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

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                  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
systems; and  integrated assessments of a wide-range of energy-related environ-
mental issues.
                        EPA REVIEW NOTICE


This report has been reviewed by the participating Federal Agencies and approved
for publication. Approval  does not signify that the contents necessarily reflect
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

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                           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.

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                            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-

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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.

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     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.

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                            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.

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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

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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

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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)

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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:

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                  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

-------
                            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

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                           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

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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

-------
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

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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

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                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

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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

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     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


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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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 6.   Stanford, W. and G.  B.  Hill.  Cooling Tower - Principles
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                               126

-------
13.  Lowe, H. J.  and D.  G. Christie.  Heat Transfer and Pres-
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-------
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                                128

-------
35.  Ryan, P. J.   Heat Dissipation by Spray Cooling.  Progress in
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    in the  United States.  Gilbert Associates, Reading, PA,
    GAI  Report No. 1869, 1975.

44.  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, EPRI-NP-150, 1976.

45.  Heeren, H. and L. Holly.  Dry Cooling Eliminates Pollution.
    Combustion, pp.  18-26, October, 1972.
                               129

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46.   GEA - Gesellschaft fur Luf tkondensation m.b.  H.   Dry Cool-
     ing Tower for the 300-MWe THTR Schmehausen Station in Ger-
     many.  West Germany, 1975.

47.   Norton, R. C. ,  W. J. Westre, and G. L. Larsen.   Dry Cooling
     Design Characteristics of a Large Power Plant.   Proceedings
     of the American Power Conference, 37:591-597,  1975.

48.   Surface, M. O.   System Designs, for Dry Cooling  Towers.
     Power Engineering, 81(9):42-50, 1977.

49.   Rossie, J. P. and E. A. Cecil.  Research  on Dry-Type
     Cooling Tower for Thermal Electric Generating,  Part 1.
     R. W. Beck and Associates, Denver, Colorado,  1970.   (Avail-
     able from National Technical Information  Service,  Spring-
     field, Virginia, PB-206 954).

50.   McAdams, W. H.   Heat Transmission,  Third Edition.   McGraw-
     Hill Book Company, Inc., New York, 1954.

51.   Robinson, K. K. and D. E. Briggs.  Pressure Drop of Air
     Flowing Across Triangular Pitched Tube Banks  of  Finned
     Tubes.  Chemical Engineering Progress Symposium Series,
     62(64), 1966.

52.   Briggs, D. E. and E. H. Young.  Convective Heat  Transfer
     and Pressure Drop Across Triangular Pitch Banks  of  Finned
     Tubes.  Chemical Engineering Progress Symposium Series,
     59(41), 1963.

53.  Eckert, E. R. G. and R. M. Drake, Jr.  Heat and  Mass Trans-
     fer, Second Edition.  McGraw-Hill Company,  Inc., New York,
     1959.

54.  Cook,  E. M.  Rating Methods for Selection of  Air-Cooled
     Heat Exchangers.  Chemical Engineering 97-104,  August,
     1964 .
 55'   ?aF^WZ-M' and A- L' London-  Compact  Heat  Exchangers,
         Edition.  McGraw-Hill Book Company,  Inc.,  New York,
      1964 .
 56.   Grober, H. , S. Erk, and U. Grigull.   Fundamentals of Heat
      Transfer.  McGraw-Hill Book Company,  Inc.,  New York, 1961.

 57.   Rozenman,  T. and J. Pundik.  Design Consideration in the
      Optimization of Dry Cooling Towers.   Proceedings of the
      SpS^h ?n.Dry*CO
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58.  DeSteese, J. G.  and K.  Simphan.  European Dry Cooling Tower
    Experience.  Battelle Pacific Northwest Laboratories, Rich-
    land, Washington,  BNWL-1995, 1976.

59.  United Engineers & Contractors Inc.  Heat Sink Design and
    Cost Study  for  Nuclear and Fossil Power Plants.  Philadelphia,
    PA, UE&C-AEC-740401, 1974.   (Available from National Techni-
    cal Information Service, Springfield, Virginia, WASH-1360).

60.  Englesson,  G. A. and M. C. Hu.  Wet/Dry Cooling Systems
    for Water Conservation.  Prepared Testimony before the
    State Energy Resources Conservation and Development Commis-
    sion of  the State of California, Sundesert Nuclear Project,
    1977.
                                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
                               135

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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

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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

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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

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  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

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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

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  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

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      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.

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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

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                     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

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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

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        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

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 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

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 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

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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

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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

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    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

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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

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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

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                         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

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 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-,,- ^

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aii^L	_-J L_a._n. n1!n
"(TTTnT-
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        B- - S

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     -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-
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    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
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    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

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     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

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    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

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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

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     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

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     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

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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

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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

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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.

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                EVAPORATION

                     t
   M
MAKE-UP
                     TOWER
                                        D
                                      DRIFT
                                            B
                                        SLOWDOWN
Figure 7.2
            Mass balance for an evaporative
            cooling tower.
                    204

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                                 • - 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

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 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

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            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

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                   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.
                               214

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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
                                215

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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
                               220

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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
                                222

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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
                               223

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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
                               224

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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.
                               225

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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.


                               226

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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

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                    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

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                     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

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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

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                     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

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                           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

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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

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    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

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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

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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

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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

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     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

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             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

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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

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             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

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          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

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                                      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

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                         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

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           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

                                265

-------
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
                               266

-------
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


                               267

-------
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
                               268

-------
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.
                                269

-------
                           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.
                               270

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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.
                               282

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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


                               283

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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,
                               285

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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-
                               286

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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)
                               288

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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.
                              289

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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
                               291

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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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a

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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
                               294

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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.
                               297

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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
301

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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:
                                305

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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

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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

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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)

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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)

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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)

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                            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.

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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)

-------
                                                              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
-------
                                                               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.

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                                                             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

-------
                           REFERENCES

1.  Federal Power  Commission.   Steam Electric Plant Air  and
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                              355

-------
10.   Sonnichsen, J. C., Jr., B. W. Bentley, G. F. Bailey, and
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-------
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-------
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-------
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-------
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-------
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-------
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                               362

-------
 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)

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