figure 7.4. Solubilities of selected scale deposits
206
-------
Cathode
Anode
Figure 7.5. Corrosion reaction schematic.
-------
sss i I
—1.000
IDS • Total diss. solids, ppm
Figure 7.6.
Nomograph for determination of Langelier or
Ryznar Index(3). Reprinted from Chemical
Engineering, 1975, by F. Caplan with per-
mission of McGraw Hill Publication Comnanv.
203
-------
Figure 7.6 (continued)
Example Illustrating the Use of the Nomograph
Find Langelier Index and Ryznar Index for water with
a) pH = 6.9
b) Total dissolved solids = 72 ppm
c) Calcium hardness = 34 ppm as CaCO.,
d) Alkalinity =47 ppm as CaC03
e) Temperature = 70°F
Procedure:
1) Find intersection of total dissolved solids at bottom
of left curve with temperature
2) Carry this point horizontally to the right to pivot
line (2) and connect with calcium hardness on scale
at extreme right
3) Note intersection of this line with pivot line (3)
4} Connect this point with alkalinity scale on left via
a horizontal line to the left and note intersection
with pivot line (4)
5) Connect this intersection to pH and read Langelier
Index at intersection with Langelier scale and
Ryznar at the intersection with the Ryznar scale.
Solution:
For conditions given in a through e, the Langelier Index,
L=-1.8; the Ryznar Index, R=10.4. These values mean that the
water has a corrosive tendency.
209
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REFERENCES
1. Clean Water at Cooling Towers. Environmental Science and
Technology, 19 (4):304-305, 1975.
2. Caplan, F. Quick. Calculation of Cooling Tower Slowdown
and Make-up. Chemical Engineering, #14:82(14):110, 1975.
3. Caplan, F. Is Your Water Scaling or Corrosive? Chemical
Engineering, 82(18):129, 1975.
4. Nordel, E. Water Treatment for Industrial and Other Uses.
Reinhold Book Corporation, New York, 1961.
5. Serper, A. Selected Aspects of Waste Heat Management: A
State-of-the-Art Study. Electric Power Research Institute,
Inc., Palo Alto, California, EPRI Report No. FP-164, 1976.
(Available from National Technical Information Service,
Springfield, Virginia, PB-255 697).
6. Hittman Associates, Inc. Saltwater Cooling Towers: A State-
of-the-Art Review. Preliminary Draft Report No. HIT-700,
Hittman Associates, Inc., Columbia, Maryland, 1977.
7. Stanford, W- and G. B. Hill. Cooling Towers, Principles
and Practice, 2nd. Edition. Carter Thermal Engineering
Limited. Birmingham, England. 1970.
8. Clark, J. and W- Weissman, Jr. Water Supply and Pollution
Control. International Textbook Company, Scranton, Pennsyl-
vania, 1967.
9. The Permutit Company. Water Conditioning Handbook. Paramus,
New Jersey, 1954.
10. Caplan, F. Is Your Water Scaling or Corrosive? Chemical
Engineering, 82 (9):129, 1975.
11. Farber, A. L. Management of Cooling Water—State-of-the-Art.
Proceedings of the Fourth Annual Industrial Pollution Con-
ference, Sponsored by Water and Wastewater Equipment Manu-
facturers Association, Houston, Texas, March 30-April 1,
1976.
210
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12. Merrill, D. T. and R. L. Sanks. Corrosion Control by De-
position of CaC03 Films: Part I, A Practical Approach for
Plant Operators. Journal of American Water Works Associa-
tion, 69(11):592-599, 1977.
13. Crits, G. J. and G. Glover. Cooling Blowdown in Cooling
Towers. Water and Waste Engineering, 12(4):45-52, 1975.
14. U.S. Environmental Protection Agency. Development Docu-
ment for Effluent Limitations Guidelines and New Source
Performance Standards for the Steam Electric Power Generat-
ing Point Source Category. EPA 440/1-74/029-a, Group I,
1974.
15. Rice, K. J. and S. D. Strauss. Water Pollution Control in
Steam Plants. Power, 120(14):S-1-S-20, 1977.
211
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SECTION 8
COOLING WATER TREATMENT PROCESSES
8.1 INTRODUCTION
In the past, many utilities have operated closed-cycle
cooling water systems with a minimum amount of water treatment.
This was possible because of the low cycles of concentration
at which the systems were operated and the absence of cooling
water blowdown regulations. In the future, water treatment will
become common practice for make-up and blowdown quantities. Side-
stream treatment of the recirculating water itself may also be
necessary to operate at high cycles of concentration. This
section describes conventional water treatment processes which
can be readily applied for blowdown, make-up, and sidestream
treatment of closed-cycle cooling water systems. Only current
technology (processes which have been used in the power industry)
and near horizon technology (processes which have been exten-
sively applied in related industries) have been included in this
section. The majority of the unit processes discussed in this
section are near horizon and have not been widely applied for
circulating cooling water systems in the power industry. The
distinction between current and near horizon processes is dis-
cussed further in Section 9. Future technology, which includes
processes still in the development stage that lack proven field
experience, will be discussed in Section 10. The processes have
been conveniently grouped according to their primary function.
8.2 REMOVAL OF SUSPENDED SOLIDS
Suspended solids are defined as the filterable undissolved
solids contained in water. They include particle sizes ranging
from logs and debris to the finely divided colloidal particles
which contribute to the turbidity or cloudiness of water. Their
removal is of importance to control fouling and abrasion in a
circulating cooling water system. Because of the wide range in
particle size associated with suspended solids, several treat-
ment processes have evolved to treat different ranges of particle
size.
8-2.1 Screening
Screening is defined as the mechanical removal of large
particles of suspended matter and debris from water by passing
213
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it through screens. The size of the particles which can be re-
moved by the screen is determined by the size of the screen
openings.
The most common types of screens employed in water treat-
ment are bar screens and rotating mesh screens. The bar screens
consist of parallel-spaced bars. Many bar screens can be auto-
matically cleaned by passing a mechanical rake through the bars
at regular intervals. Rotating screens consist of wire mesh or
metal cages mounted on a rotating drum. Rotating screens can
be continuously cleaned hydraulically with water jets. A detail-
ed description and a discussion of the environmental impact of
these devices is covered in Section 11.
8.2.2 Sedimentation
Sedimentation is defined as the physical separation of
suspended solids from water by gravitational forces resulting
from differences in specific gravity between the solids and
water. Under semi-quiescent conditions, particles which are
heavier than water will settle at a velocity which is a function
of the particle size, shape, and specific gravity. The relative
removal efficiency of an idealized sedimentation process can be
directly related to the surface overflow rate of the sedimenta-
tion tank and the settling velocity of the particles. Detention
time only affects the process;to the extent that it affects
overflow velocity and provides time for particles to flocculate,
thereby, increasing net particle settling velocities.
The principle of gravitational sedimentation applies to
grit chambers, sedimentation ponds, and clarifiers. Grit cham-
bers are designed so that the surface overflow velocity is such
that only relatively heavy particles with high specific gravity
are removed. The function of the grit chamber is to trap sand,
grit, silt, and stones to protect mechanical equipment, such as
pipes and pumps, from abrasion and to reduce the solids accumu-
lation in subsequent sedimentation devices.
Settling ponds have been used in the past by the power
industry for treatment of both blowdown and make-up water for
circulating cooling water systems. Settling ponds are usually
rectangular or irregularly shaped due either to ease of con-
struction or space availability. Water enters the pond at one
end, and particles settle out as the flow traverses the pond.
Settling ponds are often not equipped with equipment for auto-
matic sludge removal and must be periodically shutdown and
drained to remove sludge accumulation. Detention times are
fairly long to provide storage space for deposited solids and
to minimize time between shutdowns for sludge removal.
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Clarifiers are a more elaborate type of sedimentation
device which provides continuous mechanical removal of sludge
deposits. Because of the continuous removal feature, detention
times can be reduced from days to hours. Clarifiers can be
constructed in circular, rectangular or square configurations.
Automatic sludge removal can be accomplished in a variety of
ways. In circular tanks, rotating rakes often revolve around
the center of the tank pushing sludge to an outlet at the bottom
of the tank. Rectangular tanks often utilize chain and flight
collectors, which scrape the sludge to a sump from which it is
pumped from the clarifier. Traveling bridges which scrape the
sludge in either direction or pick up the sludge directly through
a hydraulic "vacuum cleaner" are also coming into common use in
some clarifier designs.
Many clarifier designs also incorporate chemical feed
systems, coagulation zones, thickening zones, collecting launder-
ers, and other accessory equipment.
8.2.3 Filtration
Filtration is a process which removes suspended solids
from water by passing the water through a bed of porous media.
Solids are retained within the porous media through a combina-
tion of physical screening of particles larger than the pores
of the filter, through gravitational settling, and through ad-
hesion to the filter media by particles entering the filter pores.
Filters can employ any combination of filter media ranging from
gravel, fine sand, and anthracite to diatomaceous earth. Some
filters utilize a pre-coating agent to form a fine mat on the
filter surface to improve the capture of fine particles.
Filters can be of either the gravity or pressure type.
Gravity filters are more often used where a large volume of
water is being filtered. Pressure filters, which usually employ
deep beds of graded media, have been used widely for industrial
installations. Pressure filters normally operate at higher
loading rates 5-10 gpm/ft^ (3.4-6.8 1/sec/nT), than gravity fil-
ters 2-4 gpm/ft2 (1.4-2.8 1/sec/irT), and require less space (1).
As suspended solids are removed by the filter media, the_
pressure loss across the filter bed is increased and accompanied
by a reduction in the flow rate through the filters, unless cor-
rective action is taken. As the filter media becomes filled
with the entrapped suspended solids, it becomes necessary to
clean the filter to reduce pressure loss and prevent breakthrough
of the suspended solids in the filter effluent. Backwashing
(reversal of flow to clean the filter) is normally activated
when the pressure loss across the filter exceeds a specified
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value. The frequency of backwashing is related to the suspended
solids concentration in the feedwater. Filter backwash cycles
typically operate at backwash rates of 10 to 20 gpm/ft^ (6.8-
13.6 1/sec/m2) of surface area for a backwash time of about 10
minutes(2). The quantities of waste water produced during a
backwash cycle can represent a sizable quantity of water being
released over a very short time(l). This backwash flow will typ-
ically exceed two percent of the filter throughput. If environ-
mental regulations prohibit the direct discharge of filter back-
wash, this waste water may have to be treated. Often this dis-
charge goes to the chemical waste treatment facility and is mixed
with other discharges for further treatment prior to discharge.
8.2.4 Coagulation
Coagulation is the process by which the double layer of
electrical charges surrounding colloidal particles is neutral-
lized. Through the reduction in the magnitude of charge of this
double layer, the colloids are destabilized, allowing the Van der
Waal attractive forces and Brownian Motion to bring about col-
lision and agglomeration of the colloidal particles (3). The
chemicals which bring about this coagulation phenomenon are
called coagulants. The most common types of inorganic coagu-
lants used for water treatment include inorganic salts, such as
alum, ferric sulfate, ferrous sulfate, sodium aluminate, and
chlorinated coppers, which react with the water to form insoluble
hydroxides. These hydroxides precipitate with the coalesced
colloids as agglomerated floes. Certain polyelectrolytes are
also capable of destabilizing the colloids and forming a dense
floe.
The term "flocculating aid" has often been applied to other
materials which when used in conjunction with the primary coagu-
lants often increase the density and settling velocity of the
agglomerated floe. The most common materials used as flocculat-
ing aids include clays, activated silica, and polyelectrolytes.
The principal advantage of coagulation is that the de-
stabilization of the colloids facilitates their removal by con-
ventional sedimentation or filtration processes. In sedimen-
tation, the coagulated particles agglomerate into floe particles,
thereby,^improving removal efficiency. In filtration, the
destabilization of the colloids increases the particle sizes
and the particle interactions with the filter and results in an
improvement in the solids capture efficiency.
8.3 REMOVAL OF HARDNESS
As noted in Section 7, hardness is normally defined as the
concentration of calcium and magnesium ions in the water. These
216
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elements are of concern in circulating cooling water systems be-
cause they are the major source of scale. The removal of these
ions is usually accomplished through chemical reaction and sub-
sequent precipitation and sedimentation of insoluble calcium
and magnesium compounds or by ion exchange. The term "softening"
has been universally applied to the processes for hardness re-
moval .
8.3.1 Cold Lime-Soda Process
The cold lime-soda process is one of the most widely used
processes for water softening. In this process, lime (Ca(OH)2)
and soda ash (Na2C03) are added to water in sufficient quanti-
ties at ambient temperatures to convert all the calcium to cal-
cium carbonate and all the magnesium to magnesium hydroxide. '
Both carbonate hardness (soluble calcium and magnesium bicar-
bonates) and non-carbonate hardness (calcium and magnesium sul-
fates) are removed by the cold lime process reactions. The
resulting calcium carbonate and magnesium hydroxide precipitates
are removed by conventional sedimentation processes, such as
circular clarifiers. The process can reduce the calcium hard-
ness to approximately 35 mg/1 (expressed as CaCC>3) and magnesium
hardness to approximately 33 mg/1 (expressed as CaCO.,) due to
the solubility of these compounds at ambient temperatures and
the incomplete reaction within the limited contact time(2).
Thus, the total hardness from a cold lime-soda softening process
may not be expected to run much below 68 mg/1 (expressed as
CaC03)(2). The pH after cold lime-soda softening typically will
range from 9 to 10.5. Any excess lime remaining in solution
after the lime-soda treatment may tend to precipitate later in
the system. As a safeguard, water softened by the cold lime-
soda process is often treated with carbon dioxide or acids to
neutralize the excess lime to soluble calcium bicarbonate.
8.3.2 Hot Lime-Soda Process
The hot lime-soda process is similar to the cold lime-soda
process except the reactions occur at elevated temperatures.
The effects of the elevated temperatures are to reduce the solu-
bility of precipitates, CaCOo and Mg(OH)2, increase the reaction
rates, and improve the settling properties of the precipitates.
The chemical requirements are also reduced since free carbon
dioxide is driven off by the heating process, alleviating the
need for converting carbon dioxide to calcium carbonate via
lime addition. In hot lime-soda softening, steam is usually
mixed with the raw water to raise the temperature to about 212 F.
Packaged softening reactors, in which the steam injection and
settling tanks are combined into an integral unit, are commonly
used. Filters are also used downstream of the settling tanks
to improve capture of the calcium and magnesium precipitates.
217
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Total residual hardness values of less than 25 mg/1 are typical
with the hot lime-soda process.
8.3.3 Warm Lime^Soda Process
Since elevations in temperature can improve the softening
process, the effectiveness of the warm lime-soda softening pro-
cess can be considered to fall between that of the cold and hot
lime-soda process. While warm processes are not common, they
may find particular application in recirculating water systems
where the recirculating water temperature leaving the condenser
is in the range of 80 to 120°F (27 to 49OC) (4).
8.3.4 Ion Exchange
Water can also be softened by passing the water through
cation ion exchange resins where the calcium and magnesium ions
are replaced with sodium ions. The sodium ions form soluble
products with the anions present in the cooling water, thereby,
eliminating scale formation. The resins must be regenerated
with a solution of sodium chloride to replace the calcium and
magnesium ions with sodium ions. While ion exchange softening
has been used extensively by the power industry for softening
boiler feedwater, it has rarely been applied to circulating
cooling water. Since the purpose of this section is to discuss
only current or near horizon technologies, further discussion of
ion exchange resins is deferred to Section 10.
8.4 USE OF CHEMICAL ADDITIVES
The use of chemical additives for water treatment in
closed-cycle cooling water systems has been widely practiced in
the power industry. This has primarily resulted from the sim-
plicity of operation, flexibility, and low capital expendi-
tures associated with this form of water treatment. Chemical
additives have been employed for diverse water-related problems
including pH control, scaling control, corrosion inhibition,
biological fouling control, and protection against wood deterio-
ration. Table 8.1 provides a comprehensive list of chemicals
used in nuclear power plants(5).
8.4.1 pH Control
The control of the pH of the circulating water was proba-
bly one of the earliest applications of chemicals in the power
industry. As noted in the previous section, the pH of the cir-
culating water can be used to control its corrosive or scaling
tendencies, using the Langelier or Ryznar Stability Indices as
guidelines. if the pH of the cooling water is too high, sul-
fur ic acid is usually used to lower the pH to acceptable levels.
Sulfuric acid is usually the acid of choice because of its rela-
218
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tively low cost. In some instances hydrochloric acid may be
substituted for sulfuric acid, if the sulfate concentration is
high and additional increases may limit the cycles of concentra-
tion. If the pH is too low, lime or caustic soda can be used to
raise the pH.
8.4.2 Corrosion Inhibitors
Corrosion inhibiting chemicals usually protect the metal
surfaces from corrosion by forming protective films on the metal
surface. The operation of circulating cooling water systems at
slightly scaling conditions to form protective films of calcium
carbonate has already been explained in Section 7. Most chemi-
cal inhibitors can be classified as either anodic or cathodic,
depending on whether their films are formed at the anode or cath-
ode of the galvanic corrosion cell. The calcium carbonate method
of corrosion protection discussed in Section 7 can be considered
a cathodic type of corrosion inhibitor. Other types of cathodic
inhibitors include polyphosphates, silicates, zinc, nickel, lead,
and copper. The metals react with the anions in the circulating
water to form insoluble deposits of hydroxides, carbonates or
oxides at the cathodic areas of the corrosion cells. The poly-
phosphates and silicates act by providing anions to combine with
the metal cations to form insoluble deposits at the cathodic
area.
The anodic inhibitors consist of negatively charged radi-
cals which cause metallic oxides to form at the anodic areas.
The most common type of anodic inhibitors include the chromates,
nitrates, ferrocyanides, orthophosphates, and organics.
Many chemical additive systems for corrosion control em-
ploy a combination of anodic and cathodic inhibitors to reduce
the total chemical requirements. For example, when using chro-
mates alone, concentration of up to 100 mg/1 may be required (6).
By combining the chromates with another anodic inhibitor, such
as orthophosphate, the required chromate concentration may be
reduced to 50 mg/1. The addition of a cathodic inhibitor, such
as zinc, can further reduce the required chromate concentration
to less than 10 mg/1. This particular combination of anodic and
cathodic inhibitors is commonly called the Zinc Dianodic Method
(7).
The organic inhibitors consist of a variety of organic
compounds which include starch derivatives, lignosulfonates,
tannins, gluconates, glyceride derivatives, and a variety of
Proprietary formulations. Many of the organic formulations have
been developed to eliminate the need for the more toxic inorgan-
ic chromate methods. Organic-based corrosion inhibitors func-
tion by promoting the development of a protective metal oxide
219
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film or by creating a surface active barrier(8). Many organic
inhibitors have been specifically developed to protect specific
metals. In general, many of the organic-based lignin derivatives
and organic sulfur inhibitors are not compatible with oxidizing
biocides, such as chlorine.
8.4.3 Scaling Inhibitors
Scaling inhibitors consist of chemicals which tend to
prevent the formation of hard scale by interfering with the
precipitation process. Most scaling inhibitors fall into the
general classifications of chelating agents, antinucleating
agents, flocculants, and dispersants. The concentrations of
these chemicals can vary from a few to several hundred parts per
million depending on the quality of the recirculating water and
the types of inhibitors used.
Chelating agents react with the metal ions to form a
soluble, heat-stable complex. These complexes can be extremely
resistant to precipitation and can persist at high concentra-
tions (8). Some of the more common types of chelating agents
include EDTA (ethylenediamine tetracetic acid), NTR (trisodium
nitrilotriacetic acid), citric acid, and gluconic acids.
Antinucleating agents prevent crystal growth by disturbing
the symmetry of the crystal structure and allow chemical com-
pounds to remain in solution in a supersaturated state(9). Dis-
persants keep scale particulates in suspension and prevent
agglomeration. Flocculants work in the opposite way by encourag-
ing agglomeration, but in a controlled manner, producing a loose
fluffy precipitate which does not adhere readily to metal sur-
faces. Polyphosphates, tannins, lignins, starches, polyacrylates,
seaweed derivatives, and other organic formulations are antinu-
cleating, flocculating, and dispersing agents.
Table 8.2 lists a compilation of some of the more common
chemicals used for both scale and corrosion control(1).
8.4.4 Biological Fouling Control
Biological fouling control can be accomplished by either
the use of biocidal chemicals to kill or inhibit biological
growth or by the mechanical cleaning of the metal'surfaces.
Since the condenser tubes are the most susceptible part of the
cooling system, automatic mechanical condenser cleaning methods
have been developed and are discussed in Section 8.5. This
section is limited to discussing the use of chemical additives
for biofouling control.
In the United States chlorine has been the most widely used
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biocide in circulating cooling water systems. Chlorine is a
strong oxidant which forms hypochlorous acid and hydrochloric
acid when dissolved in water according to the following reaction'
HOC1
The hypochlorous acid under most conditions will further disas-
sociate into a hydrogen and hypochlorite ion.
HOCI^=±:H+ + OC1~
In sufficient concentration, both the hypochlorite ion and
hypochlorous acid are strong biocides. They diffuse through the
cell walls and oxidize protein groups, resulting in the loss of
enzyme activity (10) .
When chlorine is added to a water containing ammonia com-
pounds, it reacts with the ammonia and organic nitrogen present
to form mono-, dichloro-, and trichloramines. The chloramines
are not as effective a biocide as chlorine and predominate at low
pH values. If a sufficient quantity of chlorine is added, the
chloramine can be completely oxidized to nitrogen gas, allowing
the free hypochlorous acid to exist in the disassociated hypo-
chlorite form. This quanity of chlorine which exists in the
hypochlorous acid or disassociated hypochlorite form is defined
as the free chlorine residual. The chlorinated ammonia forms,
such as mono-, dichloro-, and trichloramines, make up the com-
bined residuals. Together the free and combined residuals make
up the total chlorine residual present in the cooling water.
The term break-point chlorination has been used to describe oper-
ations in the range where the ammonia has been oxidized to nitro-
gen gas and a free chlorine residual exists.
The popularity of chlorination for control of biofouling
in the power industry is primarily a result of its low cost,
simplicity of implementation, availability, effectiveness, and
extensive operating experience. Chlorination is usually accom-
plished by the direct injection of gaseous chlorine into the
circulating water. Chlorination can be practiced as either
a continuous, intermittent or shock treatment procedure. In
continuous treatment, combined chlorine residuals are usually
kept at around 0.3 to 0.5 mg/l(5). Continuous residuals in
excess of 0.5 should be avoided to prevent deterioration of the
construction materials in the cooling system(7). In many plants
semi-continuous chlorination is practiced several times a day.
In this form of chlorination, the combined residual in the water
returning to the cooling tower after treatment is usually raised
to about 0.5 mg/1 after each treatment (5) . For infrequent shock
treatment, free residuals of several parts per million may be
employed ( 10 ). The frequency of shock treatments may vary from
221
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3 to 7 days (9) .
As noted in Section 7, EPA effluent limitations place
restrictions on the free available chlorine residual allowed in
cooling tower blowdown. These limitations restrict free and
combined residual chlorine values to no more than 0.2 mg/1. In
instances where it is necessary to chlorinate beyond these levels
to control biological fouling, it may be necessary to dechlori-
nate the effluent with a reducing agent, such as sulfur dioxide,
prior to discharge in the blowdown.
While chlorine has been the most widely used biocide for
the control of biological fouling in closed-cycle cooling sys-
tems, many other commercial biocidal chemicals are available.
Table 8.3 provides a partial listing of some proprietary chemi-
cal formulations used for biological fouling control and some
of their active ingredients(5). Most of these chemical biocides
can be classified as either oxidizing or non-oxidizing biocides.
The oxidizing biocides act in a way similar to chlorine by
oxidizing cell protein. Some of the most common oxidizing bio-
cides include chlorine dioxide, potassium permanganate, bromine,
ozone, bromine chloride, and bromina.ted propionamides. While
the mechanisms of the oxidizing biocides are similar, they dif-
fer in regard to relative toxicity and cost. In the past, none
of the other oxidizing biocides have been able to compete with
chlorine with regard to cost. The brominated propionamides
represent a rather recent addition to the family of oxidizing
biocides and are of particular interest since they can be readily
decomposed and detoxified by simply raising the temperature and
pH(10).
The non-oxidizing biocides act by a variety of mechanisms
which include affecting cell permeability, destruction of pro-
tein groups, precipitation of protein, etc. Some of the more
common non-oxidizing biocides include the chlorinated phenolics,
organo-tin compounds, organo-sulfur compounds, quaternary ammo-
nium salts, methylene bio-thiocyanate, copper salts, thiocyanates,
organic amines, arsenates and arsenites, acrolein, and cationic
surface active agents. A detailed discussion of the mechanisms,
dosages, economics, advantages, and disadvantages of each of
these compounds is beyond the scope of this study. It is suffi-
cient to say that as a family, the non-oxidizing biocides gen-
erally do not degrade rapidly by reaction with the chemical con-
stituents in the water and, therefore, are concentrated in the
circulating water systems. They can be used alone or in con-
junction with an oxidizing biocide, such as chlorine, to afford
broader control of biological growths. Although their toxici-
ties vary, their resistance to decomposition may pose potential
toxicity problems in direct discharge of cooling tower blowdown
to receiving waters. EPA is developing effluent standards for
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toxic chemicals, and some of the non-oxidizing biocides may fall
under these toxic chemical regulations.
8.4.5 Protection Against Deterioration of Cooling Tower
Components ~ ~ ~~
The application of chemical additives for the prevention of
cooling tower deterioration is primarily limited to the wooden
components which are subject to biological attack. Both the
flooded sections of the tower and the non-flooded sections, which
experience alternating wet and dry conditions, can provide suita-
ble conditions for microbial growth. Generally, control of bio-
logical deterioration of wood in cooling towers is accomplished
through pre-treatment of the wood before construction and the
addition of chemical biocides to the circulating water.
Many of the chemical biocides discussed in the previous
section for bio-fouling control are also effective in control-
ling wood deterioration in the flooded sections of the tower.
However, since the non-flooded sections are not continuously in
contact with the circulating cooling water, the pre-treatment
of the wood prior to construction is the primary method of con-
trol for these areas. !
Some of the most common types of wood preservatives used
in cooling tower installations are listed in Table 8.4(7). It
is of interest to note that almost all the chemicals used for the
pre-treatment of wood used in cooling tower construction are on
EPA's list of potential toxic substances. .To the extent that
these substances leach into the cooling water and enter the blow-
down discharge, they may also result in the imposition of addi-
tional blowdown discharge limitations.
In some instances sulfuric acid is added to the cooling
tower circulating water to prevent alkalinity buildup. This
buildup would result in delignification of the wooden components
of a cooling tower which in turn could lead to premature com-
ponent failure.
8.5 MECHANICAL METHODS FOR FOULING CONTROL
As an alternative to the use of chemicals for control of
biological fouling, automatic mechanical cleaning methods have
been developed to remove scale and slime buildup in condenser
tubes. Two commercially available automatic mechanical systems
are the Amertap System and the American M.A.N. System(5).
In the Amertap System sponge rubber balls are recalculated
with the cooling water through the condenser tubes. The balls
are sized somewhat larger than the inside diameter of the con
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denser tubes to provide a cleaning action when forced through
the condenser tube by the pressure differential. Sponge rubber
balls with abrasive bands are also available to provide addi-
tional scouring action for more tenacious scale or fouling de-
posits. A separate ball collection strainer is provided in the
outlet pipes so that the balls can be recaptured and continuous-
ly recycled and injected into the condenser inlet. The balls
have a specific gravity close to the cooling water to ensure
equal distribution throughout the condenser tube bundle. The
Amertap System can be operated in either a continuous or inter-
mittent mode. About 20 percent of the tubes have these balls
passing through them at a given time.
The American M.A.N. System, which was developed in Germany
and only recently introduced in the United States, uses a system
of brushes and baskets to provide automatic condenser tube clean-
ing. Each condenser tube must be fitted with its own internal
plastic brush and plastic cages located at each end of each con-
denser tube. Through a system of valving, cleaning is initiated
by reversing the direction of flow in the condenser tubes. Each
time the flow is reversed, the brush is driven from one end of
the condenser tube to the other. A complete cycle, which nor-
mally takes less than 80 seconds, consists of two flow reversals
and two passes of the brush for restoring the flow to its origi-
nal direction.
While mechanical cleaning may reduce the need for biocide
addition in many applications, chlorination is still often
practiced to control biological fouling and wood deterioration
in the cooling tower. In addition, problems in clogging of the
strainers, ball clogging in the condenser, and general mainte-
nance have plagued some mechanical cleaning installations.
8.6 SLUDGE PROCESSING
Since environmental regulations and pressures may restrict
the discharge of concentrated sludge and residues resulting from
water treatment processes, such as sedimentation, softening,
etc. , some of the unit processes available for sludge processing
are briefly described. In general, the objective of sludge pro-
cessing is to concentrate the solids further and convert them
from a liquid to a solid form to facilitate handling and ulti-
mate disposal. The unit processes of interest for sludge treat-
ment can be loosely classified as thickening and dewatering.
8.6.1 Thickening
Thickening is defined as the increase in the concentration
of the solids in a sludge by the removal of a portion .of the liq-
uid in which the solids are suspended. The purpose of thickening
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is to reduce the total volume of sludge to improve the efficiencv
of subsequent treatment processes. A solids concentration of any-
where from 3 to 10 percent is typical of that attained from a
thickening operation. Sludge thickening is normally accomplished
by one of three methods. The most common methods used for sludge
thickening are gravity thickening, air flotation thickening, and
centrifuge thickening.
In gravity thickening the sludge is gently agitated to
enhance the compaction of the solids and to cause the release
of trapped water from the concentrated solids. Gravity thick-
ening is essentially an extension of the basic sedimentation
process to the hindered settling zone, where particle settling
velocities are affected by particle interactions and solids con-
centration. Gravity thickening is normally performed in circu-
lar tanks, similar in many ways to circular clarifiers. However,
the tanks are equipped with picket type rakes, which move at
reduced velocities to provide the necessary slow agitation.
In dissolved air flotation thickening, air is dissolved in
the sludge by contacting the sludge with air at elevated pres-
sures. The sludge is then placed in open tanks where fine air
bubbles are formed as the air comes out of solution. These bub-
bles adhere to the sludge particles, thereby increasing their
buoyancy, and cause the solids to float to the surface. At the
surface the floating sludge is collected through a skimming
system. Chemicals are often employed in air flotation to aid in
particle agglomeration.
Centrifuges have also been used for thickening of some
sludges. However, these applications have been limited primarily
because of the high maintenance and power cost associated with
centrifuge thickening as compared to gravity and air flotation
thickening. Centrifuges are, therefore, more frequently used
for sludge dewatering to solids concentrations in excess of those
normally associated with thickening.
8.6.2 Dewatering
Dewatering, as used in this section, is used to define
those processes which remove a sufficient quantity of water from
the sludge to change it from a free flowing liquid to a semi-
solid form. Dewatering processes, therefore, normally produce
an end product of at least 10 percent solids and upwards to 95
percent solids in the case of evaporative drying beds. Many of
the dewatering processes incorporate the addition of chemicals,
such as lime, ferric chloride, alum or polyelectrolytes, to im-
prove the sludge dewaterability. The most common types of de
watering processes include evaporation ponds or drying beds,
vacuum filters, centrifuges, horizontal belt filters, and tliter
presses.
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Evaporation ponds or drying beds have been widely used by
the power industry in the Western United States for disposal
of cooling tower blowdown and other waste streams. In evapora-
tion ponds, the sludges are placed in open ponds. As the water
evaporates, the solids continue to concentrate until they reach
a dried state. Many evaporation ponds have been lined with im-
permeable liners to prevent leaching of dissolved contaminants
into the ground water. Since drying beds can only be effective
in areas where the evaporation exceeds the net precipitation,
their use is usually limited to the more arid parts of the United
States.
Vacuum filters reduce the moisture content of sludge by
applying suction to the underside of filter media attached to
a rotating drum. The drum is partially immersed in the liquid
sludge, so that as it rotates, a solid cake is formed on the
filter. The vacuum is released at a point in the drum's rotation,
and the cake is scraped off before the filter is re-immersed in
the liquid sludge.
Horizontal belt filters are similar to vacuum filters ex-
cept that roller pressure is used instead of a vacuum to force
the water from the sludge. The most common type of belt filters
employ two parallel belts which sandwich the liquid sludge be-
tween them. A system of rollers is used to apply pressure to
the sludge layer squeezed between the belts, thereby dewatering
the sludge as the water is forced through the belts.
Centrifuges rely on centrifugal force to achieve a high
rate of separation between solid and liquid fractions. Continu-
ously rotating solid bowl centrifuges are the most common type
employed for sludge dewatering. Sludge is introduced at one end
of the rotating bowl. As the centrifuge spins, the solids are
thrown to the periphery of the bowl where they are continuously
conveyed to the outlet via a screw mechanism.
Vacuum filters, horizontal belt filters, and centrifuges
are usually capable of producing solids concentrations varying
from 15 to 30 percent solids. If a drier sludge is desired, fil-
ter presses which operate on a similar principle to belt filters,
except at higher pressures, are employed. In order to achieve
the high pressure, filter presses must be operated in a batch
process. The filter press itself usually consists of several
vertical plates attached to a rigid frame. Liquid sludge is
initially loaded in the spaces between the filter plates and
compressed at high pressures to produce the desired solids
concentration. The liquid passes through the filter surface and
exits through drainage ports. When the cycle is complete, the
plates are separated allowing the dry cake to drop from the
frame. Solids concentrations as high as 50 to 60 percent solids
can be obtained in some filter press operations.
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TABLE 8.1.
LIST OF CHEMICALS ASSOCIATED WITH NUCLEAR POWER
PLANTS(5)
A. CORROSION & SCALE INHIBITORS
Chroma tes
Sodium chromate
Sodium dichromate
Zinc chromate '
Zinc dichromate
Potassium chromate
Potassium dichromate
Phosphates and Polyphosphates
Calcium metaphosphate
Sodium phosphate
Sodium metaphosphate
Sodium hexametaphosphate
Sodium tripolyphosphate
Sodium pyrophosphate
Zinc phosphate
Sodium orthophosphate
Calcium phosphate
Organic polyphosphates
Glassy Silicates
Sodium silicate
Nitrites and Nitrates
Sodium nitrite
Sodium nitrate
Potassium nitrate
Cyanates
Sodium ferrocyanate
Fluorides
Sodium fluoride
Amines (also used as biocides)
Octadecylamine
Ethylenediamine
Cyclohexylamine
Benzylamine
Chelating Agents
Ethylenediamine Tetracetic acid
(EDTA)
Nitrilotriacetic acid (NTA)
LTSR - "low temperature scale
remover"
(a proprietary compound pro-
duced by Dow Chemical)
Alkaline Cleaning Stage
Sodium hydroxide
Calcium hydroxide
Sodium phosphate
Sodium sulfate
Sodium triphosphate
Ammonium hydroxide
B. CLEANING & NEUTRALIZING COMPOUNDS
Acid Cleaning Stage
Citric acid
Sulfuric acid
Neutralizing (Passivating Stage)
Sodium carbonate
Sodium sulfate
Sodium phosphate
(continued)
227
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TABLE 8.1 (continued)
B. CLEANING & NEUTRALIZING COMPOUNDS (continued)
Neutralizing (Passivating) Oxygen Reducers
Stage (continued)
~~ Hydrazine
Sodium diphosphate Morpholine
Sulfuric acid Sodium sulfite
Lithium hydroxide Cobalt sulfate
Morpholine
Sodium lignosulfonate Reactivity Control
Cyclohexylamine
Ammonium sulfate Boric acid
Ammonium hydroxide
Ammonia
C. BIOCIDES (Cooling Tower Use)
Oxidizing Biocides
Chlorine
Bromine
Sodium hypochlorite
Calcium hypochlorite
Potassium permanganate
Chlorinated cyanurates and
inocyanurates
Persulfate Compounds
Potassium hydrogen persulfate
Non-oxidizing Biocides
1. Chlorinated and/or phenylated
phenols:
Chloro-0-phenylphenol
2-Tert-Butyl-4-chloro-5-methylphenol
0-Benzyl-p-chlorophenol
4,6-Dichlorophenol
2,4-Dinitrochlorobenzene
2,6-Dinitrochlorobenzene
2,4,5-Trichlorophenol
1,3-Dichloro-5,5-Dimethylhydranotin
Trichloromethyl sulfone (Bis)
Sodium salts (ates) of:
0-Phenylphenol
2,4,5-Trichlorophenol (sodium 2,4,5-Trichlorophenate)
(continued)
228
-------
TABLE 8.1 (continued)
C. BIOCIDES (continued)
Chloro-2,phenyIphenol
2-Chloro-4-phenyIphenol
2-Bromo-4-phenyIphenol
2,3,4,6-Tetrachlorophenol
Pentachlorpphenol
Potassium salts (ates) of:
2,4,5-Trichlorophenol
2. Quaternary Amines (quaternary ammonium compounds)
Dilauryl dimethyl ammonium chloride
Dilauryl dimethyl ammonium oleate
Dodecyl trimethyl ammonium chloride
Trimethyl ammonium chloride
Octadecyl trimethyl ammonium chloride
N-Alkyl benzyl-N,N,N-trimethyl ammonium chloride
Alkyl-9-methyl benzyl ammonium chloride
Lactory mercuriphenyl ammonium lactate
Alkyl dimethyl benzyl ammonium chloride
3,4-Dichloro benzyl ammonium chloride
Ph en y liner curie trihydroxythyl ammonium lactate
PhenyImercuric triethanol ammonium lactate
Alkyl (Ci2 to C^g) dimethyl benzyl ammonium chlorides
1-Alkyl (Cg to Cio) amino-3 aminopropane monacetate
' i
3. Organo-metallic Compounds
Organotins
Bis. (tributyl tin) oxide
Organosulfurs
Bisulfides
Organothiocyanate s
Methylene bisthiocyanate
4. Cationic Surface Active Agents
Sulfonium
Phosphonium
Arsonium
lodonium
5. Dithiocarbamic Acid Salts
Sodium dimethyl diethyl dithiocarbamate
Disodium ethylene bisdithiocarbamate
6. Organic, Amines (often used with Pentachlorophenol)
Primary Rosin Amines
Sodium carboxethyl rosin amine
Rosin amine acetate .
(continued)
229
-------
TABLE 8.1 (continued)
C. BIOCIDES (continued)
Non-oxidizing Biocides (continued)
6. Organic Amines (continued)
Other Amine (primary beta-amines and beta-diamines)
Chloramine
Benzylamine
Cyclohexylamine
Ethylenediamine
Polyethyleneamine
Zinc and Copper Salts
Zinc sulfate
Copper sulfate
Copper citrate
Acrolein
Arsenates
Arsenic Acid
Sodium arsenite
Copper ions
Zinc ions
Inorganic Scale and Precipitates
Calcium carbonate
Calcium phosphate
Calcium sulfate
Calcium hydroxide
Magnesium carbonate
Magnesium hydroxide
Magnesium phosphate
Iron oxides
230
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TABLE 8.2. COMMON CHEMICAL ADDITIVES FOR CORROSION AND SCALING
CONTROL IN RECIRCULATING COOLING WATER SYSTEMS(10)
Acrylamide polymers and copolymers
Alkylphenoxpolyethoxyethanol
Benzotriazole
Diethylenetriaminepantakis (methylenephosphonic acid)
Dioctyl sodium sulfosuccinate
Disodium phosphate
Ethylenediaminetetraacetate
Ethylenediaminetetrakis(methylenephosphonic acid)
Hexamethylenediaminetetrakis (methylenephosphonic acid)
1-Hydroxyethylidene-l, 1-diphosphonic acid
Monobutyl esters of polyethylene and polypropylene glycols
Nitrilotri(methylenephosphonic acid)
Poly(amineepichlorohydrin) condensates
Poly(amineethylene dichloride) condensate
Polydimethyidiallylammonium chlorides
Polyethylenimine
Polylphosphate esters (low mol. wt.)
Polyoxpropyleneglycol
Sodium carboxymethylcellulose
Sodium citrate
Sodium dichrornate
Sodium hexametaphosphate
Sodium lignosulfunates
Sodium mercaptobenzothiazole
Sodium molybdate
Sodium nitrate
Sodium nitrilotriacetate
Sodium nitrite
Sodium polyacrylate
Sodium polymethacrylate
Sodium polystyrenesulfonic acid and copolymer
Sodium silicates
Sodium tetraborate
Sodium tripolyphosphate
Sodium zinc polyphosphate
Styrene maleic anhydride copolymers
Sulfanic acid
Tannins
Tolytriazole
Zinc sulfate
231
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TABLE 8.3.
PARTIAL LISTING OF COMMERCIALLY AVAILABLE
FORMULATIONS FOR MICROORGANISM CONTROL(5)
Chemical
NALCO 21-S
Sodium pentachlorophenate
Sodium 2,4,5-trichlorophenate
Sodium salts of other
chlorophenols
Inert ingredients
Composition
21.3
11.9
3.0
63.8
NALCO 25-L or NALCO 425-L
1-Alkyl (C6 to C18)-amino-3-
aminopropane propionate-
copper acetate complex 15.0
Isopropyl alcohol 30.0
Copper expressed as metallic 0.55
Inert ingredients 55.0
NALCO 201
Potassium pentachlorophenate 15.7
Potassium 2,4,5-trichlorophenate 9.0
Potassium salts of other
chlorophenols 1.8
Inert ingredients 70.3
NALCO 202
Methyl-1,2-dibromopropionate 29.7
Inert ingredients 70.3
NALCO 207
Methylene bisthiocyanate 10.0
Inert ingredients 90.0
NALCO 209
1,3-Dichlor-5,5-dimethylhy-
dantoin 25.0
Inert ingredients 75.5
NALCO 321
1-Alkyl (C6 to C ) amino-3-
aminopropane monoacetate 20.0
Isopropyl alcohol 30.0
Inert ingredients 50.0
NALCO 322
1-Alkyl (C to C ) amino-3-
aminopropane monoacetate 19.8
(continued)
Usage
Periodically, as
needed,25-400 ppm
or continuously
Weekly,20-300 ppm
Periodically, as
needed 300-400 ppm
or 12-60 ppm
continuously
5-200 ppm periodi-
cally or continu-
ously
Weekly,25-50 ppm
As needed,
50-100 ppm
Weekly,5-200 ppm
As needed,
10-200 ppm
232
-------
Chemical
TABLE 8.3 (continued)
Composition
Usage
2,4,5-Trichlorophenol
Isopropyl alcohol
Inert ingredients
NALCO 405
3,4-Dinitrochlorobenzene
2,6-Dinitrochlorobenzene
Inert ingredients
Betz A- 9
Sodium pentachlorophenate
Sodium 2,4, 5-trichlorophenate
Sodium salts of other
chlorophenates
Sodium dimethyl dithiocarbantate
N-Alkyl (C^ ~ 4%fC14 - 50%,C16
10%) dime thy Ibenzylammonium ;.
chloride
Inert ingredients (including
solubilizing and dispersing
agents)
Betz C-5
l,3-Dichloro-5,5-dimethylhydrate
Inert ingredients (including
solubilizing and dispersing
agents)
Betz C-30
Bis (trichloromethyl) sulfone
Methylene bisthiocyanate
Inert ingredients (including
solubilizing and dispersing
agents)
Betz C-34
Sodium dimethyl dithiocarbamate
Nabum(di sodium ethylene
bisdithiocarbamate)
Inert ingredients (including
solubilizing and dispersing
agents)
9.5
27.0
43.7
22.2
2.8
75.0
24.7
9.1
2 . 9
4.0
5 . 0
54.3
50
50
20.0
5.0
75.0
15.0
15.3
69.7
As needed,
100-200 ppm
(continued)
233
-------
TABLE 8.3 (continued)
Composition
Chemical (%) Usage
Betz J-12
N-Alkyl (C12 - 5%,C,4 - 60%,Gig -
30%,C18 - 5%) Dimgthylbenzyl -
ammonium chloride 24.0
Bis(tributyl tin) oxide 5.0
Inert ingredients (including
solubilizing and dispersing
agents) 71.0
Betz F-14
Sodium pentachlorophenate 20.0
Sodium 2,4,5-trichlorophenate 7.5
Sodium salts of chlorophenate 2.5
Dehydrobutyl ammonium phenoxide 2.0
Inert ingredients, including dis-
persants 68.0
234
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TABLE 8.4. WOOD PRESERVATIVES USED FOR PRETREATMENT
OF WOOD IN COOLING TOWER INSTALLATIONS(7)
Celcure (Acid Copper Chromate)
Chemonite (Ammoniacal Copper Arsenite)
Chlorinated Paraffin
Copper Naphthenate
Creosote
Erdalith (Chromonated Copper Arsenate)
Flouride Chromate Arsenate Phenol
Pentachlorophenol
235
-------
REFERENCES
1. Rice, J. K. and S. D. Strauss. Water Pollution Control in
Steam Plants. Power, 120(4):S-1-S26, 1977.
2. E. Nordell. Water Treatment for Industrial and Other Uses,
2nd Edition, Reinhold Publishing Corporation, New York,
1961.
3. U.S. Environmental Protection Agency. Process Design
Manual for Suspended Solids Removal. EPA 625/l-75-003a,
1975.
4. Grits, G. J. and G. Glover. Cooling Slowdown in Cooling
Towers. Water and Waste Engineering, 12(4):45-52, 1975.
5. U.S. Environmental Protection Agency. Development Docu-
ment for Effluent Limitations Guidelines and New Source
Performance Standards for the Steam Electric Power Generat-
ing Point Source Category. EPA 440/1-74/029-a, Group I,
1974.
6. Farber, A. L. Management of Cooling Water—State-of-the-
Art. Proceedings of the Fourth Annual Industrial Pollu-
tion Conference, Sponsored by Water and Wastewater Pollu-
tion Manufacturers Association, Houston, Texas, March 30-
April 1, 1976. pp. xxiv-l-xxiv-12.
7. Hittman Associates, Inc. Saltwater Cooling Towers: A
State-of-the-Art Review. Preliminary Draft Report No.
HIT-700, Hittman Associates, Inc., Columbia, Maryland, 1977.
8. Serper, A. Selected Aspects of Waste Heat Management: A
State-of-the-Art Study. Electric Power Research Institute,
Inc., Palo Alto, California, EPRI Report No. FP-164, 1976.
(Available from National Technical Information Service,
Springfield, Virginia, PB-255 697).
9. Stanford, W. and G. B. Hill. Cooling Tower - Principles
and Practice, Second Edition. Carter Thermal Engineering
Ltd., England, 1970.
10. Cappeline, G. A., J. G. Caroll, and S. D. Strauss. Enhance
Your Cooling System's Performance through Proper Use of
Microbiocides. Power, October 1977, pp. 56-61.
236
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SECTION 9
METHODS OF CLOSED-CYCLE COOLING WATER TREATMENT
9.1 CURRENT TREATMENT TECHNOLOGY
9.1.1 Survey of Current Practice
In 1974, a power plant survey was conducted to determine
the current industry practices in the treatment of recirculating
cooling water in the power industry and to collect information
for determining the cycles of concentration at which the systems
are operated(1). There were 74 responses with respect to closed
systems from the 160 questionnaires that were sent. The break-
down of responses according to the type of recirculating cooling
system was as follows: ;
i
Mechanical draft cooling towers 46
Natural draft cooling towers 4
Cooling ponds, cooling lakes, and spray ponds 2_4_
Total recirculating systems 74
Of the plants reporting, 47 reported using water from sur-
face sources only, 24 from wells (3 from both) , and 3 from sewage
plant effluent. Of the 47 using water from surface sources only,
37 provided some form of treatment. Every plant not using sur-
face water reported some form of treatment. Table 9.1 summarizes
the types of water treatment reported.
The most common form of treatment used in the power indus-
try includes on-stream treatment of recirculating water and con-
sists of acid or base addition for pH control and chlorination
for control of biological fouling. Treatment of make-up water
is usually limited to screening, which is sometimes followed by
sedimentation. Slowdown is normally treated only to limit the
chlorine residual to that currently permitted under EPA dis-
charge limitations. Table 9.2 summarizes frequency and method
of blowdown treatment as reported in the 1974 Survey. Economics
dictate that these minimal treatment steps be applied where
water supply is plentiful.
Across the country, plant chemists and engineers have in-
dicated operations are generally trouble free. Some stations
have experienced biological fouling problems in the Circulating
water system during the summer months. Usual practice involves
237
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chlorination once per day during the summer months and once everj
other day during the winter months. The frequency of chlorina-
tion varies with change in the chlorine demand of the raw water
and other factors relating to local environmental conditions.
9.1.2 Current Treatment Objectives
Based on the nationwide survey, the cycles of concentration
presently average about 3.7 cycles for recirculating cooling
water systems(1).
As noted in Section 7, future recirculating systems may
operate at as high a cycles of concentration as possible in order
to minimize the make-up water requirement and blowdown rate. The
use of high cycles of concentration in circulating water to re-
duce make-up requirements is important where water is scarce;
reduction of blowdown is important where it is necessary to
treat the blowdown prior to discharge to a receiving water body.
Despite the desirability of operating at high cycles of
concentration under such conditions, there are upper limits at
which it is possible or practical to operate. These limits have
been described in detail in Section 7 and are necessary to con-
trol excessive amounts of corrosion, scaling, and fouling due to
high concentrations of certain contaminants in the recirculating
water. While the levels at which it is practical to operate can
be raised by using make-up treatment, corrosion resistant ma-
terials, and scaling, corrosion and fouling inhibitors, there are
still upper bounds to the permissible cycles of concentration.
9.1.3 Definition of Current Technology
Because of the wide range in water treatment practices used
for closed-cycle cooling systems, it is necessary to arbitrarily
make a distinction between current and near horizon technology.
As defined in Section 8, current technology" includes those water
treatment methods in common practice in the power industry to-
day. Based on the 1974 survey, current technology will be de-
fined to include the following:
1. No treatment or only screening of make-up water
2. No treatment of blowdown
3. Addition of chemicals for pH, corrosion and
scaling control and chlorination for control
of biological fouling in recirculating water.
238
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9.2 NEAR HORIZON TREATMENT TECHNOLOGY
Due to the large volume of water circulated in closed-cycle
cooling systems, current practice for the most part has pre-
cluded pretreatment of make-up water for economic reasons. As
water becomes scarce and environmental controls for discharge
more stringent, near horizon technology (NHT) will be adopted
as the next treatment stage by the steam-electric generating in-
dustry. The purpose of NHT is to obtain the maximum cycles of
concentration in the circulating water, consistent with the con-
trol limits provided in Section 7 and, thereby, to reduce both
water make-up and blowdown requirements. For this document,
NHT will include proven unit processes which are in current use
for large volumes of water and can be readily applied for treat-
ment of make-up, blowdown, and recirculating water.
9.2.1 Make-up Treatment
Filtration and cold lime-soda softening have been chosen for
near horizon treatment of make-up water. Although these proces-
ses have not yet been extensively applied to the treatment of
cooling water by the utilities, they are proven techniques which
have been used in industrial and municipal applications for many
years. Descriptions of these processes can be found in Section
8.
Two hypothetical freshwater sources (Ohio River and Lake
Erie) with different chemical constituency, Tables 9.3 and 9.4,
are used to illustrate how filtration and cold lime-soda soften-
ing of make-up water can increase the cycles of concentration.
The control limits presented in Table 7.4 were used to determine
the maximum allowable cycles of concentration.
For these illustrations, a recirculating flow of 500,000
gpm was assumed to calculate make-up and blowdown. Evaporation
and drift losses were assumed to be 2 percent and .003 percent
of the recirculating flow, respectively. Blowdown and make-up
quantities were calculated from the cycles of concentration,
evaporation, and drift using the equations presented in Section
7. For both current and near horizon technology, addition of
sulfuric acid to keep bicarbonate alkalinity at 50 mg/1 in the
recirculating water was assumed. The results of make-up water
treatment are shown in Tables 9.5 and 9.6 for the Ohio River
and Lake Erie waters, respectively.
Current technology was assumed to be coarse screening of the
make-up. Three cycles of concentration were assumed to be in
dicative of typical operating practice, based on the survey re
suits shown in Table 9.2. In both the Ohio River and Lake Erie
cases, suspended solids became the limiting factor at tnree
239
-------
cycles of concentration. NHT was represented by filtration and
the cold lime-soda processes. It was assumed that filtration
reduced the suspended solids concentration in the filtrate to
5 mg/1 without altering the rest of the water chemistry.
The quality of the filtered water and the effect of fil-
tration on make-up flow requirements and on the allowable cycles
of concentration are shown in Tables 9.5 and 9.6. As in the case
of current technology, sulfuric acid addition was assumed, for
maintaining the bicarbonate alkalinity at 50 mg/1. For the case
of the Ohio River water, the cycles of concentration were in-
creased to 9 as a result of filtration. The limiting criterion
for the Ohio River water at 9 cycles of concentration became the
product of the calcium and sulfate concentrations, which reached
1.49 x 106 as compared to the 1.5 x 10 limitation. For the
Lake Erie water, filtration of the make-up water permitted an in-
crease to 13 cycles of concentration because of the lower ini-
tial sulfate concentration. For this case, the product of the
magnesium and silicate concentrations approached the 35,000
limiting criterion.
The cold lime-soda softening process is capable of removing
calcium and magnesium from the make-up water by reaction with
lime and soda ash. Some silica is also removed with the result-
ing magnesium precipitate. A detailed description of the process
is in Section 8. The chemical composition of lime-soda softened
water and the net effect upon the allowable cycles of concentra-
tion are shown in Tables 9.5 and 9.6. Note that the sodium con-
centration is increased as a result of the soda ash addition.
In the case of the Ohio River water, the cold lime-soda
softening increased the cycles of concentration to 12. At this
level, the product of the magnesium and silicate concentrations
became controlling.
For the Lake Erie water example, the maximum permissible
cycles of concentration achievable with the cold lime-soda soft-
ening was 14. This is only a marginal improvement over the 13
cycles of concentration attained using filtration. For the
Lake Erie water, the product of the magnesium and silicate con-
centrations was controlling for both filtration and cold lime-
soda softening treatment of the make-up water.
The resulting reduction in blowdown and make-up quantities
are also shown in Tables 9.5 and 9.6. For the Ohio River water,
filtration reduces make-up and blowdown.flows by approximately
25 percent and 75 percent, respectively, as compared to current
technology. Cold lime-soda softening resulted in a reduction of
27 percent and 82 percent, respectively, for the make-up and
blowdown flows.
240
-------
For the Lake Erie water, filtration reduced make-up and blow-
down rates by 28 percent and 84 percent, respectively, while cold
lime softening resulted in respective reductions of 28 percent '
and 85 percent.
9.2.2 Circulating Water Treatment
The processes of sidestream filtration and warm lime-soda
softening have been selected as examples of the application of
near horizon technology for the sidestream treatment of the cir-
culating water. Sidestream treatment consists of treating a
portion of the circulating water and returning it to the cooling
system. Byproduct streams, such as sludge or filter backwash,
are not returned to the cooling system and must be replaced 'with
additional make-up quantities. Sidestream treatment can be en-
visioned as the equivalent of a blowdown recovery process which
recycles treated water to the circulating water system.
9.2.2.1 Warm Lime-Soda Process —
As discussed in Section 8, the warm lime-soda process relies
on the increased water temperature at the exit of the condenser
to accelerate the cold lime-soda process reactions. Typically,
temperatures of 80 to 120°F (27 to 49°C) are attained in cir-
culating cooling water systems, and experience has shown that
these temperatures are almost as effective as the 200°F (93°C)
temperature employed in the hot lime-soda process (2). In ad-
dition the silica removed per part of magnesium removed in-
creases at high silica concentration. These factors make warm
lime-soda treatment a very attractive near horizon treatment
process for removing calcium and magnesium hardness and silica.
As an illustration of the potential of the warm lime-soda
process, consider the Ohio River example discussed in Section
9.2.1 and the control limits given in Table 7.4 for high cycles
of concentration. Assume that filtration is used for treatment
of the make-up water. The warm lime^soda process will be used to
control the concentration of silica below 150 mg/1 and the solu-
bility product of magnesium and silica will be held to less than
60,000. It was assumed that the warm lime-soda process is capable
of reducing the silica concentration to 20 mg/1 and the magnesium
concentration to 80 mg/1 as CaCO3(3,4).
The amount of sidestream treatment will be adjusted to
achieve operation at the desired cycles of concentration. The
quantity of blowdown can be computed from Equation (7.4) as:
For assumed operation at 30 cycles of concentration, an evapora
241
-------
tion rate of 10,000 gpm and drift losses of 15 gpm,
B =
The flow rate of the sidestream treatment required can be
estimated on the basis of maintaining the silica level and the
solubility product of magnesium and silica within prescribed
limits. It will be assumed that the solubility product of 'mag-
nesium and silica will be the controlling criterion. The re-
quired sidestream treatment flow and silica and magnesium con-
centrations in the recirculat'ing water are computed from material
balances, Equations (9.1) to (9.3), described below. In these
equations the variables are defined as follows:
x = concentration of magnesium in circulating
water (mg/1 CaC03).
y = concentration of silica in circulating
water (mg/1 Si02) .
z = sidestream treatment (gpm) .
Solubility Product Limitation;
xy < 60,000 (9.1)
"Mg" Material Balance:
Blowdown = Make-up - Sidestream Removal
(330) (x) - (10,345) (44) - (z) (x - 80) (9.2)
where:
44 mg/1 is the concentration of magnesium in
the make-up water, and 80 mg/1 is the concen-
tration of magnesium to be maintained in the
sidestream.
"Si" Material Balance:
Blowdown = Make-up - Sidestream Removal
(330) (y) = (10,345) (8.4) - (z)(y - 20) (9.3)
where:
8.4 mg/1 is the concentration of silica in
the make-up water; 20 mg/1 is the concentra-
tion of silica to be maintained in the sidestream.
242
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Solving Equations (9.1), (9.2), and (9.3) simultaneously,
x = 550 mg/1 (Mg concentration as CaCO,,)
y = 110 mg/1 (Si02 concentration)
z = 575 gpm (sidestream treatment flow)
It can be seen that the silica concentration and the magne-
sium-silica solubility product remain within limits. In order to
maintain the calcium sulfate solubility product within limits,
however, it may be necessary to use hydrochloric acid instead of
sulfuric acid for alkalinity control to reduce sulfate accumula-
tion.
In the example presented, warm lime-soda sidestream treatment
of less than 0.5 percent of the make-up water flow can increase
the cycles of concentration from 9 to 30. In both cases, fil-
tration of the make-up water was assumed.
9.2.2.2 Sidestream Filtration—
In some cooling water systems, dust entrainment in the cool-
ing tower can be a major source of suspended solids. It has been
estimated that a normal industrial ambient atmosphere can add
approximately 75 mg/1 of suspended solids on a make-up flow
basis(3). This added dust can cause suspended solids levels to
approach the 400 mg/1 limitation at only 5 cycles of concentra-
tion. Sidestream filtration can effectively control the sus-
pended solids level to permit operation at higher cycles of con-
centration. While warm lime-soda softening can also remove sus-
pended solids, filtration may be more economical, if silica or
magnesium-silica levels are not controlling. In some cases, the
combination of sidestream warm lime-soda softening (Subsection
9.2.2.1) followed by filtration may permit operation at very
high cycles of concentration.
9.2.3 Slowdown Treatment
While most power plants discharge blowdown from circulating
water directly into receiving waters, evaporation ponds are some-
times used in the arid regions of the United States. Evapora-
tion ponds can provide a cost effective solution for blowdown
disposal, if the cost of transporting the blowdown to an accept-
able alternative surface water body is excessive and groundwater
injection is prohibited. Because the cost of constructing an
evaporation pond with an impermeable liner to prevent ground
water contamination is high, evaporation ponds often are ?e
in conjunction with make-up and sidestream treatment to mi
the blowdown volume and the size of the evaporation ponds.
243
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As an example of an evaporation pond application, the water
treatment system for the proposed Sundesert Nuclear Plant will
be discussed(5). This station would utilize irrigation water
high in dissolved solids as a source of make-up water. An
analysis of this irrigation water is shown in Table 9.7.
To minimize the blowdown, the Sundesert Nuclear Plant is de-
signed to employ clarification and partial softening of the make-
up water and sidestream clarification and softening of the cir-
culating water. Table 9.8 summarizes the effluent from each of
the make-up and sidestream treatment processes (5). The para-
meters shown in Table 9.8 for the high cycles of concentration
are within the suggested criteria shown in Table 7.4. A small
amount of sulfuric acid is also added to the make-up stream to
prevent calcium carbonate deposition. The sidestream clarifier
operates in the 75 to 129°F (24 to 54°C) range, which is suf-
ficient to enhance silica reduction. The cycles of concentration
value computed from Equation (7.4) for this plant is 17.5.
(Equation (7.4) does not account for blowdown of sludge from the
sidestream clarifier.)
The cycles of concentration can also be estimated by com-
paring the ratio of the chloride concentration in the circulating
water to that in the raw make-up water. The cycles of concentra-
tion computed using the chloride concentration is 17.3, which
compares favorably with the 17.5 value given above.
9.2.4 Costs of Near Horizon Technology
The approximate cost for the types of treatment discussed in
Section 9.2.1 and 9.2.2 is shown in Table 9.9. Capital costs,
which affect the approximate installed value in 1978 dollars,
were estimated from equipment costs assuming installation costs
were 40 percent of the equipment costs. An additional 10 per-
cent of equipment costs was assumed for electrical work and 35
percent for contingencies in developing the cost estimates.
The cost of the evaporation pond is based on excavation and mem-
brane liner costs for 200 acres of evaporation pond area.
Table 9.10 presents the assumed chemical consumption as
estimated from the water quality analysis for each of the ex-
amples. Chemical costs are presented in Table 9.9 without and
with the addition of ferric chloride to the clarifiers to im-
prove the settling of solids. Chemical consumption for the ir-
rigation waste water example was obtained from Reference 5.
No attempt was made to estimate labor requirements for
operating and maintaining the water treatment system, power cost,
and the cost for disposal of sludge.
244
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The total annual costs presented in the last column of
Table 9.9 were obtained by amortizing the capital cost over 20
years at 7 percent and adding the capital recovery costs to the
chemical costs. The total annual cost figure includes the ad-
dition of ferric chloride in the water softening steps. Table
9.9 shows that filtration with sidestream warm lime-soda soft-
ening can be competitive with cold lime-soda softening of the
make-up water in some cases.
9.3 SPECIALIZED CASES OF MAKE-UP WATER >
A few power plants have utilized sea water or sewage treat-
ment plant effluent as make-up water for circulating cooling
water systems. Special problems or experiences reported from
such plants are briefly summarized in this section.
9.3.1 Use of Brackish or Saline Water
In a 1977 draft report to EPA(6), Hittman Associates re-
ported that there were five steam-electric generating plants in
the United States, which utilized salt or brackish water as the
source of make-up water. Of these, only the Atlantic City
Electric Company's B. L. England Station is listed as a fully
operational saltwater cooling tower system. Two of the stations
are experimental. Two plants (Chalk Point, p'otomac Electric
Power Company; and Jack Watson, Mississippi Power Company) uti-
lize brackish water as the make-up supply. The Delmarva Power
Company's Vienna Station uses, as make-up, river water which is
seasonably brackish.
A typical composition of sea water is given in Table 9.11.
The composition of coastal and estuarine (brackish) waters vary.
They generally contain less chlorides, but more bicarbonates,
calcium, potassium, and silica than sea water. A brackish water
is defined as any water containing between 3,000 and 20,000 mg/1
total dissolved solids.
The primary effect of saline water is to increase the cor-
rosion rate of metals within the cooling system. High salt con-
centrations can cause spalling of concrete and delamination of
asbestos cement. Special construction materials, such as suitate
cement and silicon bronze or stainless steel hardware, are uti-
lized in constructing saltwater cooling systems.
Icing problems, normally associated with freshwater cooling
towers in cold climates, are reduced with the use of sea water
On the other hand, saltwater drift and spray are larger and can
be detrimental to vegetation and equipment in the down-wind
areas.
245
-------
Atlantic City Electric's B. L. England Unit 3 (175 MWe),
completed in 1974, utilizes sea water from Great Egg Harbor Bay
as a source of make-up water. The bay water is tidal with an
average of 30,000 mg/1 total dissolved solids. The unit is cool-
ed by a Reserach Cottrell natural draft hyperbolic, counterflow
cooling tower. This is the first saltwater cooling tower de-
signed and operated in the United States.
Approximately 65,000 gpm of sea water at 1.5 to 2 cycles of
concentration are circulated to cool Unit 3. Approximately
3,000 gpm is blown down from the cooling tower and discharged
into the circulating water intake system of the other two units,
which operate with once-through cooling.
The saline make-up water receives no pretreatment other than
screening. When Unit 3;went on line, sulfuric acid was added
to the recirculating water to maintain a pH between 7.0 and 7.5
to control scaling. For the past two and a half years the acid
feed has been discontinued, allowing the pH to naturally rise
in the closed system to about 8.5. Theoretically, the recircu-
lating water should be scale forming; however, no scale has been
observed, perhaps due in part to an increase in solubility of
CaCC>3 in saline water.
The cooling tower trays are asbestos cement filled with a
concrete piping distribution system. The condenser tubes are
90-10 copper-nickel alloy. No unusual maintenance problems have
been experienced.
The utility produces sodium hypochloride (NaOCl) from the
sea water by electrolysis for disinfection. The cooling water
is chlorinated downstream of the cooling tower in order to main-
tain a free chlorine residual of 0.5 mg/1 in the recirculating
water. The 3,000 gpm blowdown from Unit 3 mixes with the other
discharges from Unit 3 and is discharged at the plant intake,
thereby dissipating the chlorine residual held in the recir-
culating cooling water.
9-3.2 Use of Sewage Effluent
Some power plants have used municipal sewage effluents as
a source of make-up water for cooling systems. This application
is limited to those power plants located close to large munici-
pal waste water treatment plants.
The quantity of effluent available from a municipal waste
water treatment plant depends on the size of the population
served, the variation in flow rates due to weather conditions,
and water usage patterns. Typical waste water generation varies
from 100 to 200 gallons per capita per day, depending on the ex-
246
-------
tent of water conservation measures, infiltration, and inflow.
Total municipal waste water reuse by industries in 1974 was
reported by the United States EPA to be 133 billion gallons per
year based on use at 358 locations. Of this, approximately 20
percent was used by the power generation industry.
Table 9.12 presents a typical analysis for raw sewage and
effluent from a secondary municipal waste water treatment plant.
EPA has required that all municipal waste water treatment plants
achieve at least secondary treatment by 1981. In secondary
treatment, biochemical oxygen demand (BOD) is reduced by con-
version of dissolved organics and carbohydrates to microbial
mass during the activated sludge process. This microbial mass
is then recaptured through secondary sedimentation.
In some instances, more advanced treatment is required to
remove nitrogen and phosphorous or reduce suspended solids and
BOD to very low levels. Some advanced treatment techniques,
such as lime precipitation for phosphorous removal and filtra-
tion, approach near horizon technology for cooling system make-
up. These treatment techniques supplement normal municipal
treatment of effluents with chlorine or ozone prior to discharge
to a receiving water body.
Treated waste water may be utilized as make-up for recircu-
lating systems without further "polishing" in many instances.
The treatment methods previously discussed, such as filtration
and softening, are effective methods for further upgrading the
water quality if required. Activated carbon beds may also be
utilized to remove soluble refractory organics.
The waste water treatment plant for Colorado Springs current-
ly provides tertiary effluent to the Martin Drake Power Plant(7).
The Martin Drake Plant is located approximately two miles from
the waste water treatment plant and is a 60-MWe coal burning
plant. The power plant is equipped to use the tertiary effluent
for either cooling tower make-up or ash sluicing.
The Colorado Springs tertiary plant has two circuits, each
involving different processes. The industrial circuit has a
capacity of 2.0 mgd, which is directly piped to the Martin Drake
Power Plant. In the industrial treatment circuit, chlorinated
secondary effluent is initially subjected to solids contact
clarification using lime. The water is raised to a pH of 11.5
in this process, utilizing a lime dose of 300-350 mg/1. _Tne
high pH water leaving the solids contact unit is neutralized
with carbon dioxide from recalcination and augmented with sui
furic acid as needed. After pH neutralization, the water is
Passed through a dual media anthracite and sand filter ana a
247
-------
carbon adsorption tower.
The Southwestern Public Service Company has been utilizing
secondary-treated domestic waste water effluent for reuse in cool-
ing and boiler make-up at the Nichols Station Plant in Amarillo,
Texas and the Jones Station in Lubbock, Texas (7). The treated
effluent delivered to the Nichols and Jones Stations receives
primary and secondary treatment and is chlorinated to 0.1 mg/1
residual chlorine. Some problems with foaming, scaling, and bio-
fouling were experienced, and it was found'that treatment by
cold lime-soda softening to a high pH value could mitigate most
of these problems. At the Jones Station, filtration, reverse
osmosis, and demineralization are used to further treat a small
fraction of the waste water before its use as boiler make-up.
The Palo Verde Nuclear Generating Station of the Arizona
Nuclear Power Project is designed to utilize treated waste water
for cooling water make-up for each of its three 1,300-MWe units
(7). Each cooling system has been designed to operate at 15-20
cycles of concentration. To operate at these relatively high
cycles of concentration, the water quality parameters shown in
Table 9.11 are maintained in the make-up water system.
An economic analysis of various alternative treatment sys-
tems as reported in Reference 6 indicated that biological nitri-
fication, two-stage cold lime-soda softening, break-point chlo-
rination, and dual-media filtration would provide the most cost
effective treatment scheme.
248
-------
TABLE 9.1.
TYPE OF WATER TREATMENT ACCORDING TO EPA
REGION AND TREATMENT CATEGORY(1)
Treatment Category
Softening and solids
removal
Softening
Solids removal
pH adjustment
Acid applied
Base applied
Chemical additives
Corrosion inhibitor 0
Scale and fouling
inhibitor
Total make-up and
recirculating
treatment
I
0
0
°i
0
0
0
0
0
0
Plants
III IV
1
0
1
4
1
3
1
1
1
1
0
1
0
0
0
3
2
2
by
V
1
1
0
1
1
0
1
0
1
EPA
VI
2*
2
0
14
14
0
12
11
7
Region
VII VIII
0
0
0
3
3
0
4
3
2
1
1
1
4
4
0
5
4
2
IX
1
1
0
8
8
0
8
7
1
Total
Plants
7
5
3
34
31
3
34
28
16
18
44
249
-------
TABLE 9.2. RECIRCULATING SYSTEM PLANTS BY CYCLES OF CONCENTRATION RANGE
AND TYPE OF BLOWDOWN TREATMENT(1)
Plants by Cycles of Concentration Range
1 to 1.9 2 to 2.9 3 to 3.9 4 to 4.9 5 to 5.9 6 to 6.9 10 or
Greater
Total recirculating
plants for which
cycles of concen-
tration were cal-
culated
tv) Total plants with
Q blowdown treatment
Solids removal
Sedimentation
Filtration
Evaporation
None
9
1
t
1
1
0
0
8
7
4
4
4
4
0
3
9
0
0
0
0
0
9
11
2
2
2
2
1
9
4
1
1
1
1
0
3
2
1
1
1
1
0
1
2
2
2
1
1
1
0
-------
TABLE 9.3. ANALYSIS OF HYPOTHETICAL OHIO RIVER WATER
Calcium (Ca) as CaC03, rag/1 100
Magnesium (Mg) as CaC03, mg/1 44
t
Sodium (Na) as CaCO^, mg/1 87
Chloride (Cl) as CaCO.., mg/1 4X
Sulfate (S04) as CaC03, mg/1 140
Bicarbonate (HCO3) as CaC03, mg/1 50
Silica as Si02, mg/1 8.4
Suspended Solids, mg/1 90
pH 7.4
TABLE 9.4. ANALYSIS OF HYPOTHETICAL LAKE ERIE WATER
Calcium (Ca) as CaCO3, mg/1 78
Magnesium (Mg) as CaC03, mg/1 34
Sodium (Na) as CaC03, mg/1 15
Chloride (Cl) as CaC03, mg/1 17
Sulfate (S04) as CaCO3, mg/1 I6
Bicarbonate (HC03) as CaC03/ mg/1 94
Silica as Si02, mg/1 6
Suspended Solids, mg/1 10°
PH 7'3
251
-------
TABLE 9.5. EFFECT OF NEAR HORIZON TECHNOLOGY ON CYCLES OF CONCENTRATION
HYPOTHETICAL OHIO RIVER WATER
to
MAKE-UP WATER QUALITY AFTER TREATMENT
RECIRCULATING WATER
Cold
Current** Lime-Soda Current**
Technology Filtration Softening Technology
Calcium (as CaCO-)
mg/1 J 100 100 35
Magnesium " 44 44 33
Sodium " 87 87 181
Chloride " 41 41 41
Sulfate " 140 140 140
Bicarbonate " ,50 50 68*
Silica (as SiO )mg/l 8.4 8.4 7.5
£A
Suspended Solids
mg/1 90 5 10
Cycles of Concen-
tration
Limiting Criteria <
Slowdown Flow (gpm)
Make-up Flow (gpm) * «ivaiini*-v -« r^rn_
234
102
45
51
180
50
18
300
3
Suspended
Solids
200 - 300
4485
15000
Filtration
of Make-up
| 90Q|
396
776
369
1665
50
75.6
45
9
Calcium
Sulfate,
<1.5xlO
1235
11250
QUALITY
Cold
Lime-Soda
Softening
of Make-up
420
396
2172
492
2460
50*
90
120
12
Mg x Si02
<35,000
894
10900
**Limited to coarse screening
-------
TABLE 9.6.
EFFECT OF NEAR HORIZON TECHNOLOGY ON CYCLES OF CONCENTRATION
HYPOTHETICAL LAKE ERIE WATER
MAKE-UP WATER QUALITY AFTER TREATMENT
RECIRCULATING WATER QUALITY
Ul
Cold
Current** Lime-Soda
Technology Filtration Softening
Calcium (as CaCO )
mg/1 3 78 78 35
Magnesium " 34 34 33
Sodium " 15 15 33
Chloride " 17 17 17
Sulfate " 16 16 16
Bicarbonate " 94 94 68*
Silica (as SiO2)mg/l 665
Suspended Solids 100 5 10
Cycles of Concen-
tration
Limiting Criteria
Blowdown Flow (gpm)
Make-up Flow (gpm)
Current**
Technology
234
102
45
51
180
50
18
[ 3QO|
3
Suspended
Solids
200 - 300
4985
15000
Filtration
of Make-up
1014
|442|
195
221
1300|
50
78
65
13
Mg x SiO-
35,000
8J.8
10833
Cold
Lime -Soda
Softening
of Make-u
490
|462
462
238
|1134
50*
70
140
14
Mg x SiO
35,000
750
10776
2
* Total alkalinity as CaCO,
**Limited to coarse screening
-------
TABLE 9.7. ANALYSIS OF IRRIGATION WASTEWATER FOR THE PROPOSED
SUNDESERT NUCLEAR PLANT(5)
Calcium as CaC03 (mg/1) 398
Magnesium as CaC03 (mg/1) 184
Sodium as CaC03 (mg/1) » . . 911
Chloride as CaC03 (mg/1) 599
Sulfate as CaC03 (mg/1) 645
Bicarbonate as CaC03 (mg/1) 262
Silica as SiO2 (mg/1) 21
Suspended Solids (mg/1) 50
Total Dissolved Solids (mg/1) 2020
pH 8.0
TABLE 9.8. ANALYSIS OF WATER STREAMS FOR THE PROPOSED SUNDESERT
NUCLEAR PLANT(5)
Circulating
Make-up Water Sidestream
Average Flow (gpm) 11,000 475,000 6,000
Calcium as CaC03 (mg/1) 197 351 37
Magnesium as CaC03 (mg/1) 168 344 82
Sodium as CaCO3 (mg/1) 1,068 20,728 21,331
Chloride as CaC03 (mg/1) 694 10,356 10,375
Sulfate as CaC03 (mg/1) 730 11,284 11,284
Bicarbonate as CaC03 (mg/1) 33 43 35
Silica as Si02 (mg/1) 19 40 10
Suspended Solids (mg/1) ]_o 25 10
Total Dissolved Solids (mg/1)1,895 28,240 28,305
PH 10.2 7.9 10.2
254
-------
TABLE 9.9. COMPARISON OF TREATMENT COSTS FOR SELECTED EXAMPLES
Water Type of Treatment Gyles of Equipment Installed Chemical Total Annual
Source Treatment Flow concen- Cost Capital Costs1 Cost ($l,000/yr)
(gpm) tration ($1,000) Cost ($l,000/yr)
($1,000)
Lake No make-up
Erie treatment
Filtration
of make-up
Cold lime
softening
of make-up
to
^ Sidestream
softening
and fil-
tration of
15,000 3
11,250 13
10,900 14
30
- - 55
1,100 2,287 52
186.8
1,250 2,599 (138. 3)2
138.8
1,138 2,366 (132.4)2
55
268
432
357
make-up
Ohio No make-up
River treatment 15,000
Filtration
of make-up 10,800
Cold lime
softening
of make-up 10,800
1,000
2,079
12
1,250 2,599
(continued)
127.8
109.5
256.8
(209.3)
128
305
502
-------
TABLE 9.9 (continued)
IV)
ui
01
Water Type of Treatment Cycles of Equipment Installed Chemical Total Annual
Source Treatment Flow concen- Cost Capital Costs1 Cost ($l,000/yr)
(gpm) tration ($1,000) Cost ($l,000/yr)
($1,000)
Sidestream
softening
and fil-
tration of
make-up
575)
10,345J 30
329.3
1,038 2,158 (326.6)^
533
Sun- Partial
desert softening
Nuclear of make-up 11,000
Plant
Irri- Sidestream
gation softening 6,000
Waste
Water Evaporation
pond 682
17.5
1,250
550
3,742
24,000
9,063
3,525
NOTES:
Chemical costs were: hydrated chemical lime (93%)
at $35/ton, soda ash (99% Na2C03) at $60/ton,
sulfuric acid (100%) at $50/ton and ferric chloride
(100%) at $5/100 Ibs.
Items within parentheses denote chemical costs without
ferric chloride addition to improve coagulation.
-------
TABLE 9.10. ESTIMATED CHEMICAL CONSUMPTION FOR ALTERNATIVE TREATMENT
TECHNOLOGIES FOR SELECTED EXAMPLES
Source of
Water
Lake Erie
Type of Lime^3'
Treatment (Ibs/day)
Acid addition
for pH control
Filtration
of make-up
Soda AshlD) Sulfuric Acid
-------
TABLE 9.10 (continued)
Source of
Water
Type of
Treatment
Lime(a)
(Ibs/day)
Soda Ash(b>
(Ibs/day)
Sundesert Partial
Nuclear softening
Plant of make-up
Irrigation and sidestream
Waste softening
Water
50,000
48,000
Sulfuric
(Ibs/day)
5,000
Ferric
chloride
(d)
(Ibs/day)
4,300
Ul
CO
NOTE: (a) 93% hydrated lime
(b) 98% soda ash
(c) 98% sulfuric acid
(d) 20 mg/1 dosage on 100% basis
-------
TABLE 9.11. ANALYSES OF MAKE-UP WATER QUALITIES
U1
Typical Sea Water Analysis
Sodium Chloride (mg/1) 27,000
Magnesium Chloride (mg/1) 3,200
Magnesium Sulfate (mg/1) 2,200
Calcium Sulfate (mg/1) 1,200
Potassium Chloride (mg/1) 500
Calcium Bicarbonate (mg/1) 200
Potassium Bromide (mg/1) 100
Total Salinity (mg/1) 34,000
Total Alkalinity (mg/1) 115
pH 8.0
Make-up Waste Water Quality for Palo
Verde Nuclear Generating Station (7)
Calcium as Ca (mg/1) (28
Sulfate as SO4 (mg/1) <200
Silica as SiO (mg/1) <10
Ammonia Nitrogen (mg/1) < 5
Total Phosphorous (mg/1) <0.5
Suspended Solids (mg/1) <10
Biochemical Oxygen De-
man (mg/1) 10
Total Dissolved Solids
(mg/1) 900
pH 7.5-8.0
-------
TABLE 9.12. TYPICAL WASTE WATER AND TREATMENT PLANT ANALYSES
Parameter
Raw Sewage
Influent(8)
Primary Treatment Plant Secondary Treatment Plant
Effluent(7) (mean values) Effluent(7) (mean values)
Solids, total (mg/1)
Dissolved, total 980
Volatile 260
Nonvolatile 720
Suspended, total 200
Volatile 160
Nonvolatile 40
BOD (mg/1) 200
TOC (mg/1) 200
COD (mg/1) 400
Nitrogen (mg/1)
(total as N) 50
Organic 20
Free ammonia 30
Nitrates 0
Nitrites 0
Phosphorous (mg/1)
(total as P) 5 - 20(9)
93
167
142
346
24
20
13
Heavy Metals (mg/1) (typical from Reference 10)
14
188
165
156
550
1
176
191
Cadmium
Chromium
Nickel
Lead
Zinc
Mercury
Manganese
Copper
8
20
2
50
30
.2
20
- 142
- 700
- 880
-1270
-8310
- 44
-3360
37
28
35
86
19
11
50
202
165
67
238
6
144
92
-------
REFERENCES
1. Serper, A. Selected Aspects of Waste Heat Mangement: A
State-of-the-Art Study. Electric Power Research Institute,
Inc., Palo Alto, California, EPRI Report No. FP-164, 1976.
(Available from National Technical Information Service,
Springfield, Virginia, PB255 697).
2. Darji, J. D. Reducing Slowdown from Cooling Towers by Side-
stream Treatment. Proceedings of 5th Annual Industrial
Pollution Control Conference, Water and Wastewater Equip-
ment Manufacturers Association, Atlanta, Georgia, April
19-21, 1977.
3. Grits, G. J. and G. Glover. Cooling Slowdown in Cooling
Towers. Water and Wastes Engineering, 12 (4):45-52, 1975.
4. Betz Handbook of Industrial Water Conditioning. Seventh
Edition, 1976.
5. Stone and Webster Corporation. Conceptual Engineering:
Cooling System and Associated Water/Waste Treatment Systems.
Sundesert Nuclear Plant, Units 1 and 2, San Diego Gas and
Electric Company, 1975.
6. Hittman Associates, Inc. Salt Water Cooling Towers: A
State-of-the-Art Review. Preliminary Draft Report No.
HIT-700, Hittman Associates, Inc., Columbia, Maryland, 1977.
7. U.S. Environmental Protection Agency. Federal Guidelines-
Pretreatment Programs. EPA-430/9-76-017a. 1977.
8. MOP/8. Wastewater Treatment Plant Design. Joint Committee
of Water Pollution Control Federation and American Society
of Mechanical Engineers. 1977.
9. Metcalf and Eddy, Inc. Wastewater Engineering. McGraw-Hill
Book Company, New York, New York, 1972.
10. U.S. Environmental Protection Agency. Trace Metal Removal
by Wastewater Treatment. EPA Technology Transfer News-
letter. January, 1977.
261
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SECTION 10
FUTURE TECHNOLOGIES FOR CLOSED-CYCLE COOLING WATER TREATMENT
10.1 INTRODUCTION
Future technologies are defined as those processes which
have not been applied to recirculating cooling water systems in
power plants, but which may hold promise in solving, water
treatment problems in the future. These technologies are ap-
plicable for treatment of make-up water, circulating water, and
blowdown. The established processes outlined herein are costly,
but they provide either the ability to increase the number of
cycles of concentration or advanced treatment of blowdown.
10.2 TREATMENT OF MAKE-UP WATER
The most likely candidates for the application of future
technology to make-up waters are ion exchange resins for either
water softening or complete demineralization.
10.2.1 Ion Exchange Softening
In the water softening application, the water is passed
through a bed of ion exchange resin where the divalent and tri-
valent cations, such as calcium, magnesium, and iron, are re-
moved from the water and replaced with sodium ions. The re-
moval of the calcium and magnesium ions reduces the hardness
and, consequently, the scale forming tendency of the water. The
sodium forms extremely soluble salts with the bicarbonate, sul-
fate, and chloride ions, and even at high concentrations these
salts do not result in scale formation.
The exchange medium is exhausted when most sodium ions have
been replaced by divalent and trivalent cations. At this point,
the resin must be regenerated by passing a concentrated solution
of sodium chloride through the medium, which reverses the pro-
cess as sodium ions replace the divalent and trivalent cations.
In practice, the resin is never in a state of complete exhaus-
tion or regeneration but functions effectively until small but
appreciable quantities of hardness escape through the exchange
medium.
Ion exchange softening can reduce the °*ici™^™%*™™
hardness to a few mg/1. The waste water produced during regen
263
-------
eration contains naturally occurring hardness ions in solution
with chloride plus excess sodium chloride. This waste water is
relatively harmless to biota and may be permitted to be directly
discharged to a receiving water body.
Ion exchange softening is more readily applicable to treat-
ing make-up flow, since the high concentrations of dissolved
solids which occur in the recirculating water adversely affect
the ion exchange equilibrium and leakage.
10.2.2 Ion Exchange Demineralization
In complete demineralization applications of ion exchange
technology, all ions are removed and replaced with hydrogen and
hydroxyl ions to produce a water comparable in quality to dis-
tilled water. The process is usually conducted in two steps.
First, an acid-cation exchange resin replaces the cations in the
water with hydrogen ions. In the second step, base-anion exchange,
the exchange resin replaces the anion ions (such as bicarbonates,
sulfates, and chlorides) with the hydroxyl ion. For complete
demineralization, strong acid and strong base exchange resins are
used.
Several variations of the basic demineralization approach
have been developed using combinations of strong acid-weak base
and weak acid-strong base exchange resins to achieve different
degrees of cation and anion exchange. In some processes the
acid and base exchange resins are contained in the same column.
An economic evaluation must be made in each case to determine
the best combination of exchange resins and procedures.
As an example of the application of a demineralization pro-
cess to make-up water, consider the use of a carboxylic acid
cation exchange resin for the removal of hardness (calcium and
magnesium) and alkalinity. The metal cations (Ca++, Mg++, and
Na ) are absorbed by the carboxylic acid resin and exchanged for
hydrogen ions. The released hydrogen ions further react with the
bicarbonate ion (HCO3~) to form carbonic acid (H2CO3). Finally,
the carbonic acid causes a shift in the bicarbonate equilibrium
to produce carbon dioxide and water. The reactions for the
process can be schematized as follows:
Resin - H + Ca++ ^Resin Ca++ + H+
H2CO3
264
-------
While some forms of demineralization can tolerate high
levels of dissolved solids, as in the case of ion exchange soft-
ening, the process is more applicable for treatment of make-up
water. Demineralization wastes, however, may be more difficult
to dispose than those which result from ion exchange softening
since they contain excess acids and alkalis.
10.3 TREATMENT OF CIRCULATING WATER
The most likely candidates for the application of future
technology to recirculating water are the use of membrane tech-
nology to control dissolved solids and the use of ozone to con-
trol- biological fouling.' One additional technology which may
have some application potential is sidestream lime-barium soft-
ening.
10.3.1 Membrane Processes
r- The main application of membrane processes to recirculating
cooling water systems is to control the concentration of dis-
solved solids by treating a portion of, the recirculating flow
(sidestream treatment). The two most common forms of membrane
processes are reverse osmosis and electrodialysis. Both pro-
cessses are subject to fouling by particulate matter when applied
to streams containing even low concentrations of suspended
solids. -,
2 -in reverse osmosis, water moves across a semipermeable
membrane from a region of high solute (dissolved salts) concen-
tration to a region of lower solute concentration as a result
of the application of a pressure gradient. In an application of
reverse osmosis to circulating cooling water, a portion of the
flow enters the concentrated side of the semipermeable membrane.
The membrane permits desalinated water to pass through the mem-
brane while rejecting dissolved salts, colloids, microorganisms,
and particulates. The desalinated water is then returned to the
circulating water system, while the concentrated salt stream is
disposed. The most common types of reverse osmosis membranes
commercially available are the tubular, spiral wound, and hollow
fiber configurations. Cellulose acetate and polyamide are now
the commonly used synthetic membranes. These membranes pre-
ferentially reject divalent ions, resulting in a 99 percent re-
jection efficiency for calcium, magnesium, and sulfate as com-
pared to a 95 percent rejection efficiency for sodium and
chloride(1).
One of the major problems facing reverse
that the membranes suffer from compaction with
suits in a continual deterioration of flux rat
jection efficiency, which are accelerated at high pressures
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a result, most manufacturers guarantee only a three-year life
with a factorial reduction in operating flux.
During the last few years , several sea water reverse osmosis
installations have been in service. These systems have operated
without any acid or other chemical pretreatment and produce water
with an average TDS content of 400 to 800 mg/1 in a single stage
(3). This amounts to about 98 percent removal of salts. Assuming
the membranes resist deterioration, this technology appears adapt-
able for salt or brackish make-up supplies or sidestream treat-
ment.
In electrodialysis, a combination of direct current and al-
ternating cation and anion selective membranes are used to remove
salts from water. The cation and anion membranes are stacked
in an alternating array with electrodes at each end of the stack.
The liquid passes between the membranes with the ions moving
perpendicular to the membranes.
The electric currents induce a flow of anions and cations
across the membranes. As a result of the process, the salinity
of the water in half of the cells decreases, while it increases in
the other half. The water in the cells with the reduced salinity
can be returned to the cooling system, while the concentrated
brine is either recirculated to the concentrated cells of the
electrodialysis unit for another pass or discharged for disposal.
Unlike the reverse osmosis membranes, electrodialysis mem-
branes preferentially transport divalent ions. The electrodial-
ysis membranes also do not undergo compaction with time and have
a longer life expectancy than do the reverse osmosis membranes.
Although electrodialysis membranes are not sensitive to tempera-
ture, they are more sensitive to chlorine degradation than are
reverse osmosis membranes.
10.3.2 Lime-Barium Softening
Barium hydroxide can be used in a sidestream precipitation
process to reduce sulfate and silica levels in the circulating
water. The barium hydroxide reacts with the sulfate present to
form insoluble barium sulfate and two hydroxide ions.
Ba(OH)0 + SO" - *-BaSO, I + 2(OH~)
In the presence of magnesium, magnesium hydroxide also
precipitates, and silica is removed in an adsorption reaction
with the magnesium hydroxide. The adsorption of silica with
magnesium hydroxide will also occur during cold-lime-soda soft-
ening. Therefore, the main advantage of this process over cold
lime-soda softening is the removal of sulfate ions. The process
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is more applicable for sidestream treatment than make-up treat-
ment because of the high cost of barium hydroxide. The toxicity
of barium compounds may also pose special disposal problems.
10.3.3 Use of Ozone to Control Biological Fouling
Ozone is receiving attention as an alternative to chlorine
for many disinfection and biocidal applications, because it does
not produce persistent residuals. As noted previously, chlorine
reacts with ammonia and organic compounds to form chlorinated
amines and hydrocarbons. Some of the chlorinated hydrocarbons
have been found to be carcinogenic at fairly low concentrations.
Ozone, on the other hand, is a strong oxidant (exhibiting ap-
proximately twice the oxidizing power of chlorine) which dis-
sociates into oxygen without the production of such deleterious
derivatives as chlorinated hydrocarbons. While ozone has been
used widely in Europe, it- has not been economically competitive
with chlorination in the United States.
The testing of ozone as a biofouling control agent in sa-
line waters was conducted by the United Stated Department of the
Interior (4). In general, it was found that maintaining an ozone
residual of approximately 1.0 mg/1 was effective in controlling
barnacles, algae, and slime. The results, however, suggest that
continuous rather then intermittent ozonation may be necessary.
Further testing is required to establish recommended dosage
rates for non-marine applications and to protect metal compon-
ents from ozone oxidation.
10.4 TREATMENT OF SLOWDOWN WATER
Presently, the regulatory guidelines specify limitations
with respect to residual chlorine content for cooling water
discharges. More strict standards will apply to "new sources,"
i.e., plants whose construction started after March, 1974.
These stations will have to meet "no detectable amount" limita-
tions with respect to chromium, zinc, and phosphorous as well
as other corrosion inhibitors. •
For power stations using recirculating evaporative cool-
ing tower systems, blowdown from the tower is the largest volume
of waste water produced by the station. As the cycles of concen-
tration is increased through the utilization of pretreatment
or sidestream processes, the blowdown volume will decrease. Tne
concentration of constituents in the waste water, however, will
increase by several fold, and the composition may change through
the addition of inhibitors dictated by the higher cycles of con
centration. Consequently, treatment employed for the blowdown
will depend on the waste constituents present.
In the past, most power plants have discharged blowdown
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water directly into a receiving surface water body. In a few
cases, sedimentation ponds have been used to reduce the sus-
pended solids concentration prior to discharge. With the
advent of more advanced treatment procedures for make-up and re-
circulating water, the concentration of dissolved constituents
in the blowdown may be expected to increase. Future 'regula-
tions may limit the discharge of concentrated blowdown streams
into surface waters. As a result, more elaborate treatment
processes for reducing the volume of the blowdown waste stream
may be required.
Of major importance is the treatment of blowdown discharge
when several waste water streams are combined. Effluent limita-
tions for a plant which combines its waste water streams should
not reflect pollutant reductions less than would be achieved
if each stream were individually treated. In light of this, it
should be noted that all power plant waste sources identified
by EPA, other than cooling water, have suspended solids and pH
limitations. Currently, oil and grease limitations are not
applicable to rainfall runoff, and copper and,iron limitations
are included only for boiler blowdown and metal cleaning wastes.
If it is desired to combine all streams for treatment, it
is necessary to monitor the copper and iron content of all
streams not regulated for these parameters and the oil and grease
content of rainfall runoff prior to combination to demonstrate
that a particular pollutant is actually reduced rather than
simply diluted. This can become a burdensome task depending
upon piping logistics. In addition, it is necessary to monitor
each point of discharge to the receiving body of water.
Other potential concerns of such a combined scheme are the
resulting low effluent limitations for iron, copper, oil and
grease which result when large quantitites of a stream not re-
gulated for these parameters, and containing negligible concen-
trations of these parameters, are mixed with small quantities
of wastes regulated for these parameters. It is possible that
an effluent limitation could be imposed which is unattainable
by conventional treatment processes.
Two processes which may have application for treatment of
blowdown wastes are reverse osmosis and evaporation. Reverse
osmosis has been discussed previously in this section. The
evaporation can be performed in solar evaporation ponds, flash
evaporators, single step distillation units or vacuum compres-
sion evaporators. In all cases, the object is the same, to con-
centrate the dissolved solids into a brine while returning the
purified water to the cooling system.
To reduce solids buildup in the evaporation process, it is
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expected that the blowdown will first pass through a coagulation
and sedimentation process to remove suspended solids. Sludge
from the sedimentation steps, as well as the concentrated brine,
may require further dewatering prior to land disposal. The de-
vices applicable for sludge dewatering were discussed in Section
8.
The treatment of blowdown discharge requires a commitment
of energy and capital investment. The solids removed during
blowdown treatment will usually be disposed in the form of? sludge
in an approved landfill. The additional cost of blowdown treat-
ment should, therefore, be carefully weighed against the degree
of environmental impact that an untreated discharge may impart
to the receiving waters.
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REFERENCES
1. Rice, J. K. and S. D. Strauss. Water Pollution Control in
Steam Plants. Power, 120(14):S-1-S-20, 1977.
2. Mattson, M. E. Membrane Desalting Gets Big Push. Water
and Wastes Engineering, 12(5):35-45, 1975.
3. Seawater Desalination with DuPont B-10 Permasep Permeators.
Reprint from Desalination, 19:201-210, 1976.
4. Methods for Controlling Marine Fouling in Intake Systems.
Pamphlet, U.S. Department of Interior, Office of Saline
Water, 1973.
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SECTION 11
ENVIRONMENTAL IMPACTS OF CLOSED-CYCLE COOLING SYSTEMS
11.1 BACKGROUND
11.1.1 Overview
This section provides background information on the environ-
mental impacts resulting from the operation of closed-cycle cool-
ing systems and indicates control measures for reducing or elimi-
nating these impacts. Enviromental impacts of closed-cycle
cooling systems can be divided into three broad categories.
These are: 1) hydrological and aquatic impacts, 2) atmospheric
and terrestrial impacts, and 3) land use aesthetics and noise
impacts. A general description of each of these impacts follows;
detailed discussions are included in subsequent subsections.
11.1.2 Hydrological and Aquatic Impacts
Hydrological and aquatic impacts are those effects caused
by the make-up water intake structure itself, effects due to the
water consumption, and effects created by the cooling tower blow-
down. Make-up water intake structures may entrain organisms that
lack sufficient mobility to withstand the pumping forces. These
organisms may impinge on intake screens intended to prevent the
entry of debris with the water supply. As a result, not only
will these organisms be damaged or destroyed, but operating ef-
ficiencies of the closed-cycle cooling system may be reduced.
Most water consumed by a closed-cycle cooling system is
lost via evaporation. Evaporative losses place a renewal burden
on the water body from which the supply is drawn. This consti-
tutes a depletion of resources, if the water body is incapable
of replenishing the supply in quality and quantity.
Slowdown water has relatively high temperature and relatively
high concentration of total dissolved solids. Depending on the
amount and the nature of the receiving water body, cooling water
blowdown can cause detrimental effects. These effects can be,
for example, damage to the ecology of the receiving body of
water and an overall lowering of the water quality, since ex-
cessive chemical or heat loading on the biota _may alter tne
ecology in the area where these waters are being discharged.
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11.1.3 Atmospheric and Terrestrial Impacts
Atmospheric and terrestrial impacts are those effects caused
by the discharge of large quantities of warm, humid air into the
atmosphere, as well as effects on biota due to the entrained im-
purities in the discharged vapor. Although airborne heat and
water vapor emitted from closed-cycle cooling systems are not
classified as pollutants, large amounts of water vapor are re-
leased to the atmosphere by these systems. Once released to the
atmosphere, the excess vapor cools and may form local fog or ice
conditions in the winter and may lead to increased precipitation.
If the emitted water vapor mingles with a nearby industrial stack
plume containing a reactive substance such as sulfur dioxide,
environmental damage can occur.
Another potential atmospheric impact is that caused by drift.
Drift is that fraction of the circulating cooling water exhausted
to the atmosphere as water droplets. Upon leaving the cooling
system, drift rises and may descend to the ground at various dis-
tances depending on the local meteorological conditions. As the
water droplet evaporates, all the constituents in the water (pri-
marily water treatment chemicals and dissolved salts) concentrate
and, if deposited, can cause damage to nearby soils and vegeta-
tion, as well as materials ajnd equipment subject to corrosion.
,• i
11.1.4 Land Use Aesthetics and Noise Impacts
Land use, aesthetics and noise impacts are those effects
related to the quantity and utilization of land required by the
various closed-cycle cooling systems, their visual and noise
impacts to the environment as a whole. The siting of a closed-
cycle cooling system on a tract of land effectively removes that
land from other constructive uses. The land requirements may be
relatively large as that needed for a cooling pond. Impacts to
the environment, such as erosion, sedimentation, ground water
contamination, defoliation, and habitat modifications, must be
considered. In addition to these impacts, the noise generated
by the various modes of closed-cycle cooling must be considered
relative to background noise already present at the site.
Visual impacts and aesthetics are factors which must also
be taken into account when the environmental impacts of closed-
cycle cooling systems are reviewed. The type and elevation of
the cooling system to be used, prominent viewpoints, ground cover
and subjective considerations by the affected population must be
taken into account.
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11.2 IMPACT OF INTAKES
11.2.1 Introduction
Steam-electric power generating stations operated with
closed-cycle cooling drastically reduce the requirements for
cooling waters when compared to operation with a once-through
cooling system. Although closed-cycle cooling requires a small-
er volume of water (approximately 10,000 gpm as make-up) than
that of a once-through cooling system, the volume required for
a 1000-MWe power plant is comparable to the water use of a munici-
pality of 100,000 people. Therefore, the environmental impact
of intakes remains an important consideration of intake designs
that have been used by other industries and which have the po-
tential to minimize the impact of the cooling system on the en-
vironment.
A Federal Power Commission (FPC) nationwide survey(1) in-
dicated that, out of 651 power plants surveyed, 17.2 percent used
cooling towers for heat dissipation, 5.4 percent used cooling
ponds, 18.9 percent used once-through cooling with saline water,
49.8 percent used once-through cooling with freshwater, and 8.7
percent used a combined system. Subsequent FPC reports based
input from power plants (Form 67) show a trend of increasing
use of closed-cycle cooling for dissipating heat from condensers.
With the use of closed-cycle cooling, only the size of the once-
through cooling intake structure is changed for closed-cycle
cooling since less cooling water is required. All other engineer-
ing parameters are similar to those used in designing intake
structures for once-through cooled power plants.
Except for the more recent developments in intake design,
much of the present day technical information relating to evalu-
ation and design of intakes has been presented in four major
documents(2-5). These references should be consulted for
additional details and results. Because less cooling water is
required for closed-cycle cooling systems, there is a beneficial
reduction in impact on the aquatic environment. Basically, there
are three major types of biological impacts associated with pre-
sent day intake structures: entrainment, entrapment or impinge-
ment, and habitat modification.
Entrainment damage occurs when plankton are drawn into the
cooling system with the cooling water. Close to 100 percent of
these entrained organisms can be expected to be damaged or kill-
ed by mechanical impact from the pumps, biocides, and heat.
When entrained plankton includes the larval forms of fish clams,
lobster, and other aquatic organisms important to man, tfte re
suit may be fewer fish and shellfish available to the public.
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Organisms such as clams, crabs, and fish are too large to
pass through intake screens, but are either unable to swim away
from the intake or are actually attracted to it and become en-
traped in the intake structure where they may eventually be-
come impinged against the screens. This impingement is caused
by hydraulic forces in the intake stream at the screens. For
most aquatic life, impingement will be lethal due to starvation
and exhaustion when caught in the screen well, asphyxiation when
forced against a screen by velocity forces which prevent proper
gill movement, descaling by screen wash spray and asphyxiation
by removal from water for long periods of time.
Intake structures can change the nature of habitats when the
physical size and placement of these structures alter normal cir-
culation of water or bar migration of organisms. The result is
habitat modification, that is, the disruption of the normal cir-
culation of the water body through changed flow patterns or ero-
sion and deposition.
The most obvious methods to reduce losses caused by entrain-
ment, entrapment, and impingement are to locate the intake in an
area of low larval density, use specially developed intake screen-
ing systems which reduce attraction to fish, and regulate the
mode of operation of these screens. Presently, experimental
programs are being conducted at Oak Ridge National Laboratory
and at various utilities to quantitatively determine the mortali-
ty associated with each component of the cooling system(6).
11.2.2 Reduction of Impact Through Location
The extent of biological damage can often be reduced drasti-
cally by identifying and avoiding important spawning areas, juve-
nile nursery areas, fish migration paths, and shellfishing habi-
tats. The ability to avoid these areas will depend not only on
the nature of the organisms living in the water, but also on the
nature of the cooling water source. Assessing the effects of
intake location on aquatic life is controversial, as attested by
the numerous court litigations involving regulatory agencies,
utilities, and environmental groups.
11.2.2.1 Freshwater Intakes—
River intakes have generally been placed on the shoreline
upstream of the discharge. The unstratified nature of river
water usually results in this being a satisfactory solution.
However, when fish populations such as striped bass and salmon
use the shoreline as a migratory path, the shoreline intake can
act as a trap. In such cases, the intake may have to be placed
offshore and built with special screens to prevent entrainment
and impingement or operated in a controlled mode. An example
of a controlled mode may be as simple as continuous operation of
the screens or as complex as the combined operation of a once-
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through system with a helper tower which is periodically operat-
ed as a closed-cycle system during times when intakes can have
severe adverse xmpacts on biota.
11.2.2.2 Small Freshwater Lakes and Reservoirs-r-
Small lakes are frequently stratified with a layer of warm
highly oxygenated nutrient rich, water. While the use of the
cooler layer for cooling purposes by power plants presents a
significant engineering and economic advantage, a significant
depletion of this layer can have serious repercussions. Ex-
amples include depriving lake trout of a part of their habitat
and causing unwanted algae blooms when nutrient-rich water from
the lower water depths is discharged at the surface. Pumping
water from the surface may also be harmful because the surface
is the site of primary production and the basis of the food
chain. A suitable solution is to pump and discharge above the
deep layer but below the primary production or photic zone(7).
11.2.2.3 Estuaries— '
The design of environmentally sound intake structures for
estuaries is complicated by stratification, varying salinities
and tides, and the fact that estuaries are the primary production
areas for aquatic organisms.
EPA stated in the guidance document for Section 316 (b)
(PL 92-500) , that even though it is accepted that closed-cycle
cooling is not necessarily the best technology available for
power plant siting on estuaries despite the dramatic reduction
in rates of water use, closed-cycle cooling is beginning to be
employed in estuaries as the primary mode of cooling and often
as a helper system(5). An example of this use is the A. M.
Williams Station located in Berkely County, South Carolina, which
employs mechanical draft cooling towers during the hot summer
months as helpers to supplement the cooling capacity of the once-
through system and to reduce the discharge temperature of the
cooling water returning to the water body.
11.2.2.4 Oceans and Lakes—
In addition to the engineering problems caused by storm
waves and heavy sediments in the surf area, open ocean and laKe
intakes must be designed to avoid major migration routes and
spawning sites for fish and shellfish. Thermal stratification
in large lakes is not as stable or problematical as in f™^1
lakes. in some areas, the intake should be placed offs^re to
avoid productive nearshore habitats formed by aquatic plants ana
to avoid fish spawning grounds and nearshore concentrations o±
warm water fish(5) .
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11.2.3 Reduction of Impact Through Design
11.2.3.1 Velocity Consideration—
Velocity characteristics are the most important design con-
siderations for screening systems at intake structures. Intake
velocity can be measured at three locations: 1) in the screen
channel and upstream of the screen face, 2) through the screen-
face or approach to the screen and 3) at entrance restrictions,
such as under or over walls at the intake entrance. EPA recom-
mends that engineering and design based on velocity considera-
tions use the approach velocity measured through the screen face
(3) since this velocity causes the highest stress to biota.
Until recently, screens at intakes were designed solely
for debris removal with the major design criterion being main-
tenance of a low head loss across the screen. This has resulted
in screen approach velocities of 0.25 to 0.65 m/s (0.8 to 2.1
ft/s or higher.
Much of the reported research on fish swimming speeds in-
dicates that considerably lower approach velocities, on the order
of 0.16 m/s (0.5 ft/s) or less are needed, if the capability of
fish to swim away from an intake is required to avoid impingement
(3,4). EPA recommends an approach velocity of 0.16 m/s (0.5 ft/s)
or less as an intake velocity criterion to minimize entrainment
and impingement.
11.2.3.2 Selection of Screen Mesh Size—
Screen efficiencies (ratio of net open area of the screen to
total area) decrease rapidly as mesh size decreases. Thus, if
mesh velocity is a limiting criterion (instead of or in addition
to approach velocity), the total screen area must be enlarged
for smaller mesh sizes. When the screen area is not enlarged
after a decrease in mesh size to reduce entrainment of small
fish, the resultant increase in approach velocity may increase
the number of fish impinged.
The appropriate mesh size depends not only upon velocity
and other engineering considerations but on the type and size of
organisms needing protection. For protection of small fish
larvae, special screen types which have small openings should
be considered.
11-2.4 Conventional Intake System Designs
All cooling water intake systems employ a physical screen-
ing facility at some point before the condenser to remove debris
that could potentially clog the condenser tubes. The most com-
mon mechanically operated screen used in closed-cycle cooling
systems in U. S. power plant intakes is the vertically-rotating,
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single-entry, band-type screen mounted facing the waterway (Fig-
UJ.G _L j. • .L j • -7
The screen system consists of the screen (usually (3/16-in)
0.474-cm mesh size), the drive mechanism, and the spray clean-
ing system, which washes away the debris from the screen The
screen mesh is usually arranged in individual removable panels
referred to as "baskets" or "trays".
As presently used at most facilities, the conventional
vertical graveling screen has several features potentially damag-
ing to fish and other aquatic life. During normal operation and
when the water is relatively free of debris, the screens are
stationary. As debris collects on the screens, the increased
pressure drop across the screens initiates operation to clean
the screens. If the intake velocity is too high, fish can be
pinned against the screen when the screens are stationary. When
the screens are rotated, the fish are removed from the water and
then subjected to a high pressure water spray. Any fish exposed
to these hazards will be destroyed in the subsequent refuse dis-
posal operations.
Modifications to the design and operation of conventional,
vertical traveling screens can be made to minimize adverse en-
vironmental impacts. At the Surry Nuclear Station (8) (a once-
through system) for example, special fish buckets (commonly re-
ferred to as Surry buckets) , low pressure screen washing sys-
tems, and special fish sluice troughs to carry impinged fish
av?ay from the screens were installed (Figure 11.2). In addition,
the screens are run continuously. This scheme has proven to be
effective in significantly increasing the survival rate of those
species which become impinged.
11.2.4.1 Intake Arrangement —
The most common intake arrangement is the combination of
inlet, screen well and pump well in a single structure on the
shore of a river or lake. Water usually passes first through a
trash rack, then through a stop-log guide, and finally through
traveling screens. Occasionally, a skimmer wall is used to in-
sure that cooler lower strata waters will be drawn into the in-
take structure.
A variation of this common arrangement is to have the side
walls of the intake protrude into the waterway where they create
eddy currents on the downstream side of the intake. This ar
rangement is undesirable because fish sometimes . Centra te in
the eddy currents, thereby, increasing the possibility of their
eventual impingement.
Another variation of the shoreline intake is the approach
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channel intake in which water is diverted from the main stream
to flow through a canal at the end of which is the screening de-
vice. This arrangement is undesirable because the fish will
tend to congregate in the approach channels and thus, increase
the possibility of fish impingement.
11.2.4.2 Screen Placement—
Most conventional intakes are designed with the traveling
screens set back away from the face of the intake between con-
fining concrete walls (Figure 11.3a). This creates a zone of
possible fish entrapment between the screen face and the intake
entrance from which small fish may not be able to swim away.
An improvement to this design would be to mount the screens
flush with their supporting walls and place the trash racks out
into the waterway in such a manner that fish passageways are
provided in front of the screens (Figure 11.3b).
Where channel sections leading to the screens cannot be
avoided due to some unusual condition, proper design of the
screen supporting piers can reduce the fish entrapment potential
of the area. For example, a pier which protrudes into the flow
between two screens prevents fish from making the turns re-
quired to escape. Removing the protrusion of the pier (Figure
11.4) allows the fish to move to and rest in the stillwaters
near the face of the pier before swimming away. In addition,
screens can be oriented so that incoming water flow can guide
fish to bypasses.
11.2.4.3 Velocities Across the Screens—
Uniform velocities should be maintained across the screens.
When flow is not uniform across the screen, the potential for
fish impingement is increased. Velocities can become non-uni-
form when water approaches the screen structure at an angle.
Screen locations can also affect the flow distribution.
One basic consideration in the initial design of the intake
is the matching of the pumping head to the pressure drop through
the screens. In a two-pump system, for example, screen veloci-
ties substantially increase when only one pump is in operation.
Consequently, if plans are to operate for a considerable dura-
tion with only one pump, the screens should be designed for the
expected flow of one pump. Higher intake flow velocities may be
permissible during periods when little fish activity is expected.
During periods of high activity (spawning) or when the fish are
sluggish (cold winter temperatures), low flow velocities would
be maintained.
H-2.5 Alternate Intake Designs
11.2.5.1 Inclined Screens—
Inclined screens have been used in the northwestern United
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States for irrigation diversions and in Canada to divert down-
stream migrating fish. They also have some advantages in arSas
of heavy debris loading. One type of inclined screen has been
designed specifically with fish populations in mind (Figure 11 5)
?LS??Sai °ri!ntati?n Sf 5hS SCreen and itS cleaning mlchanism,
the fish can be slowly herded up the screen and kept immersed iA
water until they are dumped gently into tthe bypass trough.
The horizontal traveling screen has been designed specifi-
cally to protect fish. This screen rotates horizontally at a
sharp angle to the incoming water flow. The principle is to
guide fish to a point where a bypass channel can carry them to
safety. It has been very effective in protecting fish but has
been found to have considerable maintenance and operational
problems(3).
Other types of traveling screens used in power plants in
Europe, but not in the United States, include vertical axis re-
volving drum screens, horizontal axis revolving drum screens, and
rotating disc screens. None of these were designed with fish
protection in mind.
11.2.5.2* Filter Type Intake— "
Many types of filter intake, e.g., leaky (porous) dams or
infiltration galleries, have been developed on an experimental
basis, and some have been installed in applications for power
plants. The water is drawn through filter media, such as sand
or stone, rather than mechanical screens. Filter intakes can be
designed at low inlet velocities and thus, protect small fish and
even some plankton. Several intake structures in the Great Lakes
region utilize the "leaky dam" concept for mitigating environ-
mental impact (Lakeside Power Plant, Milwaukee, Wisconsin;
Bailly Generating Station, Porter County, Indiana). The "leaky
dam" consists of a rubble-wall and rocks. Voids between the
rocks allow sufficient passage of water through these large fil-
ters to meet plant water requirements.
Another variation of a filter type intake is the infiltra-
tion gallery. This has been used for many years for treatment
of water. Infiltration galleries are cavities constructed below
the water table or adjacent to a body of water which use the
natural water head and permeability of the soil or bank to pass
the quantity of water necessary. Soil permeability and heavy
debris loads can cause clogging problems which preclude use of
these designs for many waterways. However, for the relatively
smaller volumes of water required to operate cooling towers,
these systems show good potential applicability and use.
11.2.5.3 Fixed Screens— . . a^t-oni-ion for
Fixed screen intakes are receiving increased attention tor
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fish protection, even though the more common type of fixed
screens were not designed for fish protection. The bulk of these
screens are found on small, old plants. They include those which
are permanently anchored below the waterline of intakes and those
which can be moved but are not capable of continuous travel. The
first type of fixed screen is mounted upstream of the pumps in
vertical guides to allow them to be moved to a position above the
waterline. The second type involves a cylindrical screen attach-
ed to the pump suction well.
Fixed screen intakes have longer periods between cleaning
cycles then do traveling screen intakes; therefore, increased
impingement damage to fish is possible. The crude cleaning
methods currently used on fixed screens can also be damaging to
fish.
An example of fixed screens is that at Brayton Point Station,
Somerset, Massachusetts. At this fossil-fueled station, fixed
screens are set in place on the trash bars from May to November
to prevent the impingement of horseshoe crabs(9).
11.2.5.4 Perforated Pipe, Wedge Wire Screens—
Two significantly different types of fixed screens have re-
cently received increased attention for fish protection: the
perforated pipe and the Johnson well screen. These screens are
of particular interest for closed-cycle cooling systems, since
they appear to provide a very small adverse environmental im-
pact.
The original perforated pipe screen was designed for debris
exclusion. It is a pipe made of perforated material which is
placed in the waterway and oriented such that the passing cur-
rent will sweep debris downstream. Thus, the perforated pipe
is very effective in a river. The reliability of this perforat-
ed pipe system is very high(10).
Further development of the perforated pipe to prevent fish
impingement and entrainment has been completed for the recir-
culating, close-cycle cooling systems of Washington Public Power
Supply System's Nuclear Projects 1, 2, and 4(11). An intake pipe
for these plants (Figure 11.6) consists of a perforated outer
sleeve with 3/8-inch (.95 cm) holes over 40 percent of its area
inside of which is an inner sleeve with 3/4-inch (1.9 cm) holes
over 7 percent of its area. The outer sleeve prevents fish and
debris from entering the system. The inner sleeve distributes
the inflow evenly along the surface of the outer sleeve. The
average approach velocity of the intakes was experimentally de-
termined to be less than .12 m/s at 1.9 cm (0.4 ft/s at 3/4 in.)
from the outer sleeve surface.
A promising development for minimization of both impingement
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and entrainment in problem environments is the application of
Johnson wedge-wire well screens for power plant intakes. John-
son screens are cylinders composed of circular windings of
wedged-shape wires, oriented so the wider portion of the wire
faces outward (Figure 11.7). This orientation prevents clogginq
by providing only two-point contact for particles. The large
percentage of open space, despite small aperture widths, pro-
vides uniformly low approach and screen velocities. Cylinders
of wedge-wire screens can be made in a variety of sizes and
mounted behind bar racks in conventional intake wells or on pipes,
such as those of the perforated pipe designs (12). Fixed wedge-
wire screens of conventional flat design have proven to be re-
liable over a number of years in the paper and pulp industry
as well as the vegetable and food industry (13) .
11.2.5.5 Behavioral Screening Systems —
Behavioral screening systems (behavioral barriers) employ
one or more of several stimuli to cause fish to move away from
an intake structure. These systems rely on the swimming ability
of fish to avoid the artificial stimuli. One of the more popu-
lar innovations in intake design for power plants located on
large bodies of water, such as lakes and oceans, is the velocity
cap. This design is based on the observation that fish sense
and, subsequently, react to vertical flow fields much more slow-
ly than to horizontal flow fields. By inserting a cap over an
open pipeline, flow can be reoriented into a horizontal flow
field. Another advantage to this design is that entrance veloci-
ty can be controlled by setting the lid to the desired flow gap.
This type of design is being used by the Consumers Power Company
at its Palisades Nuclear Plant (closed-cycle cooling) and is
proposed to be used by the Seabrook Generating Station (New
Hampshire Public Service Company) (14) . (See Figure 11.8)
Most behavioral systems are ineffective in the presence of
stronger stimuli, such as currents, availability of food or
predators and, therefore, most other systems have not demonstrat-
ed a consistent, high-level performance. Some of these systems
are noted below.
Electric screens with electric fields to repel fish were
tested by the National Marine Fisheries Service. They were
found to be unreliable and dangerous to both fish and humans (3).
Air bubble screens, which basically consist of air PJPes
with equally spaced jets to provide continuous curtains of air
bubbles to repel fish, have been tried in two dif fer ent P™Jr
Plants. The system worked effectively at one plant, but not at
the other (3) .
Louver diverters have been used to form abrupt changes in
flow velocity and direction to form barriers through which
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risn wi±i not pass if an escape is provided. Individual louver
panels are placed at right angles to the direction of flow and
are followed by flow straighteners. The efficiency of this
system increased with fish size and decreased with increased
channel velocities. The louver system requires careful design
and model testing with each application because of the many
variables. In addition, complex and expensive fish handling
systems would still be necessary to return the fish to the water
source(3).
Other behavioral mechanisms, including sound and light
barriers and several types of fish attraction systems, have been
tried but produced only limited success. After the fish be-
came accustomed to the barrier or attraction system, its effec-
tiveness declined, so that the use of these systems has not
gained general acceptance by utilities.
11.2.5.6 Fish Handling and Bypass Facilities—
Fish handling and bypass equipment have been used in con-
junction with a conventional intake system to return impinged
fish back to the waterway. Most of these systems have been de-
veloped for irrigation and hydroelectric facilities in The West-
ern States. However, these may be applicable to utility use.
After being concentrated and removed from the screen well,
the fish must be safely returned to a hospitable environment.
The bypass system should be designed to minimize the time the
fish are out of the water and insure their rapid return to a
location far enough away from the intake to prevent re-impinge-
ment. Fish should not be returned via the discharge because
the heated, chlorinated chemically-treated cooling water would
be deleterious to the fish. Where conditions do not permit
hydraulic conveyance, fish can be trucked back to the waterway
as is routinely performed on the Snake River, Washington, to
prevent fish from passing through hydroelectric dams.
Fish can be moved from one water body to another with fish
pumps. The volute type of pump with screen or bladeless impel-
lers seems to cause the least amount of damage to fish. If fish
are to be moved in batches rather than continuously, special
buckets or elevators can be used.
A recently proposed fish ejector system is being installed
at Southern California Edison's San Onofre Nuclear Units 2 and
3(3). The system has been tested at the Redondo Generating Plant.
The fish ejector system removes fish from a moving stream of
water by attracting or directing fish away from the main flow in-
to a quiet zone where the fish are trapped and, subsequently,
removed to another discharge system for return downstream with-
out injury.
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11.2.6 Summary and Conclusions
Methods of reducing impact to fish populations from opera-
tion of intake structures and screens include designing and lo-
cating intake structures to help fish avoid or escape the struc-
ture itself, installing fish handling equipment to return im-
pinged fish unharmed to the water, and using special screens
whose design makes entrainment or impingement virtually impos-
sible. The determination of which of these methods is the best
available technology for a particular power plant will depend
on the type of environment and the kinds of aquatic life present.
Although no strict rules can be made as to what type of in-
take is best for a particular plant or environment, some trends
are evident. For plants on the open ocean or large lakes, sub-
merged velocity caps offshore have reduced impingement of fish
up to 95 percent in some cases. When entrainment or impingement
of shoreline migratory fish in rivers is a problem, the perforat-
ed pipe offshore in the river offers a possible solution. When
the entrainment of small larval fish or eggs is a potential pro-
blem, intake screens made of wedge-wire appear promising although
still untested. Where no serious impingement or entrainment
problems are predicted, conventional shoreline intakes and verti-
cal traveling screens carefully designed to minimize fish en-
trainment will probably be sufficient.
11.3 CONSUMPTIVE WATER USE OF ALTERNATE COOLING SYSTEMS
11.3.1 General Description
In the selection of a cooling system for steam-electric
power plants, three major areas require close attention: water
quality, water availability, and water quantity. The parameters
related to water quality and treatment are covered in Sections
7 through 10. Water availability, aside from its physical aspect,
is a licensing concern involving water allocations, water rights,
and permits. The consumptive water use of power plants is dis-
cussed in this section.
In once-through cooling the same amount of water taken from
a water source for condenser cooling is returned to that water
source, albeit at a higher temperature, usually, the amount of^
water taken from the water source is a small fraction o± tne a
vailable water; and after discharge and mixing, the net in-
crease in water temperature will be small. T^V^ fJ^nora-
perature will cause increased evaporation (called forced evapora
tion) from the natural water body. Because the change in tern
perature relative to the natural ambient temperature will be
small, the additional evaporation over the ^^
will also be small. In general, for once:thr°U^
vective heat transfer is a significant mode of heat
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For a closed-cycle cooling system using a pond, the amount
of water evaporated will, in general, be greater than that for
the once-through system. This is because the closed cooling pond
system operates at a higher temperature than a once-through sys-
tem. The net water consumption for a pond system must take into
account water losses due to seepage and water gains due to pre-
cipitation, as well as water lost by evaporation. Also of im-
portance is the natural evaporation of the pond system. If a
river or stream is impounded for use as a closed-cycle cooling
pond, natural evaporation from the pond must be added to the
consumptive water budget. However, if the pond or reservoir
serves another purpose in addition to power plant cooling, then
only the enhanced or forced evaporation need be charged to the
power station, while the natural evaporation could be propor-
tionally allocated to the other users. In general, for a closed-
cycle cooling system using a pond, heat transfer by evaporation
ranges from 40 to 80 percent of the total heat transfer(15).
For a closed-cycle cooling system using a wet cooling tower,
the amount of water evaporated is, in general, greater than the
forced evaporation for the pond system(16-19). A wet tower is
designed to obtain maximum direct contact of cooling water with
the flowing air to insure efficient cooling of water by the
evaporative process. Thus, evaporation is the primary mode of
heat rejection in a wet cooling tower.
In discussing consumptive water use by cooling systems, a
distinction should be made between the amount of water withdrawn
from the surface water resources for cooling purposes and the
amount of water "consumed" as a result of the cooling process.
Water consumption is defined as that portion of water removed
from and not returned to the surface water resources of a given
area as a consequence of the cooling system under consideration.
The water budget of a closed-cycle cooling system for a
steam-electric generating station can be expressed, in volume
per unit time, by the following equation (1):
V = R + P + M- (G + S + B + E + I) (11.1)
where:
V = consumptive water use.
R = local runoff inflow.
P = precipitation impingement onto the cooling water
surface.
M = make-up water.
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G = net groundwater movement (negative for inflow
to pond).
S = uncontrolled releases, e.g., pond seepage, over-
flow, etc.
B = blowdown.
E = total (natural, NE, plus forced, FE) evaporation.
I = miscellaneous inplant use.
Although several terms in Equation (11.1) are not applicable to
some cooling systems, the equation is general in its application
to common types of closed-cycle cooling systems.
The terms, R, P, G, S, and NE, are site dependent variables.
The terms, M and B, were discussed in Section 7. The term, I,
can be specifically identified for each plant. The rest of this
section will be concerned with the forced evaporation component,
FE, of E. Forced evaporation is that component of evaporation
specifically attributable to the operation of the power plant.
For cooling towers, all of the evaporation is forced; for a
pond, there is a natural component, NE, which exists whether the
power plant is operating or not.
11.3.2 Methods for Calculating Evaporative Losses
The water consumption for various cooling system alterna-
tives can be predicted with models simulating the behavior of
cooling towers, cooling ponds, and once-through cooling systems.
The evaporative loss part of the total consumption, especially
its forced evaporative component, is the term whose calculation
differs greatly from system to system.
11.3.2.1 Evaporative Loss From Cooling Towers—
An evaporative or wet cooling tower is a device which cools
hot water by heat exchange at the air-water interface. The pro-
cess primarily involves evaporation with a small portion of
sensible heat transfer. This particular type of cooling is wide-
ly used and its design is based on a well-defined technology.
Under most meteorological conditions, the exhaust air from
the cooling tower is saturated. The physical processes involved
in the operation of a wet cooling tower can be easily modeled to
give accurate predictions of the evaporation rate. The methods
of Hamilton (.20) or Leung and Moore (21) can be simply represented,
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For a cooling tower, the energy equation requires:
C L AT = G AH (11.2)
p a
where:
C = specific heat of water.
L = mass flow of water in the cooling system.
c
AT = water temperature range.
G = mass flow of dry air through the system.
AHa = change of the air enthalpy per unit mass of
dry air as the air passes through the tower.
The mass flow of water evaporated is given by:
E = G AW_ (11.3)
d
where:
AW = change in the specific humidity of the
a air as it passes through the tower, mass
of water per unit mass of dry air.
Substituting (11.2) into (11.3) obtains:
(:
- *. (11.4)
Based on a heat and mass balance method similar to that describ-
ed above, Hamilton(20) and Leung and Moore(21) have prepared
graphs which provide reasonably accurate estimates of the water
evaporation from wet cooling towers. The data from Reference 20
are given in Figure 11.9.
11.3.2.2 Evaporative Loss From Cooling Ponds (Forced Evapora-
tion)—
Heat dissipation from the pond surface is accomplished
through evaporation, convection, conduction, and radiation. It
is highly dependent upon local meteorological conditions (solar
radiation, dry bulb temperature, relative humidity or wet bulb
temperature or dew point, wind speed, and cloud cover).
Determination of the forced evaporative losses for a cool-
ing pond is a considerably more complex task than it is in the
case of a wet cooling tower. This is because quantitative esti-
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mates of evaporation for cooling ponds involve many parameters
which are difficult to. model. There are two basic methods for
estimating the forced evaporation from cooling ponds. One is
called the energy budget method and is based on the First Law
of Thermodynamics: it accounts for all incoming, outgoing and
stored energy at the pond surface layer and enables the calcula-
tion of the energy available for evaporation. The other is call-
ed the mass transfer method and is based on the Law of Conserva-
tion of Matter. A number of empirical models have been develop-
ed based on these methods. A recent literature review(18) iden-
tified one model, Harbeck(22), based on the energy budget method
and several based on the mass transfer method(23,24) .
1) Energy Budget Method—Harbeck Model
As applied to a water body, this method requires that the
net influx of energy be balanced by an increase of energy stored
in the water. The energy budget or balance for a pond may be
expressed in terms of energy rates as follows(22):
AB + AE + AH +
= C
(11.5)
where:
AB = increase in long wave thermal radiation
emitted by the body of water.
AE = increase in the amount of energy used for
evaporation.
AH = increase in the amount of energy convected
from the water surface to the atmosphere
as sensible heat.
AW = increase in the amount of sensible energy car-
ried away by the evaporated water.
C = the amount of energy added to the cooling lake
or pond by the power plant.
Equation (11.5) yields:
(11.6)
+ AH + AW
where:
AE/C =
percentage of heat added to the lake
or pond that is used in forced evapora
tion.
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The amount of heat added to the lake or pond, C, is known, and
if the amount of energy used in forced evaporation is known, the
actual volume of forced evaporation can be easily determined by
dividing by the latent heat of evaporation and density of water.
The Harbeck model(22) based on this method is represented
by a nomograph. The nomograph (Figure 11.10) give AE/C as a
function of water surface temperature with wind speed at the
two-meter height as a parameter. For wind speed measured at
other heights, adjustments to the two-meter height can be ob-
tained by the following formula:
u = uz (6.56/z)0'3 (11.7)
where:
u = wind speed at two meters, mph.
uz = recorded wind speed at height z, mph.
z = height of anemometer above ground at the
measuring site, feet.
Ordinarily, water surface temperature data are not readily
available, and Harbeck suggested that the air temperature above
the surface could be used as the water surface temperature in
utilizing the nomograph. The assumption that the air temperature
is approximately equal to the water surface temperature is usually
acceptable according to Harbeck (22). On an annual basis in areas
where ice cover does not occur, the average annual water surface
temperature is usually slightly lower than the average annual air
temperature because of the cooling effect of natural evaporation.
The addition of heat by a power plant may cause the water surface
temperature to more nearly equal the air temperature, unless the
plant load is large relative to the size of the lake(22). If
large air-water temperature differences exist, the procedure
using Harbeck's nomograph becomes questionable because of proba-
ble errors in the surface temperature dependent energy terms of
the energy budget equation.
2) Mass Transfer Method—Brady Model
This method is based on mass transfer theory (Law of Conser-
vation of Matter). Evaporation from a water surface is treated
as the turbulent transport of water in an overlying boundary
layer of water vapor. All the models using this theory are
quasi-empirical, and the equations take the following form:
E = CA f (U) (es - e-,) (11.8)
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where :
E = evaporation rate, million gallons per day
C = conversion factor, 106 gal-ft2/
Btu-acre.
A = pond surface area, acres.
f (u) = wind speed function (u is wind spped
in mph) , Btu/ft2 -day-nun Hg.
es = vapor pressure of saturated air at pond
water surface temperature, mm Hg.
ea = vaP°r Pressure in the ambient air,
mm Hg.
The wind speed function is assumed to be of the form:
(MGD)
f (u) = a + bu + cu2, (Btu/ft2-day-mm Hg) (11.9)
where:
a, b, and c are wind speed function coefficients
and are determined experimentally for the various
models used.
There are a number of empirical models available using this
method. The Brady model (23) based on this method has been par-
tially described in Section 4.2. In estimating the evaporation,
the average water surface temperature, Ts, is initially unknown
and is estimated, by trial and error, using Equations (4.21) to
(4.25) and
T = T + 5li (11.10)
s e K
where:
T = water surface temperature, °F.
S
T = equilibrium pond temperature, F.
Q • = rate of heat rejection per unit of
J lake surface area, Btu/ftz-day.
K = surface heat exchange coefficient,
Btu/ft2-day~°F.
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11.3.3 Evaporation Rates
Evaporation rates from closed-cycle cooling systems (ponds
and towers) have been estimated for all of the water resource
regions in the conterminous United States(16,17,25). A summary
and comparison of these results is given in Reference 18. The
comparison shows that: 1) estimates of evaporation rates from
cooling towers using different models are in general agreement,
and 2) estimates of evaporation rates from cooling ponds pre-
pared using the Harbeck model are about 30 percent to 50 percent
of those calculated using the Brady model.
When estimating consumptive water use for cooling ponds,
care should be exercised to select a model which best typifies
the actual site, cooling system, and thermal load characteristics
being analyzed.
11.3.4 Current and Projected Consumptive Water Use
Consumptive water use from energy related industries is in-
creasing at an exponential rate relative to the population. 'The
continued economic and industrial development of states having
limited water availability is creating a major environmental con-
cern in those areas of the country (18). As a result, restric-
tions in the allocations of water among consumptive users has or
will be implemented in many states.
Current and projected consumptive water use for the steam-
electric industry has been calculated and compared to that of
other major consumers as shown in Table 11.1(18). The informa-
tion provided in this table includes the consumptive water use
of the public supply, agricultural, industrial and mining, and
steam-electric components of the economy.
The consumptive water use for the steam-electric industry
is projected to grow from less than two percent of the total in
1975 to greater than seven percent in the year 2000. Thus,
although currently a small fraction of the total, consumptive
water use from the utility industry will become an important
consideration in the design and construction of power generating
facilities in the future.
11.4 IMPACTS OF SLOWDOWN
11.4.1 Introduction
The blowdown impacts of closed-cycle cooling systems are
primarily a problem of present day water chemistry and the treat-
ment required to minimize fouling, corrosion, and scaling as de-
scribed in Sections 7 through 10. Even though the volume of blow-
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down from a closed-cycle system is small when compared to the
discharge volume of a once-through cooling system, the attempt
to minimize blowdown by operation at high cycles of concentra-
tion (Section 7) can make the quality of the blowdown a potential
environmental/toxicological hazard. Hence, it is important to
insure that all the constituents of the blowdown are carefully
reviewed for their short term, as well as cumulative, impacts on
the environment and that the disposal of blowdown minimizes ad-
verse environmental impacts.
|
11.4.2 Impacts and Biological Control Factors of .Slowdown
The evaporation of large quantities of water in a closed-
cycle cooling system and the cycles of concentration employed
lead to the buildup of salts and other chemicals in the recir-
culating water system. There are three main problems associated
with the chemistry of the circulating water of these systems:
1) scaling of heat transfer surfaces, 2) corrosion which results
in shortened life of materials of construction, and 3) biological
fouling and growth which results in reduced heat transfer, ac-
celerated corrosion, and algal blooms. In order to minimize
these problems, the degree of concentration in a cooling system
is carefully controlled with various chemicals being added to
control these problems (Sections 7, 8, and 9 address these
problems and methods of treatment.) These chemicals affect the
pH, toxicity, dissolved solids level, and general water quality
of the blowdown stream.
Chemical evaluation of the blowdown waters must be routinely
carried out to determine that chemical discharges do not exceed
permissible standards. These standards for discharges to re-
ceiving bodies limit adverse impacts to the biota (lethal or
sublethal effects).
11.4.2.1 pH and Sulfate Levels —
Generally, the conditioning of make-up water involves the
adjustment of the alkalinity content of the water with sulfuric
acid. This procedure attempts to achieve a certain degree of
carbonate solubility in the circulating water to minimize exces-
sive scaling. The permissible range of pH values acceptable for
fish survival, however, depends upon factors, such as temperature
dissolved oxygen, and prior conditions in the receiving body of
water. J. E. McKee and H. W. Wolf reported that the pH values
of most inland U. S. waters containing fish ranges between 6.7
and 8.6(26). The Ohio River Valley Water Sanitation Commission
concluded that direct lethal effects of pH are not produced
within a range of about 6.5 and 8.2(26).
Depending upon the gulf ate concentration inth
water, cycles of concentration, and amount of sulfuric acid re
quired for scale control, the concentration of sulfate in tne
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blowdown can vary over a wide range. The pH adjustment of the
circulating water with sulfuric acid also increases concentration
of sulfates in the blowdown stream. The maximum acceptable con-
centration of sulfate in raw water used for drinking water sup-
plies is 250 mg/1 except where no other drinking water supplies
with a lower sulfate concentration are available.
It has been reported that waters with 500 mg/1 sulfate con-
tent will not be detrimental to domestic* water supplies or stock
watering, and 200 mg/1 will not be detrimental to irrigation. In
the United States, most waters that support good fish populations
contain 90 mg/1 or less, of sulfates (26). These factors must be
considered not only in the disposal of the blowdown of cooling
towers, spray ponds, and cooling lakes, but also when bodies of
water are utilized for multiple purposes, one of which is power
plant cooling.
11.4.2.2 Toxicity Level—
Companies which specialize in industrial water conditioning
usually perform the evaluations and determine the required chemi-
cal treatment for a particular system/water condition. Many
of these chemicals are proprietary compounds. Historically,
toxicity data for these compounds and their constituents have
been scant or not available.
Chemicals which prevent corrosion or inhibit scaling, when
present in the blowdown stream, can have an adverse impact on the
aquatic life of the receiving water body. Chromate salts, zinc
phosphates, and organic phosphonates have been used as effective
corrosion inhibitors. These chemicals have been shown to have
deleterious effects to biota in the discharge area. The passage
of the Toxic Substances Control Act of 1976 required detailed
description of the toxic potential of the chemicals expected in
the blowdown stream. Thus, it is expected that the use of chem-
icals for corrosion and scale inhibition in the future will most
likely have less toxic effects on the biota. Concentration limi-
tations have been placed by the Environmental Protection Agency
on specific corrosion and scale inhibiting compounds in water
effluents from existing and new electric power generating units
(effective in 1983). The prevention of biological fouling may
necessitate some degree of toxicity. Studies have shown that
chlorine is an effective biocide for the control of bacterial
slimes and algae at a level of 1.5 ppm free available chlorine
on a once or twice-a-day injection schedule. The continuous
application of chlorine is generally not necessary.
The period of treatment or use of these chemicals is defined
as the time required for destruction of oxidizable biological
matter within the system. This period is a variable dependent
on chlorine demand of the circulating water system, seasonal
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variations in temperature, and environmental factors, such as
spawning period for the various species of fish inhabiting the
receiving water body and stages of fish development.
Effluent limitations for new electric generating units re-
strict the amount of chlorine which can be discharged in the
blowdown, as well as the schedule of chlorine treatment (Section
9). Although the effluent limitations for steam-electric power
stations were remanded to EPA for review and reissuance, much of
the discussion here on effluent limitations is based on the 1974
effluent guidelines as many of these limitations are still ap-
plicable.
The maximum concentration of free available chlorine is
limited to 0.5 ppm with an average value not to exceed 0.2 ppm.
Also, neither free available chlorine nor total residual chlorine
may be discharged for more than two hours a day per unit unless
the utility can demonstrate that higher levels of chlorine or
more frequent treatment is absolutely necessary for operation.
11.4.2.3 Nutrient Levels—
Since there are no limitations or restrictions on the use
of corrosion inhibitors until 1983, the current discharge of
these materials may have an adverse impact on the phytoplankton
community of the receiving water body. Those inhibitors con-
taining nutrients, such as phosphates or nitrates, tend to stimu-
late algal growth in the region of the discharge. The degree to
which such a stimulus would affect the balance of the ecosystem
is dependent on many interrelated parameters, including existing
nutrient levels, fish population, and hydrological characteris-
tics tif the water body. The nutrient levels in the mixing zone
of the blowdown stream should be estimated as the basis for
assessing the potential impacts of increased algal growth.
11.4.2.4 Thermal Shock—
Thermal shock occurs when aquatic organisms are exposed to
a rapid and substantial change in water temperature. Most
aquatic species are unable to adjust rapidly to this temperature
change and, consequently, die. The degree of thermal shock is
dependent on the amount of heat added to the receiving water and
the area of influence.
Thermal shock is most severe in once-through cooling sys-
tems, especially when, for example, the discharge of heated
effluent is disrupted due to plant shutdown and causes sudden
changes in temperature near the point of discharge. Blowdown
from a closed-cycle cooling system is discharged from the cold
side of the cooling system; therefore, for a cooling tower the
effect of thermal shock is expected to be small. However, tor-
cooling pond or lake, the effect can be significant and must b
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determined with a biological evaluation.
11.5 ATMOSPHERIC AND TERRESTRIAL IMPACTS
11.5.1 Introduction
The atmospheric and terrestrial effects of closed-cycle
cooling generally take the following forms:
1. Impact Caused by Drift: A localized deposition of
water droplets which are transported out of the
evaporative cooling device. These droplets may con-
tain potentially harmful chemicals or pathogens, expe-
cially when agricultural runoff water, municipal/in-
dustrial discharge water or saltwater cooling is em-
ployed .
2. Fogging and Icing: Ground level phenonmena caused by
an elevation (above saturation level) in the water
vapor content of the ambient air. During cold weather
this condition can create hazardous conditions, such
as icing of roads and nearby structures.
3. Climatic Modifications: Increased precipitation and
cloud formation resulting from discharge to the atmos-
phere of large quantities of heat and water vapor from
closed-cycle cooling systems. Acid rainout and sul-
fate and nitrate deposition are additional environ-
mental concerns due to the possibilities of mixing of
cooling tower vapor plumes with stack gas plumes.
Since drift from cooling ponds, spray ponds, and reservoirs
is usually confined to the immediate vicinity of the waterbody,
the discussions on drift will be limited to drift from wet cool-
ing towers. In addition, the impact of fogging and icing from
ponds, spray ponds, and reservoirs are limited to the immediate
vicinity of or within a few hundred meters downwind of the
water body. These effects, if they occur, are usually associ-
ated with atmospheric conditions that favor the natural forma-
tion of these effects(27,28).
11-5.2 Factors Affecting Drift Deposition and Its Impact
During normal operation of cooling towers, droplets of cir-
culating water escape the tower and are carried upward in the
rising plume. Dissolved in these droplets are naturally occur- .
ing salts, as well as chemicals added to control the growth of
organisms which tend to foul heat transfer surfaces and to inhib-
it the corrosion of equipment. As the plume disperses, these
droplets begin to evaporate to an equilibrium size. During the
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transformation from droplet to saturated salt particle, the fall
velocity of the drop changes significantly. Eventually these
particles are deposited on the ground at specific downwind dis-
tances, which are directly related to the unique trajectory of
each individual particle.
In order to predict the deposition and, hence, the impact of
the drift, the following parameters must be established in ad-
dition to the ambient background:
1. Water quality of the drift
2. Total drift emission rate from the cooling device
3. Particle size and mass distribution of the drift
at the tower exit
4. Meteorological conditions (wind speed and direction
frequency analysis)
5. Tower operating characteristics (see Section 4)
11.5.2.1 Salt Deposition Impacts—
The expected salt concentrations in the ambient air and
deposition in the vicinity of the power plant as a result of
cooling tower operation have been predicted analytically using
various computer models (29-32). Field measurements are, at pre-
sent, sparse. The presently available drift models are routine-
ly updated, reviewed, and compared to be better able to predict
and correlate plant operations with the limited field measure-
ments available.
Studies, such as the Chalk Point experimental cooling tower
project(33), critical reviews of models conducted by the Ameri-
can Society of Mechanical Engineers(34), and on-going evalua-
tions by Chen and Hanna(35) and Policastro(36) have added great-
ly to the understanding and further refinement of these pre-
dictive models.
Because of evaporation in the tower, total dissolved solids
(TDS) concentration in the circulating water can be many times
that of the make-up water. Hence, the low TDS quality of the
make-up water is of prime importance. For example, using ocean
water for make-up, the circulating water TDS concentration could
be as high as 70,000 ppm. Deposition of drift with salinity in
this range would be damaging to most types of vegetation having
commercial importance.
Measurements of natural (background) salt deposition has
been recorded in the literature (37-39). These studies indicate
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that the geographic location, atmospheric conditions, and dis-
tance from the ocean are factors which affect salt deposition.
Values ranging from 280 kg/km^-mo. (2.6 Ib/acre-mo.) to 3500
kg/km2-mo. (31.0 Ib/acre-mo.) have been given as reasonable
deposition values (37 , 38) .
The effect that salt deposition may have on the biota will
depend on the degree of deposition, the incidence and severity
of foliar damage, the species affected, and the stages of their
development. The primary adverse effects cited in the litera-
ture are those of foliar necrosis and premature loss of the
affected foliage(37). However, these are effects that resulted
after acute levels of exposure.
The native vegetation in a coastal environment has adapted
to withstand high ambient salt levels. Even though this type
of vegetation is more salt tolerant, it also has its limits.
It has been estimated that the minimum long-term average back-
ground airborne salt concentration needed to affect natural
vegetation distribution in Eastern coastal areas is approximate-
ly 10 Mg/m3-mo. (37) . Salt background levels from the shoreline
have been measured from 9 Mg/m3 to 100 Mg/m3 . For a tower
utilizing ocean waters, it has been reported that a conservative
limit for no vegetation damage could be set at 60 jug/m (38) .
In an area where the cooling tower would utilize brackish
water for make-up, such as agricultural runoff or estuary water,
the growing vegetation in that area may not be as resistant to
high salt deposition as seashore vegetation, and adverse effects,
such as low crop yield and leaf necrosis, could occur. There
are, at present, in the United States several steam-electric
power plants which utilize cooling towers with brackish or salt
waters. Four of these stations are: B. L. England, Atlantic
City Electric Company; Jack Watson, Mississippi Power Company;
P. H. Robinson, Houston Lighting and Power Company; and Chalk
Point, Potomac Electric Power Company.
Damage to vegetation due to salt deposition from a natural
draft cooling tower is currently being evaluated by EPRI , EPA,
DOE (ERDA) , and the State of Maryland at the Chalk Point Facili-
ty of the Potomac Electric Power Company. The tentative con-
clusions of this study indicate that the environmental effects
due to cooling tower salt deposition appear to be limited to the
area encompassed by the plant boundaries; hence, salt deposition
from natural draft towers is minor impact to the biological com-
munity as a whole.
A recent concern, related to drift associated with the use
of highly polluted waters for condenser cooling, is the potential
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that drift from a cooling tower using polluted waters would trans-
fer pathogens and toxins over the area where the drift UcarrSd
and deposited. Studies supported by EPA and the Nuclear Regula-
tory Commission (NRC) are assessing potential effects of patho-
g!nS«nd toxi]}S fr°m drift when cooling tower make-up consists
of effluents from municipal sewage treatment plants.
When using highly contaminated waters for condenser cooling
the bacteriological quality of the, water must be known. If
the concentrations of bacteria and/or viruses exceed that estab-
lished for water intended for use by humans or animals, treat-
ment measures for effective bacterial and viral inactivation
through disinfection should be carefully considered, although
there are no present standards or treatment requirements for
usage of these waters for cooling purposes(40,41).
11.5.2.2 Drift Emission Rate Measurement—
Several methods are available to measure drift emission
rates. When measuring ambient background rates, most of these
methods rely on coated surfaces, such as liquid plastic, magne-
sium oxide, gelatin, petroleum jelly, and oil coatings on glass
or sensitive papers, which retain the impression of the impact-
ing water particle. When used within a cooling tower, these
methods disturb the flow of air; consequently, methods have been
developed which measure particle size without disturbing the air
flow. In one of these methods, high intensity light is scattered
while passing through the drift. A second technique uses a set
of fixed components to collect a continuous isokinetic drift
sample(43,44). High volume samplers and deposition pans are ad-
ditional methods which collect the drift either on a filter or
in pans on the ground after the drift has settled.
11.5.2.3 Particle Size and Mass Distribution—
Coated slides are an excellent device for determining parti-
cle size, whereas coated slides and sensitive papers are used
in determining particle size and mass distribution. Sensitive
papers are preferable for particles larger than 100 microns as
reported in Central Electric Generating Board (CEGB) Technical
Disclosure Bulletin No. 182(44).
Figures 11.11 and 11.12 show cumulative mass distributions
of drift droplets for natural and mechanical draft cooling towers
as measured at the tower outlet and as reported by various inves-
tigators (43) . These figures indicate that there are significant
variations in these measured values. For instance, for the stand-
ard input data used by Chen for natural-draft cooling towers, 9b
percent of the total mass was made up of particles 50 microns and
larger in diameter. However, the Keystone data indicate that 98
percent of the total mass consisted of particles 100 microns and
larger.
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Figure 11.13 shows the nominal settling rate of water drop-
lets in air(44). The determination of deposition must account
for the variations of a number of parameters: plume rise,
initial salt concentration, ambient relative humidity, wind speed,
and drop size, each of which has a significant effect on the tra-
jectory of a given particle. In addition, deposition rate is
directly proportional to the drift rate, which is dependent pri-
marily on tower design.
11.5.2.4 Effects of Meteorological Conditions--
Once the drift droplets leave the tower, they are carried
aloft by the rising plume. The ambient wind tends to bend the
rising plume until it begins to travel horizontally. Since each
drift droplet has a distinct fall velocity, the droplets begin
to separate from the plume as soon as they leave the tower. The
droplets are carried downwind by the wind and eventually fall to
the ground. The largest droplets (diameters greater than 100
microns) have the greatest fall velocity and reach the ground
after traveling 200-300 meters downwind. In contrast, the small-
est droplets (diameters less than 20 microns) remain in the plume
indefinitely and are carried far downwind (see Figure 11.13).
It has been reported that at high wind speeds (greater than
10 m/s), the plume will be bent over quickly and may be caught
in the aerodynamic cavity region or wake downwind of the tower.
If the plume is caught in the "wake" region of the tower, greatly
increased ground level concentrations of the salt particles in
the vicinity of the towers can occur. This condition is known
as downwash. Since downwashed plumes have strong buoyant forces,
these plumes will "lift off" at about 200-500 meters from the
tower. Ground impact due to downwash conditions are most common
for mechanical draft cooling towers due to their low heights.
Hanna has estimated that at the Oak Ridge mechanical draft cool-
ing towers this condition occurs approximately 50 percent of
the time(45).
11.5.3 Control of Drift
The drift generated by a cooling tower must be controlled
since its effects, as previously described, can be a nuisance,
damage on-site vegetation, be a potential health hazard, and
enhance the corrosion of metal structures. Methods for control
of drift are primarily engineering controls, physical controls,
and type of tower design. The first two methods will be dis-
cussed below, since tower design was covered in Section 4.
11.5.3.1 Engineering Controls—
The tried and proven engineering control for cooling tower
drift has been the drift eliminator and is installed in most of
the facilities in the United States (see Section 4). Manufac-
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turers of cooling towers give written guarantees on the maximum
percentage of the circulating water that will leave the tower
as drift. (Drift eliminators are generally curved blades spaced
from 1 to 2 inches apart which cause the air flow to change direc-
tion rapidly. When this occurs, water droplets in the air stream
impinge upon the blades and collect to form larger droplets.
These larger droplets have sufficient fall velocities to prevent
re-entrainment by the rising plume.)
All manufacturers have standard guarantees for drift rate.
Most cooling tower manufacturers have indicated that, in general,
for both mechanical draft and natural draft towers the guaranteed
drift emission rate is 0.002 percent of the circulating water
volume. Measurements of actual drift from such towers have shown
that the drift rate may be much less, on the order of 20 to 40
percent of the written guarantee.
11.5.3.2 Physical Controls—
Towers that use salt and brackish water should be located
downwind of immediate areas of sensitive vegetation or structures.
Excessive cooling tower drift may collect on switchyard insula-
tors, and under extreme conditions (persistent high winds di-
rected toward the switchyard) the salt buildup on the insulators
could cause a flashover. Thus, if possible, this equipment
should be located so that the plume passes over the switchyard
a minimum amount of time. Roffman et al.(37) have found that at
distances greater than 0.5 km (0.3 miles), the effects of salt
deposition are insignificant.
In certain instances if efforts to limit unacceptable cool-
ing tower drift cannot be reduced by location, the use of towers
which maximize the dispersion of the drift are in order. Natur-
al draft towers, which are generally between 300 and 500 feet
in height, disperse drift more effectively than the lower profile
mechanical draft towers. Round mechanical towers and fan-assist-
ed towers have an intermediate drift dispersion capability to
that of natural and mechanical draft towers.
11.5.4 Impacts of Fogging and Icing
11.5.4.1 Fogging and Icing—
The plume which exits the cooling tower, spray pond, or
reservoir is warmer than the ambient air and saturated with water
vapor. As it mixes with the ambient air, the plume is diluted,
cooled, and a portion of the water vapor is condensed in to mi-
nute droplets. These droplets scatter light, causing the plume
to become visible, and give the plume the appearance of a hori-
zontally moving cloud.
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The international definition of fog and the one used by the
United States National Weather Service (NWS) established fog as
a condition consisting of a visible aggregate of minute water
droplets or ice crystals suspended in the atmosphere near the
earth's surface which reduces visibility to less than one kilo-
meter. If the horizontal visibility is more than one kilometer,
the condition is mist; if visibility is less than 0.4 km, the con-
dition is classified as dense fog.
A main concern with visible plumes is that under certain
meteorological conditions the plume can spread to ground level
and cause localized fogging. If ambient temperatures are below
freezing, icing conditions can occur. These concerns are more
important in climates where cold, damp winters are experienced.
Fogging can become a hazard, if the plume impacts visibility or
enhances ice formation on roads and bridges.
11.5.4.2 Engineering Controls—
The distance from the cooling device where fogging and icing
effects can occur is proportional to the above ground elevation
where the plume is generated. Plumes from cooling ponds, spray
ponds, and low-profile cooling towers stay close to the area
of plume generation and cause fogging and icing conditions with-
in or near the power plant property line. As in the case of
drift, the natural draft cooling tower provides sufficient sepa-
ration between the plume and the ground to reduce or avoid
ground fogging.
G. E. MeVehil{46) compared a 76.2-m (250-ft) fan-assisted
hyperbolic tower to two natural draft towers with heights of
106.7 m (350 ft) and 152.5 m (500 ft). The results show that
the distance of maximum fog frequency for the fan-assisted tower
is less by factors of 1.25 and 1.67 than the 106.7-m (350-ft)
natural draft tower and the 152.5-m (500-ft) natural draft tower,
respectively, in addition, this investigation pointed out that
the fog from mechanical draft towers can be expected to occur
on 100 to 150 days per year, whereas for the fan-assisted natural
draft tower fog episodes can be expected to occur on 5 to 20
days per year(46). These estimates are shown in Table 11.2.
Measurements made at the American Electric Power Corporation's
John E. Amos Plant, Charleston, West Virginia; Muskingum River
Plant, Beverly, Ohio; Big Sandy Plant, Louisa, Kentucky; and
Mitchell Plant, Moundsville, West Virginia indicated that at
these plants, all of which operate natural draft towers, no
ground level fog was ever observed, even with winds as strong
as 18 m/s (59 ft/sec)(47).
11.5.4.3 Physical Controls—
In some cases, the topography of a site can increase the po-
tential for cooling tower fog formation.* For example, in a steep
river valley the tops of the ridges may be several hundred feet
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The
above the valley floor where the cooling towers are located.
plume from any cooling tower or pond cooling system might not
rise above these ridges and could cause localize fogging. Hence
careful siting and site-specific meteorological data"are prere-
quisites for reducing or preventing fogging and icing conditions.
11.5.5 Effects on Weather Modification
The effects of closed-cycle cooling on modifications of
weather conditions are a potential problem that is currently
under study by various federal agencies. These potential modi-
fications include increases (attributed to multi-unit installa-
tions) of precipitation and cloud cover due to the atmospheric
discharge of heat and water vapor. In this regard, there have
been reported instances of increased rain and snowfall related
to natural draft cooling tower evaporation that have been measur-
ed at distances in excess of 40 km (25 mi) (48) from the tower.
These concerns, even through long recognized, are just beginning
to receive attention.
Dry cooling towers for electric power plants are now being
considered for large power plants. Climatic modifications, such
as cloud cover, localized wind, and local heating, have been at-
tributed to dry cooling towers. A study performed by Boyack and
Kearney(49) pointed out that a slight increase in cloud coverage
is possible, a redirection and speed alteration of local wind
toward a covergence zone created by the heat from the towers can
be expected, and the buoyant volume will raise the local ambient
air temperature. However, since at present very few power plants
utilize dry cooling towers, their environmental impact is still
subject to speculation.
11.5.6 Cooling Tower and Stack Plume Interaction
The interaction of a cooling tower plume with the stack gas
effluents of an oil- or coal-fired steam-electric power generat-
ing facility can lead to the formation of toxic substances, such
as sulfuric acid, sulfates, nitric acid, nitrates, etc. Acid
drops with pH values between 2 and 3 have been reported in the
visible plume (but not on the ground) from a natural draft cool
ing tower(50).
The composition of stack gases varies with the type of fuel
used as well as the environmental/engineering measures taKen -co
control these gaseous discharges. Hence, stack gas compositions
will vary from plant to plant. The oxidation rate of SO,, a
prerequisite in acid formation, in an interactive plume has been
evaluated by various investigators(51,52) and can range from 0
to 6 percent/hr. Heavy metals which are commonly found in fossil
fuels, such as Pb, Mo, and Fe, can act as efficient catalysts in
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promoting high sulfate reaction rates. In addition, they may
act synergistically to cause environmental damage. Currently,
no regulatory standards for pH values have been set for atmospher-
ic dischargeso
The existing models for predicting reaction rates and acid
deposition from cooling tower plumes are based on laboratory
analyses. Well-designed field studies and empirical correlations
are needed to properly estimate the magnitude of the problem of
stack gas and cooling tower plume impact.
i
11.6 LAND USE, AESTHETICS, AND NOISE IMPACTS
11.6.1 Land Use - Introduction
The land requirements for the various closed-cycle cooling
systems previously described in this manual have been calculated
by various researchers. Table 11.3 presents estimates of land
requirements on a unit power basis for these closed-cycle cool-
ing systems(53-57) .
Generally, of all presently available closed-cycle cooling
systems, cooling ponds require the most land, and mechanical
draft wet cooling towers require the least. However, the ra-
tionale for selection of one closed-cycle cooling system over
another involves many other factors: availability of land,
water availability, local climatology, socioeconomic factors,
and local, state, and national laws and regulations.
The impacts that these structures may have on the land are
those related to construction which disrupts, and in most cases,
permanently alters the immediate habitat. Species which are
rare or endangered are displaced and may be destroyed by this
construction. Impacts due to operation of the various cooling
systems were discussed previously in Subsections 11.2 through
11.5.
Detailed site selection programs, pre-construction surveys,
and environmental control and monitoring programs during con-
struction are methods which will provide remedial courses of
action with consequent reduction of the impact caused by con-
struction. These programs are necessarily site-specific and
tailored for each locale.
The land that these cooling systems occupy is, for the im-
mediate future, last to the biota that occupied that portion of
land, but the obvious benefits gained are related to providing
electrical energy for society.
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11.6.1.1 Environmental Land Impacts of Cooling Ponds-
Prior to the current environmental awareness, cooling ponds
have been used for a number of years for condenser cooling by
Western and Midwestern utilities. Their use was due primarily
to a need to guarantee a steady supply of water in areas where
the seasonal water supply fluctuated widely. Thus, cooling ponds
became an. attractive, cost-effective method to assure the neces-
sary volumes of water for condenser cooling.
Presently, well over half of the cooling ponds in the United
States are located in the Southwest (Texas and Oklahoma) , a
quarter in the Southeast, and the remainder mainly in the Midwest.
The overall advantages of cooling ponds depend on the climatic
conditions, topography, availability of land, and capital costs.
The specific land use advantages of cooling ponds are as follows:
1) operation for extended periods of time without make-up, 2)
suitability as settling basins for suspended solids, and 3) uti-
lization for multi-purpose use, such as recreation, flood con-
trol, and an available source of water for other uses.
The primary disadvantage of cooling ponds is the amount of
land required. The land used for a cooling pond is basically
land that will be taken out of production. In addition, it may
serve as an attraction to migratory birds. Since the waters in a
cooling pond are maintained artifically warm, the migratory birds
may stop in their migration either temporarily or over winter.
If no food is available in the vicinity of the ponds, the birds
could cause crop damage to nearby farms; hence, economic loss
and liability could occur. To remedy this possible situation, ad-
jacent land may have to be planted with grain or other feed
brought in. Consequently, additional land may be required to
supplement the cooling pond.
11.6.1.2 Environmental Land Impacts of Spray Ponds —
The factors involved in determining the amount of land
necessary for a spray pond relate only to the desired perfor-
mance of the spray pond; in other words, the heat load to be
rejected by the spray pond will be the controlling factor in
determining the size of the spray pond. Generally, an increase
in the cooling range causes the performance of the spray pond to
decrease.
The environmental impacts that spray ponds may have are _
intermediate between cooling ponds and towers, depending on tneir
size and number of spray sets used. Although experience with
spray ponds is limited, formation of dense fog and hard rime ice
on vertical surfaces near spray ponds has been reported. Spray
Ponds have more serious drift problems than mechanical drart wet
cooling towers because greater water deposition can occur on ad-
jacent land and structures (58) .
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Herman(59) and Ryan(60) recommend that in order to minimize
drift the distance between any spray nozzle and the edge of the
pond be not less than 7.63 m (25 ft). In areas where strong
winds are prevelent, the distance should be no less than 10.67 m
(35 ft).
11.6.1.3 Environmental Land Impacts of Cooling Towers—
Investigators have quantitatively estimated the land re-
quirements for cooling towers. Woodson(53) studied the relative
land area required for both wet and dry cooling towers for an
800-MW fossil-fueled plant. The results of the study are in-
dicated in Table 11.4.
Boyack and Kearney(61) conducted an investigation of land
requirements for mechanical and natural draft dry cooling towers
for 1000-MW capacity plants (nuclear- and fossil-fueled). Their
estimated areas are in Table 11.5.
These tables indicate that dry cooling towers require from
2.5 to 4.2 times more land than that needed for wet cooling tow-
ers. In addition, these land requirements do not account for
the additional space required for the necessary air flow around
the towers and areas required for other tower-related equipment.
The land that is occupied by wet or dry cooling towers is,
in most if not all cases, within the property lines of the utili-
ty. Even though the quantities of land required are sometimes
impressive by themselves, they are quite insignificant compared
with the total property required for operating a fossil or nu-
clear power plant.
11.6.2 Aesthetic Impacts
In evaluating the visual impacts of closed cooling systems,
those of cooling lakes and ponds are generally the least, while
those of natural draft cooling towers are the most objectionable.
This is due to the fact that ponds and lakes closely resemble
familiar natural bodies of water, while towers may rise to 400
or 500 feet in elevation and be the dominant feature in the
immediate landscape. Various techniques have been developed in
assessing visual changes due to man-made intrusions to the land-
scape. Some of these techniques are discussed below.
Aesthetics measurement or visual impact has often been de-
scribed as an unquantifiable measure, even though it is a parame-
ter that affects all individuals. Each individual has a very
definite opinion concerning visual impact, and there are often as
many opinions as there are individuals. In less subjective
terms, aesthetic impact has been defined as "the change in visual
quality over time resulting from the introduction of a facility
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into a landscape setting as viewed from the surrounding area"l62).
Various methods have been used to assess aesthetic impacts of
closed-cycle cooling systems. Jones et al. (63) provide a simple
formula for evaluating the effect of a particular landscape
measured at a specific viewpoint.
VQ =1/3 (I + V + U) (11.11)
where :
VQ = visual quality.
I = intactness (or wholeness of a screen) .
V = vividness (or memorability of a screen) .
U = unity (degree of coherence and harmany
of individual elements).
Equation (11.11) is formulated so that VQ has no limiting value.
Overall visual quality and its individual components are scored
on a normalized scale ranging from 1 (very high quality) to 100
(very low quality) . The standards to be used in scoring have
been carefully defined (63). ' I, V, and U are scaled factors
which must be carefully defined prior to assigning a numerical
value. As the values of I, V, and U increase, the visual quality
deteriorates.
In order to determine the change in visual impact of the
landscape which results from a proposed construction modifica-
tion, the following equation has been formulated (63) :
_ a (11>12)
VQb
where :
R = ratio of change in visual quality.
VQa » visual quality after plant construction.
VQb = visual quality before plant construction.
The ratio, R, can be either positive, zero, ° .
depending on whether certain attractive or unattractive features
of the landscape are highlighted, unaffected, or obscured by the
proposed change. If correspondingly there is no change, R will
equal zero. The visual impact at a specific viewpoint may be
expressed as:
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Visual Impact = R x P (11.13)
where:
p = population viewer contacts per year at a
given viewpoint.
The total aesthetic impact on a landscape is, thus,_the
summation of the calculated composite impacts at the various
viewpoints. Inputs for these composite impacts are obtained by
analyzing slides which present the existing site from various
views and an artist's rendition of the proposed structure super-
imposed on the site to give an "after" view. A panel of experts
is convened to develop specific values for the formula variables
presented in Equations (11.12) and (11.13).
The basic questions relating to the aesthetic impact of a
closed-cycle cooling system consider site-specific factors, such
as:
1. Opinions of the people living near or at the
viewpoints of the cooling system who will be
constantly exposed to the visual impact
2. The economic impact on real estate values in
the various visually impacted neighborhoods
and on future neighborhood development
Usually, those closed-cycle cooling systems that are closer
to the ground, such as cooling lakes and ponds, provide the least
detrimental aesthetic impact when compared to those systems that
generate very large plumes and are many hundreds of feet above
ground elevation (see Section 11.4). This is true even when
these systems are viewed from surrounding high ground and may be
clue to an established familiarity with natural lakes and ponds
or the fact that tall structures, such as cooling towers, require
time before becoming faimilar items in the landscape. Although
it may be generally said that multi-purpose use ponds cause lit-
tle or no detrimental visual impact, site-specific analysis of
this impact is always required.
11.6.3 Noise Impacts
The Noise Control Act of 1972 sets as its goal the attain-
ment of an enviroment for all Americans free from noise that
jeoparizes their health and welfare. In attempting to comply
with this Act, the United States Department of Housing and Urban
Development has established noise criteria for sound levels which
occur at least 8 hr/day. These criteria define a "clearly un-
acceptable" area as one where the sound level exceeds 75 dBA.
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A firATfidr00^1316"-^83 corresP°nds to sound between 45
and 65 dBA(64) These criteria, however, do not take into con-
sideration background noise levels.
On the other hand, the Environmental Protection Agency has
developed information which recommends a permissible average
24-hour outdoor noise level of 55 dBA, LDN or an equivalent of
49 dBA. (LDN represents the sound energy averaged over a 24-
hour period with a 10 dB nighttime weighting)(65) .
11.6.3.1^ Noise Impact Measurement—
It is impossible to account for all factors of significance
in attempting to predict the reactions and opinions of people to
noise. For instance, the degree of acceptance of a power plant
by its neighbors is based on their experienced unrelated to noise
and can affect their reactions to noise. It is estimated that
about 25 percent of the population is hardly affected by high
noise levels while another 10 percent is extremely susceptible
to even very small noise levels(66). Background noise and the
degree to which the community has been acclimated to it are im-
portant parameters that must be considered. Background noise
constitutes a measure of adaptability and serves to identify
any significant deviation from the norm.
Cooling tower noise can be a major source of power plant
noise. This noise is generated by a number of conditions, such
as:
1. The falling water within the tower
2. The movement of air through the tower
3. The operation of the fans that mechanically
create draft, bearing noises, and magnetic hum
from drive motors or switchgear
Cooling tower noise levels have been measured at a number
of operating facilities which use mechanical draft towers (cross-
flow) and natural draft towers (crossflow and counterflow) (67).
Although the water flow capacity may vary by as much as a factor
of four (140,000-600,000 gpm to 529,000-2,268,000 gpm), these
measurements indicated that the sound level remains practically
unchanged.
The average noise level at the top of a forced draft cooling
tower is near 85 dBA. This noise level is not an on-site problem,
However, in order to meet the EPA recommendation of bb CIBA, .UDN
or an equivalent of 49 dBA, tower location is a critical item
at some sites.
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It has been estimated that at a distance of 500 feet (152.4 m)
a natural draft cooling tower will generate a noise level of 61
dBA. This noise level remains approximately the same at 1000 feet
(304.8 m) and does not drop to 50 dBA until a distance of 3500
feet (1066.8 m) from the tower is reached(68).
11.6.3.2 Control Measures
Measures for controlling the noise generated by falling
water in cooling towers include splash decks or plates just a-
bove the water surface to create a gliding effect of the water
prior to entering the basin. If the spaces between the cooling
tower fill are very narrow, these create a higher noise level
because of the comparatively higher air movement velocity. The
reduction of this effect and that of the falling water require
trade offs which need further study.
Noise generated by fans and motors and their bearings and
connecting shafts can be maintained at low levels with good
maintenance and lubrication. Magnetic hum generated by the motors
used to drive the cooling tower fans are a very minor component
of the overall cooling tower noise and can generally be ignored
(69).
Various measures of noise control are used by tower manu-
facturers, such as two-speed motors with low speed operation
at night and high speed during daytime, derating the tower with
a slow speed fan, air flow silencers or attenuators, barrier
walls or earthen dams(70). These measures are expensive for any
type of tower, and a more suitable location, if available, would
be preferable to control the noise level.
In general, forced draft cooling towers encounter greater
disfavor with regard to noise than do natural draft towers.
Noises from air movement over fan blades and through tower and
exhaust stacks is the controlling factor for the higher noise
levels. In selecting a cooling tower system, other factors,
such as visible plume and aesthetics, may be more important than
noise.
11.7 LICENSING AND PERMITS
11.7.1 Introduction
Power plants using closed-cycle cooling systems require a
number of permits prior to start-up and operation. The process
of acquiring these permits is called licensing. These cooling
system related permits fall into three general categories: 1)
permits required for the use and consumption of water, 2) per-
mits required for the various discharges, and 3) permits requir-
ed due to a potential impact on navigation. Federal, state, and
308
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local authorities require permits which must be acquired so as
to assure compliance with the law. These required permits play
an important part in the ultimate selection of the type of cool-
ing system for a particular plant application.
11.7.2 Consumptive Water Use Permits
Paramount to the use of a closed-cycle cooling system is the
acquisition of permits for the utilization and consumption of
water. Federal statutes have been enabted which affect and, in
a few cases, control the development of water resources in the
United States. In addition, numerous interstate compacts have
been enacted by the states and approved by Congress which appor-
tion waters of interstate streams. These statutes, compacts,
and treaties must be considered in successfully obtaining water
for consumptive cooling purposes. However, it is important to
note that there is no uniform body of laws which regulates con-
sumptive water use in the United States.
Rules and regulations on water use vary from state to state.
Customarily, water use permits are either issued by the state or
are purchased or leased by the user when waters are not available
for allocation.
Before withdrawing water for use by a power plant, a water
usage permit must be secured. The licensing procedure requires
that the applicant must indicate volume of water, time frame,
and intended use of the withdrawn waters, as well as volume, rate,
and quality of the water to be discharged. The pertinent river
basin commission, state water engineer, state environmental
quality board, Army Corps of Engineers or Bureau of Reclamation
may issue this permit depending on jurisdictional authority over
the water body intended for use.
In addition, the following state and local bodies or their
equivalent should be consulted in the appropriate state to de-
termine whether additional permits and licenses are required:
1. State Environmental Quality Board
2. State Air Control Commission
3. State Highway Department
4. State Board of Health
5. State Public Utilities Commission
These agencies may require that an environmental impact study
be prepared stating the effects that this withdrawal may have on
309
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the specific region of the waterbody where the use takes place
or on the water basin as a whole.
11.7=3 Discharge and Navigational Permits
When waste heat and certain other byproducts are discharged
into the environment, they are classified as pollutants. Fed-
eral, state, and local statutes which have been legislated to
protect the quality of our environment define these pollutants.
The mechanisms used for implementing these statutes are regula-
tory licenses and/or permits.
11,7.3.1 Federal Requirements—
Various federal regulatory agencies have developed criteria
that provide guidance in the preparation of the required docu-
ments and reports needed to evaluate the potential impacts of a
proposed power plant and its cooling system. These guideline
criteria are dynamic tools and change from time to time as more
precise knowledge on the subject becomes available.
The Federal Water Pollution Control Act amendments of 1972
(the Act) established as a national goal the elimination of
discharges of pollutants into navigable waters by 1985. In
order to achieve this goal, the Act further requires that by'
1983, all discharges will use the best available control techno-
logies.
One pollutant, as defined by Congress in the Act, was heat.
It was recognized, however, that a basic technological approach
to water quality control could not be applied in the same man-
ner to the discharge of heat as to other pollutants. Thus,
Congress included within the Act in Section 316 (a) a basis for
modifications of the standards as they pertain to thermal dis-
charges from point sources. Section 316 (a) allows the dis-
charge of heat to water bodies, if it can be demonstrated that
the environmental impact of the thermal discharge will be minimal.
Pursuant to the Act, EPA, in 1974, established regulations
for the discharge of heat from steam-electric generating plants.
Under these regulations, subject, however, to the variance allow-
ed under 316 (a), all existing generating plants of 500 MWe or
more with once-through cooling systems which began commercial
operation on or after January 1, 1970 must backfit to closed-
cycle cooling systems by July 1, 1981. All generating plants
that began or will begin operation on or after January 1, 1974
were likewise subject to the backfit requirements. Finally, all
new plants were made subject to the thermal limitation without
exception.
As of October, 1978, there are no thermal regulations
310
-------
wntten specifically for the steam-electric industry, because the
^lat*~ Promjlg^ed by EPA in 1974 were remanded'to EPA In
1976. However, the federal regulations required by the National
Environmental Policy Act (NEPA) do stipulate the use of best
available control technology. One' available control technology
for the steam-electric industry is closed-cycle cooling.
Table 11.6 is a partial list of Federal Government documents
to guide owners and operators of electric generating stations to
prepare information needed to assess the'impacts of closed-cycle
cooling systems.
Federal agencies requiring permits that must be acquired as
they relate to construction and operation of closed-cycle cooling
systems of nuclear- or fossil-fired power plants are:
1) U. S. Army Corps of Engineers
In the construction of an intake or discharge structure,
a dredging and construction permit is required for work in a
navigable river and for work on (or potentially affecting) levees
(Section 10 of the Rivers and Harbors Act of 1899) . A permit for
the discharge of dredged excavation material is also required
(Public Law 92-500, Section 404). The applicant must provide
information, drawings, and sketches which will indicate1 the man-
ner in which these activities will be conducted, as well as the
potential environmental and navigational impacts that these
structures may have. Subsections 11.2, 11.3, and 11.4 of this
manual provide information that can be used in reducing these
impacts.
2) U. S. Coast Guard
The Coast Guard requires lighting fixtures on waterfront
structures, particularly if they extend into a navigable water-
way. The Coast Guard also regulates and controls all toxic and/
or hazardous spills. Generally, the required information to be
provided consists of drawings and descriptions that indicate
that the intake and discharge structures will not interfere or
create hazardous conditions in the body of water.
3) Environmental Protection Agency - NPDES Discharge Permit
The Federal Water Pollution Control Act amendments of 1972
created that National Pollutant Discharge Elimination System
(NPDES) under which the regional administrator of the EPA_may
issue permits for the discharge of any pollutant into navigable
waters. The required information must indicate quantity ana
type of chemical effluent to be released to the receiving body
of water. The EPA effluent regulations limit the maximum con
311
-------
centrations of many chemicals discharged by power plants. Sec-
tions 7 through 10 of this manual review these constituents and
provide information on controlling these effluents. Several of
the states have been granted authority to issue NPDES permits
(see Subsection 11.7.3.2).
4) U. S. Department of the Interior
When a fossil-fueled power plant is to be built on or crosses
Department of the Interior land, the issuance of a permit, grant,
license, contract or right-of-way is required. The Department
of the Interior has guidelines for generating stations that must
be followed. These guidelines require the preparation of a
comprehensive environmental report in which the cooling system
is one of the many systems to be reviewed. The information
necessary for describing the potential impacts of the cooling
system include atmospheric and aquatic thermal plume analyses,
chemical constituents to be discharged into the receiving body
of water, their effects on the ecosystem, population and noise
impacts, etc. Section 11 of this manual addresses these con-
cerns.
5) Federal Aviation Administration
Approval from this agency is required for construction of
structures extending into the air, such as meteorological towers,
stacks, or cooling towers. The required information, such as
descriptions and drawings, must indicate the location and manner
of lighting of these structures as well as their potential im-
pact on air traffic and air space.
6) U. S. Nuclear Regulatory Commission
A construction permit from this agency authorizes the con-
struction of a nuclear plant plus its cooling system in accor-
dance with plans submitted by a utility in its application for
the permit. The application includes an environmental report,
a preliminary safety analysis report and necessary information
for an anti-trust review.
The subsequent operating permit authorizes a utility to load
fuel and begin power operations. The submittal of a final safety
analysis report, an operating stage environmental report and pro-
posed environmental technical specifications, is required as
part of the application for this permit.
Both the construction and operating permit requirements
must address those parameters that can cause an environmental
impact due to the closed-cycle cooling system selected. At-
mospheric, aquatic, terrestrial, aesthetic, and social impacts
312
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must be reviewed and their impacts assessed prior to the is-
suance of these permits.
... Many of the permits identified in this subsection can be
filed utilizing information collected for other permits? How-
ever, all permits must be obtained before operation of the plant
can be initiated. Although many agencies have signed memoranda
of understanding, it is incumbent upon the applicant to obtain
all permits and insure that the requirements of all agencies are
satisfied. ;
11.7.3.2 State and Local Permits—
Several states have been granted the authority to issue
NPDES permits. Table 11.7 is a listing of those states that
have NPDES granting authority as of the end of 1977. Others
may have specific office requirements and guideline documents
which must be followed. However, as a minimum the same informa-
tion that would have been provided at the federal level is re-
quired by the state issuing this permit.
11.8 BENEFIT-COST ANALYSIS
11.8.1 Introduction
A benefit-cost analysis must be provided when applying for
construction and operating permits for steam-electric generating
stations. In performing this analysis, the economic costs and
environmental impacts of closed-cycle cooling systems must be
included. In general, the capital and operating costs of the
cooling system are those discussed in Section 3 and provided in
Subsection 4.5 of this manual. Some of the environmental factors
that must be considered when comparing alternate cooling systems
are also quantifiable. For example, capital and operating cost
requirements of mitigative measures, such as the operation of a
fish hatchery or construction of an upstream dam for flow augmen-
tation, can be readily included in the benefit-cost analysis.
On other environmental factors it is more difficult to place a
monetary benefit or detriment value (e.g., number of hours of
increased ground fogging). Consequently, these factors are
often described on a qualitative basis. This is not to say that
a cost-benefit analysis cannot be performed, but rather that this
analysis will involve expert technical judgment, as well as nara
data on resources affected.
Guides have been published by various regulatory govern-
mental agencies which provide assistance in the area of environ-
mental cost-benefit analysis(71-73). These guides should be con
suited when preparing the closed-cycle cooling system se^i?ns
of the benefit-cost analyses. For convenience, all of tte items
relating to power plant cooling systems as published in the
313
-------
Nuclear Regulatory Commission Guide for preparing a benefit-cost
analysis have been extracted from U. S. NRC Regulatory Guide 4.2
and assembled as Table 11.8(71). It is included here since it
provides one of the most complete assessments available. It
indicates those environmental parameters which can be quantified
on a dollar basis and those impacts that must be assessed on some
other numerical basis.
11.8.2 Benefit-Cost Analysis Methods
The classical method of benefit-cost analysis quantifies
perceived costs and benefits for comparison purposes in common
units of dollars(74). However, many environmental factors (e.g.,
noise increase and aesthetics which are not easily converted to
dollar values) have, in the past, received scant consideration,
while those factors which are easily converted to dollars (e.g.,
the capital cost of mechanical draft towers vs. natural draft
towers) generally received a major consideration.
A number of models, programs, and methods which attempt to
place a value, rating scale or numerical grade on the various
environmental parameters have been developed and applied to the
alternate cooling systems. The majority of these evaluations
are based on a decision analysis concept(75). Q. B. DuBois et
al. in a paper entitled "Systematic Development and Application
of A Comprehensive Power Plant Site Selection Methodology"
propose the use of a "figure of merit" for a site-cooling water
system combination(76). This figure of merit is made up of rank-
ing factors by "expert" groups. Others have proposed to assign
a ranking scale to various environmental impacts and mathematical-
ly manipulate these values to a "best" or "least" impact. Com-
puterized programs, such as the Department of the Interior's
"Power"(77), attempt to find the least cost/impact power trans-
mission route between two given points by making use of a
similar ranking of relevant environmental site parameters and
impacts.
Another technique used to arrive at a cost-benefit analysis
which encompasses environmental parameters is the Delphi De-
cision technique(78,79). This technique is made up of two dis-
tinct phases. In phase 1, a group of "experts" (project team
members, representatives from private groups, utility members,
regulators) list the environmental issues of concern in a de-
scending order of relative importance, and importance ratios or
percentage values are assigned. This is done independently by
each member of the group of experts. In phase 2, the individual
results are analyzed by a non-participating moderator, normal-
ized to a percentage scale, and returned to the group for review.
This process is repeated until a consensus is reached.
314
-------
H. T. Odum et al.(80) have attempted to convert environ-
mental field data into energy flow equivalent values or energy
units by using the "Lotka Maximum Power Principle"(81) , which
deals with the useful work accomplished from energy flowing
in a system and not just the heat equivalent, value of that
energy.
However, these elegant but complex calculations have not
received a great deal of acceptance by the engineering/biologi-
cal community dealing with environmental cost-benefit analysis
of cooling systems.
Others(82) have attempted to utilize dollar values for
impacts on fish by employing the "values per reported catch"
for commercial fishermen and other factors, such as time spent
fishing, stock of fish per acre and distance traveled to fish-
ing area, to reflect a dollar value for impact on recreational
fisherman. These factors, although valid per se, are strictly
short-term impact values and fail to consider the potential
long-term impact on the overall environment.
The majority of the methodologies presently employed for
the evaluation of environmental cost-benefit analysis considers
objective, as well as subjective utilization concurrence by a
group. These methods have proven to be of value. For these
environmental cost-benefit methodologies to represent the actual
facts, a broad data base, efficient information processes, a
multi-disciplinary approach, and public opinion poll and survey
information must be considered.
315
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TABLE 11.1. PROJECTED CONSUMPTIVE WATER USE, MGD(22)
Year
Category 1975 1985 2000
Public Supply 8,485 9,594 10,978
Agriculture 99,149 107,281 107,467
Industry & Mining 8,130 11,395 17,760
Steam-Electric 1,440 4,110 10,598
Total Consumption 117,204 132,380 146,803
316
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TABLE 11.2. ESTIMATED FOG FREQUENCIES FOR NATURAL DRAFT
AND HYBRID COOLING TOWERS(47)
Type of Tower
Hybrid
(Powered Hy-
perbolic)
Natural Draft
Natural Draft
Size
Height
76.2m
(250 ft)
106.7m
(350 ft)
152.5m
(500 ft)
Diameter
54.8m
(180 ft)
54.8m
(180 ft)
67.1m
(220 ft)
Fog Frequency
(Hours/Year)
25 - 100
15 - 75
5-40
Distance of
Max. Freq.
(km)
12
15
20
317
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TABLE 11.3. APPROXIMATE LAND REQUIRED BY VARIOUS COOLING
SYSTEMS
Cooling Method Acre/MWe m2/MWe
Cooling Pond(55) 1.00 - 3.00 (4.05 - 12.15) x 103
Jet Spray Pond(54,57) 0.05 - 0.30 (0.202 - 1.215) x 103
Natural Draft, Wet (4.58 - 5.06)
Tower(53,56) x 10~3 18.55 - 20.50
Mechanical Draft, Wet
Tower(53) 2.86 x 10~3 11.58
Natural Draft, Dry
Tower(53) 21.20 x 10~3 85.80
Mechanical Draft, Dry
Tower(53) 6.98 x lO"3 28.30
318
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TABLE 11.4. RELATIVE AREA REQUIREMENTS FOR ALTERNATE COOLING
TOWER SYSTEMS (800-MWe FOSSIL POWER PLANT(53)
Cooling Tower System
Wet Tower Dry Tower
Natural Draft
Mechanical Draft
1.64 hectare
(4.05 acre)
0.90 hectare
(2.22 acre)
6.87 hectare
(16.9 acre)
2.26 hectare
(5.58 acre)
319
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TABLE 11.5. LAND REQUIREMENTS FOR DRY COOLING TOWERS FOR
REPRESENTATIVE 1000-MWe POWER PLANTS(61)
Fossil Nuclear
Cooling Tower LWR+ HTGR*
Natural Draft 1.90 hectare 4.50 hectare 2.51 hectare
(4.7 acres) (11.1 acres) (6.2 acres)
Mechanical Draft 2.75 hectare 4.13 hectare 3.08 hectare
(6.8 acres) (10.2 acres) (7.6 acres)
+LWR - Light water reactor
*HTGR - High temperature gas-cooled reactor
320
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TABLE 11.6.
GUIDANCE LIST OF DOCUMENTS AVAILABLE FROM THE FEDERAL GOVERNMENT FOR
FILING PERMITS RELATED TO CLOSED-CYCLE COOLING SYSTEMS
ro
Name of Laws, Statutes, Guidance
Document s, etc.
U.S. laws, statutes, etc., 1972.
Federal Water Pollution Control
Act Amendments of 1972.
U.S. Environmental Protection
Agency. 1974. Thermal dis-
charges: 316(a) regulations.
Federal Register 39 (196):36176-
36184.
U.S.'Environmental Protection
Agency. 1975. EPA/NRC
316 (a) technical guidance manual
and guide for thermal effects
sections of nuclear power plant
environmental impact statements:
a first step towards standard-
izing biological data require-
ments for the EPA/NRC memoran-
dum of understanding.
U.S. Environmental Protection
Agency. 1976. Best technology
available for the location, de-
Brief Description
The objective of this law (P.L.
92-500) is to restore and main-
tain the chemical, physical, and
biological integrity of the Na-
tion's waters.
Section 316 (a) regulations re-
quire that the thermal effluent
"assure the protection and pro-
pagation of a balanced, indigen-
ous population of shellfish, fish
and wildlife in and on that body
of water into which the discharge
is to be made."
This manual describes the infor-
mation which should be developed
in connection with making tech-
nical determinations under Section
316(a) of the Federal Water Pol-
lution Control Act Amendments
of 1972. ~~
Section 316 (b) final regulations
which require location, design,
construction, and capacity of
(continued)
-------
u>
N)
TABLE 11.6 (continued)
Name of Laws, Statutes, Guidance
Documents, etc.
sign, construction, and capacity
of cooling water intake struct-
ures for minimizing adverse en-
vironmental impact. Federal
Register 41 (31):17387-17390.
U.S. Environmental Protection
Agency. 1976. Guidance for de-
termining best technology avail-
able for the location, design,
construction, and capacity of
cooling water intake structures
for minimizing environmental im-
pact, Section 316(b), P.L. 92-
500
U.S. Environmental Protection
Agency. 1974. Steam electric
power generating point source
category: effluent guidelines
and standards. Federal Register
39(196):36186-36207.
U.S. Environmental Protection
Agency. 1976. Steam electric
power generation point source
category: effluent guidelines
and standards (Cooling lakes
amendment). Federal Register
41(60):12694-12696.
U.S. Environmental Protection
Brief Description
cooling water intake structures
reflect the best technology a-
vailable for minimizing adverse
environmental impacts.
This guidance manual describes
the information and techniques
needed to evaluate cooling wa-
ter intake structures and allow
for determination of the best
technology available for mini-
mizing adverse environmental im-
pact.
Regulations establish final
effluent limitations and guide-
lines for existing sources and
standards of performance and
pretreatment standards for new
sources in the steam electric
power generating category.
Proposed regulations would
permit the use of a "recirculat-
ing cooling water body" (cooling
lake or pond) for certain speci-
fied sources.
This document presents the find-
Continued)
-------
tsJ
UJ
TABLE 11
Name of Laws, Statutes, Guidance
Documents, etc.
Agency. 1974. Development
document for effluent limita-
tions guidelines and new source
performance standards for the
steam electric power generating
point source category.
(EPA 440/1-74/029-a)
U.S. Environmental Protection
Agency. 1976. Development
document for best technology
available for the location, de-
sign, construction, and capacity
of cooling water intake struct-
ures for minimizing adverse en-
vironmental impact.
(EPA 440/1-76/015-a)
U.S. Nuclear Regulatory Commis-
sion. 1976. Regulatory Guide
4.2: Preparation of environ-
mental reports for nuclear power
stations.
(continued)
Brief Description
U.S. Atomic Energy Commission.
ings of an extensive study of the
steam electric power generating
point source category for the pur-
pose of developing effluent lim-
itations, guidelines, and standards
for the industry in compliance
with and to implement Sections
304, 306, and 307 of the Federal
Water Pollution Control Act
Amendments of 1972.
This document presents the find-
ings of an extensive study of the
available technology for the lo-
cation, design, construction, and
capacity of cooling water intake
.structures for minimizing adverse
environmental impact in compliance
with and to implement Section
316(b) of the Federal Water Pol-
lution Control Act Amendments of
1972.
This document identifies the in-
formation needed by the Nuclear
Regulatory Commission in its
assessment of the potential en-
vironmental effects of"the pro-
posed nuclear facility and es-
tablishes a format acceptable to
the NRC for its presentation.
This guide discusses the major
(continued)
-------
OJ
fO
TABLE 11.6 (continued)
Name of Laws, Statutes, Guidance
Documents, etc.
Brief Description
1975. Regulatory Guide 4.7:
General site suitability cri-
teria for nuclear power sta-
tions.
U.S. Nuclear Regulatory Commis-
sion. 1975. Regulatory Guide
4.8: Environmental technical
specifications for nuclear power
plants.
U.S. Department of the Interior.
Guidelines for the Preparation
of Environmental Reports for
Fossil-Fueled Steam Electric
Generating Stations, November
1976.
U.S. Department of the Army.
Regulation No. 1105-2-507,
"Planning, Preparation and Coor-
dination of Environmental State-
ments", February 1973.
site characteristics related to
public health and safety and en-
vironmental issues which the
NRC staff considers in determin-
ing the suitability of sites for
light-water-colled (LWR) and
high temperature gas-cooled (HTGR)
nuclear power stations
This regulatory guide provides
guidance to applicants on the
preparation of proposed environ-
mental technical specifications
and includes an identification
of their principal content and
a standard format.
This document identifies the in-
formation required by the Depart-
ment of Interior in its assess-
ment of the potential environ-
mental effects of a proposed
fossil-fueled facity when the
Department of Interior is designat-
ed as the lead Federal Agency.
This document identifies information
needed by the U.S. Army Corps of
Engineers when a portion of a steam-
electric power generating facility
infringes on a navigable waterway
so that environmental/safety impacts
can be assessed and permits issued
(continued)
-------
TABLE 11.6
Name of Laws, Statutes, Guidance
Document, e_tc_.
U.S. Coast Guard, "Procedures
for Considering Environmental
Impacts." Commandant Instruction
5922.10B, 1975.
U.S. Department of Transporta-
tion, Federal Aviation Adminis-
tration, AC 70-7460-LA, "Ob-
struction Marking and Lighting",
January 1972.
U.S. Fish and Wildlife Service.
1975. Review of fish and wild-
life aspects of proposals in or
affecting navigable waters:
Adoption of guidelines. Federal
Register 49 (231):55810-55824.
U.S. Nuclear Regulatory Commis-
sion. 1976. Regulatory Guide
4.11: Terrestrial environ-
mental studies for nuclear power
stations.
(continued)
Brief Description
or denied.
This document identifies those
parameters that may create an
environmental/safety impact when
a portion of a steam-electric
power generating facility in-
fringes on a navigable waterway.
This document identifies those
parameters that may create an
environmental/safety impact when
a portion of a steam-electric
power generating facility in-
fringes on airspace.
The final guidelines describe the
objectives, policies and pro-
cedures to be followed in the re-
view of proposals for works and
activities in or affecting
navigable waters that are sanc-
tioned, permitted, assisted or
conducted by the Federal govern-
ment.
This regulatory guide provides
technical information for the
design and execution of terrest-
rial environmental studies for
nuclear power stations.
-------
TABLE 11.7.
STATES THAT HAVE NPDES GRANTING AUTHORITY (AS OF
31 DECEMBER 1977)
State
California
Colorado
Connecticut
Delaware
Georgia
Hawaii
Indiana
Kansas
Administrative
Agency
California Water Resources
Control Broad
1416 North Street
Sacramento, CA 95814
Department of Health
4210 East llth Avenue
Denver, CO 80220
Dept. of Environmental
Protection
State Office Building
Harford, CT 06115
Dept. of Natural Resources
and Environmental Con-
trol
Tatnall Building
Dover, DE 19901
Georgia Dept. of Natural
Resources
Environmental Protection
Division
47 Trinity Avenue SW
Atlanta, GA 30334
Department of Health
Environmental Health Division
P. 0. Box 3378
Honolulu, HI 96801
Stream Pollution Control
Board
1330 West Michigan Street
Indianapolis, IN 46206
Kansas State Dept. of
Health
Division of Environmental
Health
535 Kansas Avenue
Topeka, KS 66603
(continued)
326
-------
State
Maryland
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
TABLE 11.7 (continued)
Administrative
:_ Agency
Maryland Dept. of Natural
Resources
Water Resources Adminis-
tration
State Office Building
Annapolis, MD 21401
Dept. of Natural Resources
Water Resources Commission
Stevens T. Mason
Building
Lansing, MI 48926
Minnesota Pollution Control
Agency
1935 W. County Road B2
Roseville, MN 55113
Mississippi Air and Water
Pollution Control Com-
mission
416 North State Street
Jackson, MS 39205
Clean Water Commission
1014 Madison Street
P. 0. Box 154
Jefferson City, MO 65101
Dept. of Health and Environ-
mental Sciences
Cogswell Building
Helena, MT 59601
Nebraska Dept. of Environ-
mental Control
P. 0. Box 94653
State House Station
Lincoln, NE 68509
Dept. of Human Resources
Bureau of Environmental
Health
Capital Complex
1209 Johnson Street
Carson City, NV 89701
(continued)
327
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TABLE 11.7
State
New York
North Carolina
North Dakota
Ohio
Oregon
South Carolina
Vermont
Virginia
Virgin Islands
n nTAmninistrative
Agency
Dept. of Environmental
Conservation
50 Wolf Road
Albany, NY 12233
Department of Natural and
Ecologic Resources
P. 0. Box 27687
Raleigh, NC 27611
Dept. of Health
State Capital
Bismark, ND 58501
Ohio Environmental Pro-
tection Agency^
450 E. Town Street
Columbus, OH 43216
Dept. of; Environmental
Quality
Water Quality Control
Division
1400 SW Fifth Avenue
Portland, OR 97201
Dept. of Health and Environ-
mental Control
2600 Bull Street
Columbia, SC 29201
Environmental Conservation
Agency
Montpelier, VT 05602
State Water Control Board
P. 0. Box 11143
Richmond, VA 23230
Dept. of Conservation
and Cultural Affairs
P. 0. Box 278
Charlotte Amalie
St. Thomas, VI 00801
(continued)
328
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TABLE 11.7 (continued)
Administrative
State Agency
Washington Dept. of Ecology
Olympia, WA 98501
Wisconsin Environmental Protection
Division
Dept. of Natural Resources
Madison, WI 53701
Wyoming Dept. of Environmental
Quality
State Office Building
Cheyenne, WY 82001
329
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TABLE 11.8*. ENVIRONMENTAL FACTORS TO BE USED IN COMPARING ALTERNATIVE PLANT SYSTEMS 171)
Unit of Method of
Description Measure3 Computation
Primary Impact
Population or
Resources Affected
oo
U)
o
1. Natural surface water
body
1.1 Impingement or
entrapment by
cooling water intake
structure
(Specify natural water
body affected)
1,1.1 Fishb
Juveniles and adults are sub-
ject to attrition.
1.2 Passage through or
retention in cooling
systems
1.2.1 Phytoplankton
and zooplankton
Plankton population (ex-
cluding fish) may be changed
due, to mechanical, thermal,
and chemical effects.
Percent of har-
vestable or adult
population de-
stroyed per year
for each import-
ant species.
Percent changes
in production
rates and species
diversity.
Identify all important species as de-
fined in Section 22. Estimate the
annual weight and number of each
species that will be destroyed.
(For juveniles destroyed, only the
expected population that would
have survived naturally need be con-
sidered.) Compare with the esti-
mated weight and number of the
species population in the water
body.
Field studies arc required to esti-
mate (1) the diversity and produc-
tion rates of readily recognizable
groups (e.g., diatoms, green algae,
zooplankton) and (2) the mortality
of organisms passing through the
condenser and pumps. Include in-
direct effects0 which affect
mortality.
j*Applicant may substitute an alternative unit of measure where convenient. Such a measure should be related quantitatively to the unit of measure shown in this table
"Fish" as used in this table includes shellfish and other aquatic invertebrates harvested by man.
Indirect effects could include increased disease incidence, increased predation, interference with spawning, changed metabolic rates, hatching of fish out of phase with food
organisms.
*From U.S. NRG Regulatory Guide 4.2, Revision 2 "Preparation of Environmental Reports for Nuclear
Power Stations", July 1976 (Table 4). Where references to sections appear, these refer to sections
in the Guide.
(continued)
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TABLE 11.8* (continued)
Primary Impact
Population or
Resources Affected
Description
Unit of
Measure3
Method of
Computation
1.2.2 Fish
1.3 Discharge area and
thermal plume
1.3.1
Water quality,
excess heat
U)
OJ
1.3.2
1.3.3
Water quality,
oxygen avail-
ability
Fish
(nonmigratory)
All life stages (eggs, larvae,
etc.) that reach the condenser
are subject to attrition.
Percent of har-
vestable or adult
population de-
stroyed per year
for each impor-
tant species.
Acres and acre-
feet
The rate of dissipation of the
excess heat, primarily to the
atmosphere, will depend on
both the method of discharge
and the state of the receiving
water (i.e., ambient tempera-
ture and water currents).
Dissolved oxygen concentration Acre-feet.
of receiving waters may be
modified as a consequence of
changes in the water temperature,
the translocation of water of
different quality, and aeration.
Fishb may be affected directly
or indirectly because of
adverse conditions in the
plume.
(continued)
Net effect in
pounds per year
(as harvestable
or adult fish by
species of
interest).
Identify all important species as de-
fined in Section 2.2. Estimate the
annual weight and number of each
species that will be destroyed. (For
larvae, eggs, and juveniles destroyed,
only the expected population that
. would have survived naturally need
be considered.) Compare with the
estimated weight and number of
the species population in the water
body.
Estimate the average heat in Btu's
per hour dissipated to the receiving
water at full power. Estimate the
water volume and surface areas
within differential temperature
isotherms of 2, 3, and 5°F under
conditions that would tend, with
respect to annual variations, to
maximize the extent of the areas
and volumes.
Estimate volumes of affected waters
with concentrations below 5,3,
and 1 ppm under conditions that
would tend to maximize the impact.
Field measurements are required to
establish the average number and
weight
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TABLE 11.8* (continued)
Primary Impact
Population or
Resources Affected
Description
Unit of
Measurea
Method of
Computation
1.3.4 Fish (migratory)
1.3.5 Wildlife (in-
cluding birds
and aquatic and
amphibious
mammals and
reptiles).
Suitable habitats (wetland or
water surface) may be
affected.
A thermal barrier may inhibit
migration, both hampering
spawning and diminishing
the survival of returning
fish.
Acres of defined
habitat or nest-
ing area.
Pounds per year
(as adult or
harves table fish
by species of
interest).
U)
CO
to
1.4 Chemical effluents
1.4.1 Water quality,
chemical
Water quality may be impaired. Acre-feet, %.
(continued)
Determine the areas impaired as
habitats because of thermal dis-
charges, including effects on food
resources. Document estimates of
affected population by species.
Estimate the fraction of the stock
that is prevented from reaching
spawning grounds because of plant
operation. Prorate this directly
to a reduction in current and
long-term fishing effort supported
by that stock. Justify estimate on
basis of local migration patterns,
experience at other sites, and
applicable State standards.
The volume of water required to
dilute the average daily discharge
of each chemical to meet applicable
water quality standards should be
calculated. Where suitable standards
do not exist, use the volume
required to dilute each chemical to
a concentration equivalent to a
selected lethal concentration for the
most important species (as defined
in Section 2.2) in the receiving
waters. The ratio of this volume to
the annual minimum value of the
daily net flow, where applicable, of
the receiving waters should be ex-
pressed as a percentage, and the
largest such percentage reported.
Include the total solids if this is a
limiting factor. Include in this
calculation the blowdown from
cooling towers.
-------
TABLE 11.8* (continued)
Primary impact
Population or
Resources Affected
Description
Unit of
Measure3
Method of
Computation
1.4.2 Fish
Aquatic populations may be
affected by toxic levels of dis-
charged chemicals or by reduced
dissolved oxygen concentrations.
Pounds per year
(by species of
fish).
1.4.3
U)
oj
OJ
Wildlife
(including
birds and
aquatic and
amphibious
mammals and
reptiles).
Suitable habitats for wildlife
may be affected.
Acres.
1.4.4 People
Recreational water uses (boat-
ing, fishing, swimming) may be
inhibited.
Lost annual
user days and
area (acres) or
shoreline miles
for dilution.
(continued)
Total chemical effect on important
species of aquatic biota should be
estimated. Biota exposed within
the facility, as well as biota in re-
ceiving waters, should be considered.
Supporting documentation should
include reference to applicable
standards, chemicals discharged,
and their toxicity to the aquatic
populations affected.
Estimate the area of wetland or
water surface impaired as a wildlife
habitat because of chemical con-
tamination, including effects on
food resources. Document the
estimates of affected population
by species.
The volume of the net flow to the
receiving waters required for dilution
to reach accepted water quality
standards must be determined on
the basis of daily discharge and
converted to either surface area or
miles of shore. Cross-sectional and
annual minimum-flow character-
istics should be incorporated where
applicable. Annual number of
visitors to the affected area or
shoreline must be obtained. This
permits estimation of lost user-days
on an annual basis. Any possible
eutrophication effects should be
estimated and included as a de-
gradation of quality.
-------
TABLE 11.8* (continued)
Primary Impact
Population or
Resources Affected
Description
Unit of
Measure2
Method of
Computation
1.5 Radionuclides dis-
charged to water
body
1.5.1 Aquatic organisms Radionuclide discharge may intro- Rad per year.
duce a radiation level which adds
to natural background radiation.
1.5.2 People, external
1.5.3 People, ingestion
1.6 Consumptive use
1.6.1 People
1.6.2 Agriculture
Radionuclide discharge may intro-
duce a radiation level which adds
to natural background radiation
for water users.
Radionuclide discharge may intro-
duce a radiation level which adds
to natural background radiation
for ingested food and water.
Drinking water supplies drawn
from the water body may be
diminished.
Water may be withdrawn from
agricultural usage and use of
remaining water may be
degraded.
(^continued)
Rem per year for
individual ;man-
rem per year for
estimated popu-
lation as of the
first scheduled
year of plant
operation.
Rem per year for
individuals (whole
body and organ);
man-rem per year
for population as
of first scheduled
year of plant
operation.
Gallons per year.
Acre-feet per year.
Sum dose contributions from
radionuclides expected to be
released.
Sum annual dose contributions
from nuclidcs expected to be re-
leased. Calculate for above-water
activities (skiing, fishing, boating),
in-water activities (swimming), and
shoreline activities.
Estimate biological accumulation
in foods, and intake by individuals
and population. Calculate doses
by summing results for expected
radionuclides.
Where users withdraw drinking
water supplies from the affected
water body, lost water to users
should be estimated. Relevant
delivered costs of replacement
drinking water should be included.
Where users withdrawing irrigation
water are affected, the loss should be
evaluated as the sum of two volumes;
the volume of the water lost to
agricultural users and the volume
of dilution water required to reduce
concentrations of dissolved solids
in remaining water to an agricultur-
ally acceptable level.
-------
TABLE 11.8* (continued)
Primary Impact
Population or
Resources Affected
Description
Unit of
Measure"
Method of
Computation
to
(jj
tn
1.6.3 Industry
1.7 Plant construction (in- 1.7.1 Water quality,
eluding site prepara- physical
tion)
1.7.2 Water quality,
chemical
1.8 Other impacts
1.9 Combined or inter-
active effects
Water may be withdrawn for
industrial use.
Gallons per year.
Turbidity, color or temperature of Acre-feet and acres. The volume of dilution water re-
natural water body may be altered. quired to meet applicable water
quality standards should be cal-
culated. The areal extent of the
effect should be estimated.
Water quality may be impaired. Acre-feet, %.
1.10 Net effects
2. Ground Water
2.1 Raising/lowering of
ground water levels
2.1.1 People
Availability or quality of drinking Gallons per year.
water may be decreased and the
functioning of existing wells may
be impaired.
To the extent possible, the appli-
cant should treat problems of spills
and drainage during construction
in the same manner as in 1.4.1.
The applicant should describe and
quantify any other environmental
effects of the proposed plant that
arc significant.
Where evidence indicates that the
combined effect of a number of
impacts,on a particular population
or resource is not adequately indi-
cated by measures of the separate
impacts, the total combined effect
should be described.
See discussion in Section 5.7.
Volume of replacement water for
local wells actually affected
must be estimated.
(continued)
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TABLE 11.8* (continued)
Primary Impact
Population or
Resources Affected
Description
Unit of
Measure3
Method of
Computation
2.1.2 Plants
2.2 Chemical contamina-
tion of ground water
(excluding salt).
U)
2.3
Radionuclide con-
tamination of
ground water
2.2.1 People
2.2.2 Plants
2.3.1 People
2.3.2 Plants and
animals
2.4
Other impacts on
ground water
Trees and other deep-rooted vege- Acres.
tation may be affected.
Drinking water of nearby commu- Gallons per year.
nities may be affected.
Trees and other deep-rooted vege- Acres.
tation may experience toxic
effects.
Radionuclides that enter ground
water may add to natural back-
ground radiation level for water
and food supplies.
Rem per year for
individuals (whole
body and organ);
man-rem per year
for population as
of year of first
scheduled year of
plant operation.
Radionuclides which enter ground Rad per year.
water may add to natural back-
ground radiation level for local
plant forms and animal popula-
tion.
(continued)
Estimate the area in which ground
water level change may have an ad-
verse effect on local vegetation.
Report this acreage on a separate
schedule by land use. Specify such
uses as recreational, agricultural
and residential.
Compute annual loss of potable
water.
Estimate area affected and report
separately by land use. Specify
such uses as recreational, agri-
cultural and residential.
Estimate intakes by individuals and
populations. Sum dose contributions
for nuclides expected to be released.
Estimate uptake in plants and
transfer to animals. Sum dose
contributions for nuclides expected
to be released.
The applicant should describe and
quantify any other environmental
effects of the proposed plant which
are significant.
-------
TABLE 11.8* (continued)
Primary Impact
Population or
Resources Affected
Description
Unit of
Measure3
Method of
Computation
3. Air
3.1
Fogging and icing
(caused by evapora-
tion and drift)
3.1.1 Ground transpor- Safety hazards may be created in
tation the nearby regions in all seasons.
Vehicle-hours per
year
3.1.2
Air transportation Safety hazards may be created
in the nearby regions in all
seasons.
Hours per year,
flights delayed
per year.
U)
3.1.3
Water transpor-
tation
Safety hazards may be created
in the nearby regions in all
seasons.
Hours per year,
number of ships
affected per year.
3.1.4 Plants
3.2 Chemical discharge to
ambient air
3.2.1
Aii quality,
chemical
Damage to timber and crops may Acres by crop.
occur through introduction of ad-
verse conditions.
Pollutant emissions may diminish % and pounds or
the quality of the local ambient tons.
air.
(continued)
Compute the number of hours per
year that driving hazards will be
increased on paved highways by fog
and ice from cooling towers and
ponds. Documentation should in-
clude the visibility criteria used for
defining hazardous conditions on
the highways actually affected.
Compute the number of hours per
year.that commercial airports will
be closed to visual (VFR) and in-
strumental (1FR) air traffic because
of fog and ice from cooling lowers.
Estimate number of flights delayed
per year.
Compute the number of hours per
year ships will need to reduce speed
because of fog from cooling towers
or ponds or warm water added to
the surface of the river, lake or sea.
Estimate the acreage of potential
plant damage by crop.
The actual concentration of each
pollutant in ppm for maximum
daily emission rate should be ex-
pressed as a percentage of the
applicable emission standard. Re-
port weight for expected annual
emissions.
-------
TABLE 11.8* (continued)
Primary Impact
Population or
Resources Affected
Description
Unit of
Measure3
Method of
Computation
3.3 Radionuclides dis-
charged to ambient
air and direct radia-
tion from radioactive
materials (in-plant or
being transported).
3.2.2 Air quality, odor
3.3.1 People, external
3.3.2 People, ingestion
u>
00
3.3.3
Plants and
animals
3.4 Other impacts on air.
Odor in gaseous discharge or from Statement.
effects on water body may be
objectionable.
Radionuclide discharge or direct
radiation may add to natural back-
ground radiation level.
Radionuclide discharge may add
to the natural radioactivity in
vegetation and in soil.
Radionuclide discharge may add
to natural background radio-
activity of local plant and
animal life.
Rem per year for
individuals (whole
body and organ);
man-rem per year
for population as
of year of first
scheduled
operation.
Rem per year for
individuals (whole
body and organ);
man-rem per year
for population as
of year of first
scheduled opera-
tion.
Rad per year.
A statement must be made as to
whether odor originating in plant
is perceptible at any point offsite
Sum dose contributions from
nuclides expected to be released.
For radionuclides expected to be
released estimate deposit and
accumulation in foods. Estimate
intakes by individuals and popu-
lations and sum results for all ex-
pected radionuclides.
Estimate deposit of radionuclides
on, and uptake in plants and
animals. Sum dose contributions
for radionuclides expected to be
released.
The applicant should describe
and quantify any other environ-
mental effects of the proposed
plant that are significant.
(continued)
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TABLE 11.8* (continued)
Primary Impact
Population or
Resources Affected
Description
Unit of
Measure3
Method of
Computation
4. Land
4.1 Site selection
4.1.1 Land, amount
Land will be preempted for con- Acres.
struction of nuclear power plant,
plant facilities, and exclusion zone.
4.2 Construction activities
(including site
preparation)
u>
u>
10
4.2.1 People (amenities) There will be a loss of desirable
qualities in the environment due
to the noise and movement of
men, material and machines.
Total population
affected, years.
4.2.2 People (accessi- Historical sites may be affected by Visitors per year.
bility of historical construction.
sites)
4.2.3 People (accessi- Construction activity may impinge Qualified opinion.
bility of archeo- upon sites of archeological value.
logical sites)
(continued)
State the number of acres preempted
for plant, exclusion zone, and
accessory .facilities such as cooling
towers and ponds. By separate
schedule, state the type and class
of land preempted (e.g., scenic
shoreline, wet land, forest land,
etc.).
The disruption of community life
(or alternatively the degree of
community isolation from such
irritations) should be estimated.
Estimate the number of residences,
schools, hospitals, etc., within area
of visual and audio impacts. Esti-
mate the duration of impacts and
total population affected.
Determine historical sites that might
be displaced by generation facilities.
Estimate effect on any other sites
in plant environs. Express net
impact.in terms of annual number
of visitors.
Summarize evaluation of impact on
archeological resources in terms
of remaining potential value of the
site. Referenced documentation
should include statements from
responsible county, State or Feder-
al agencies, if available.
-------
TABLE 11.8* (continued)
Primary Impact
Population or
Resources Affected
Description
Unit of
Measure3
Method of
Computation
4.2.4 WUdlife
Wildlife may be affected.
4.2.5 Land (erosion)
Site preparation and plant con-
struction will involve cut and
fill operations with accompany-
ing erosion potential.
4.3 Plant operation
4.3.1 People (amenities) Noise may induce stress.
4.3.2 People (aesthetics) The local landscape as viewed
from adjacent residential areas
and neighboring historical,
scenic, and recreational sites
may be rendered aesthetically
objectionable by the plant -
facility.
4.3.3 Wildlife
Wildlife may be affected.
(continued)
Qualified opinion.
Cubic yards and
acres.
Number of resi-
dents, school
populations,
hospital beds.
Qualified opinion.
Qualified opinion.
Summarize qualified opinion in-
cluding views of cognizant local
and State wildlife agencies when
available, taking into account both
beneficial and adverse affects.
Estimate soil displaced by construc-
tion activity and erosion. Beneficial
and detrimental effects should be
reported separately.
Use applicable state and local codes
for offsite noise levels for assessing
impact. If there is no code, consi-
der nearby land use, current zoning,
and ambient sound levels in assessing
impact. The predicted sound level
may be compared with the pub-
lished guidelines of the EPA,
American Industrial Hygiene As-
sociation, and HUD.
Summarize qualified opinion in-
cluding views of cognizant local
and regional authorities when
available.
Summarize qualified opinion in-
cluding views of cognizant local
and State wildlife agencies when
available, taking into account both
beneficial and adverse effects.
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TABLE 11.8* (continued)
„ . . Population or
Pnmary Impact Resources Affected
4.3.4 Land, flood
control
Description
Health and safety near the water
body may be affected by flood
control.
Unit of
Measure3
Reference to
Flood Control
District approval
Method of
Computation
Reference must be made to regula-
tions of cognizant Flood Control
Agency by use of one of the follow-
ing terms: Has NO IMPLICATIONS
for flood control, COMPLIES
with flood control regulation.
4.4 Salts discharged
from cooling
towers
4.4.1 People
oo
4.4.2
Plants and
animals
4.4.3
Property
resources
Intrusion of salts into ground
water may affect water supply.
Deposition of entrained salts
may be detrimental in some
nearby regions.
Structures and movable property
may suffer degradation from
corrosive effects.
Pounds per Estimate the amount of salts dis-
square foot per charged as drift and particulates.
year. Report maximum deposition.
Supporting documentation should
include patterns of deposition and
projection of possible effect on
water supplies.
Acres. Salt tolerance of vegetation in af-
fected area must be determined.
That area, if any, receiving salt
deposition in excess of tolerance
(after allowance for dilution) must
be estimated. Report separately
an appropriate tabulation of
acreage by land use. Specify such
uses as recreational, agricultural,
and residential. Where wildlife
habitat is affected, identify popula-
tions.'
Dollars per year. If salt spray impinges upon a local
community, property damage may
be estimated by applying to the
local value of buildings, machinery,
and vehicles a differential in average
depreciation rates between this and
a comparable seacoast.community.
-------
SPRAY NOZZLES
FOR CLEANING
DEBRIS TROUGH
HIGH WATER
OPERATING DECK
SCREEN BASKETS —
(OR "TRAYS")
r FLOOR OF SCREEN
1 STRUCTURE
Figure 11.1. Conventional vertical traveling screen(3)
342
-------
Low pressure
(ish washing
system
Conventional
high pressure
spray
Fish buckets exemplify
steps taken to protect
aquatic life in
watercourses. Buckets
replace trash lips that lift
debris from v/ater surface
in conventional traveling
screens. System shown is
similar to cne installed at
Surry nuclear station
Figure 11.2.
Modification of conventional
traveling screens to protect
impinged fish(3).
343
-------
TRASH BARS
SCREEN WELLS
SHORELiNE
mini TOTT
(FISH ENTRAPMENT AREAS)
C....X..itM ntiim
TRAVELING
SCREEN
6H:
(a) CONVENTIONAL SCREEN SETTING
TRASH BARS -
SHORELINE
-"FLUSH" MOUNTING OF SCREEN
1111 ii ji 1111 \ i -r-r-mi—-]*yrr~r \l•''' • f—I
FISH PASSAGE 14 —"-H
7,
1A
.
I
i
s~
— /
^
V
—
'
TRAVELING!
SCREEN
r
^
". ' •
>
J
t
i
C\\
— ^-y—
1
" ' '. 1
f •
1
i
!
rt
PUMPS
Figure 11.3.
(b) MODIFIED SCREEN SETTING (PREFERRED)
Screen settings(3).
(a) Conventional Screen setting
(b) Modified screen setting
fflush mounted)
344
-------
SCREEN
t
iV PIER
UNDESIRABLE
FISH CANNOT
MAKE TURN IN ,
THIS AREA '••
(a) UNSATISFACTORY DESIGN
,l/
I
SCREEN
^
1
*
I
FISH REST
IN THIS AREA
IMPROVED DESIGN
Figure 11.4.
Pier design considerations(3) .
(a) Pier design (unsatisfactory
design)
(b) Pier design (improved design)
345
-------
SHUTTER HOIST
TRASH BIN
GATE LIFT -v
HORIZ. SCREEN
WITH SHUTTER
SCREEN
CLEANING
DEVICE
DRIVE
.UNIT
BYPASS FLUME
I—STOP LOG
GUIDES
INCLINED SCREEN —
BRUSH
ASSEMBLY —
WATER LEVEL
u FISH COLLECTION
TROUGH AND
TRASH RACK
Figure 11.5. Inclined plane screen with fish protection(3)
-------
u>
Figure 11.6. Perforated pipe make-up water intake detail (11).
-------
The full V-shaped, streamlined $lot of
JOHNSON Well Screens (left/ passvs
extraneous materials freely without clog-
ging. In contrast, non-continuous slots
and square-cut forms of openings,
Shown at the right, arc easily clogged
«n
-------
Velocity cap
Idealized Vekxity Distribution
Without Cap
Idealized Velocity Distribution
With Cap
Figure 11.8. Operation of a velocity cap.
349
-------
'-'OR COOLING TO\V> KS AUOVt SLA
LI-VLL. ADO 1 1°F TO WET BULB
ITR 1000 HI ITT OF F.LF.VATION
(K-ll I
E » B -
WATER FLOW
AIR FLOW
SLOWDOWN. GPM
EVAPORATION, GPM
(% EVAP./°R)/IOO
TC3S IN CIRC. WATER |
TD5 IN MAKEUP
MAKEUP. GPM
CIRC. WATER, GPM
COOLING RANGE »F
..i- 30
G
.IOOH
.040H
.0/5-1- £
WET EULB. -F
WET BULB.'F
Figure 11.9.
Cooling tower evaporation rate(20)
Reprinted from Power Engineering,
1977, by T. H. Hamilton with per-
mission of Technical Publishing
Company.
350
-------
40 50 60 70
Water-surface temperature, °F
80
90
Figure 11.10.
Estimating the increase in reser-
voir evaporation resulting from
the addition of heat by a power
plant (22).
351
-------
1000
500
3
DC
Ul
5
I'loo
CL
O
CC
O
so
10
=—n—n—n—i i
MASS SIZE DISTRIBUTION
I I
FISH AND DUNCAN
RESEARCH-COTTRELL
(UNPUBLISHED)
GPU
PSU [KEYSTONE)
ESC (CHALK POINT)
STANDARD INPUT
USED BY CHEN
II t t I I I I i I I I !_!_!
0.1 0.2 125 10 20 50 90 95 S3 99
PERCENT PROBABILITY OF TOTAL MASS SMALLER THAN STATED
99.8
Figure 11.11. 'Cumulative mass distribution of drift
droplets for natural draft cooling
towers(45).
352
-------
5000,
1000 —
3
oc
Ul
1-
UJ
o.
O
tc
O
ECODYNE. 1973
ORGDP. 1973
TURKEY POINT. 1974
NEW CALIBRATED
.ECODYNE DATA, 1976
ESC. 1971
I ! ! I I I
5 to 20 30 40 50 60 70 80 90
PERCENT PROBABILITY OF TOTAL MASS SMALLER THAN STATED
98
Figure 11.12.
Cumulative mass distribution of drift
droplets for mechanical draft cooling
towers(45).
353
-------
1000
100
E
u
o
o
UJ
to
10
10
o
c
u
c
LJ
>
C.I
J I
to
100
DROPLET DIAMETER (MICRONS)
I I I i I
1000
Figure 11.13. Nominal settling rate of water
droplets in air(33).
354
-------
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362
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EPA- 600/7-79-001
TITLE AND«r.TITLi
Steam-electric Power Plants: A Statl-oi thwart
Manual
.„ TECHNICAL REPORT DATA
(Please read Instruction* on the reverie before completing
I3- RECIPIENT'S ACCESSION NO.
5. REPORT DATE
January 1979
6. PERFORMING ORGANIZATION CODE
orT' H-A-Alsentzer, G.A.Englesson,
.C. Hu. and C.
8. PERFORMING ORGANIZATION REPORT NO.
"-"•" --—., j_ _-—•• "•»• • •"••.**.*. M. vv \s fj y ^^
9- PERFORMING OROANIZATIUN NAME AND ADDRESS
Mackell, Inc.
P. O. Box 411
Woodbury, New Jersey 08096
10. PROGRAM ELEMENT NO.
E HE 62 4 A
11. CONTRACT/GRANT NO.
68-02-2637
ADDRES
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
13. TYPE OF REPORT,
Final; 4-10/77
14. SPONSORING AGENCY CODE
EPA/600/13
!Y NOTES
2683.
IERL-RTP project officer is Theodore G. Brna; MD-61, 919/541-
The report, in a practical manual format, gives results of a technical
review of the state-of-the-art of thermal pollution control and treatment of cooling
water in the steam-electric power generation industry. It assesses current, near
horizon, and future technologies utilized or anticipated to be used with closed-cycle
cooling systems. It is organized for ease of reference: the design and operation of
closed-cycle cooling systems, their capital and operating costs, methods of evalua-
tion and comparison, water treatment, environmental assessment of water and non-
water impacts, permits required to build and operate these cooling systems, and
benefit-cost analyses. It provides sufficient information to allow an understanding
of the major parameters which are important to the design, licensing, and operation
of closed-cycle cooling systems. It was prepared for engineers, technical managers,
and federal and state regulatory agency staffs who must evaluate and render judg-
ments on the application and use of these systems.
17,
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Electric Power Plants
Cooling Water
Water Reclamation
Evaluation
Assessments
Pollution Control
Stationary Sources
Thermal Pollution
Closed-cycle Systems
Environmental Assess-
ment
13B
10B
ISA
14B
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisRtp<
Unclass if ied
386
20 SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 <9-73)
------- |