EPA 440/1-74 029-a


Group I




                             i

       Development Document for




    Effluent Limitations Guidelines



and New Source Performance Standards



                for the
   STEAM ELECTRIC POWER GENERATING
         Point Source Category
                 ^lsr%

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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY



                October 1974

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                          ABSTRACT

This document presents the findings of an extensive study of
the steam electric power generating  point  source  category
for   the   purpose   of  developing  effluent  limitations,
guidelines, standards of performance for  new  sources,  and
pretreatment  standards  for the industry in compliance with
and to implement Sections 30U, 306 and 307  of  the  Federal
Water Pollution Control Act Amendments of 1972.

Effluent  limitations  guidelines contained herein set forth
as mandated by the "Act":

    (1)  The degree of effluent reduction attainable through
    the  application  of  the  "best   practicable   control
    technology  currently  available" which must be achieved
    by nonnew point sources by no later than July 1, 1977.

    (2)  The degree of effluent reduction attainable through
    the  application  of  the  "best  available   technology
    economically  achievable"  which  must  be  achieved  by
    nonnew point sources by no later than July 1, 1983.

The standards  of  performance  for  new  sources  contained
herein  set  forth the degree of effluent reduction which is
achievable through the application of  the  "best  available
demonstrated control technology, process, operating methods,
or other alternatives."

This    report    contains    findings,    conclusions   and
recommendations on control and treatment technology relating
to  chemical  wastes  and  thermal  discharges  from   steam
electric  powerplants.   Supporting  data  and rationale for
development of  the  effluent  limitations,  guidelines  and
standards of performance are contained herein.
                           iii

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                          CONTENTS
Section

I   CONCLUSIONS

II  RECOMMENDATIONS                                      3

III INTRODUCTION                                         7

    Gener al Background                                   7
    Purpose and Authority                                8
    Scope of Work and Technical Approach                11
    Industry Description                                14
    Process Description                                 24
    Alternate Processes                                 26
         Presently Available Alternate Processes        26
              Hydroelectric Power                       26
              Combination Turbines and Diesel Engines   28
         Alternate Processes Under Active Development   29
              Future Nuclear Types                      29
              Coal Gasification                         31
              Combined Cycles                           31
         Future Generating Systems                      32
              Magnetohydr©dynamics                      33
              Electrogasdynamics                        33
              Fuel Cells                                34
              Geothermal Generation                     34
    Industry Regulation                                 35
    Construction Schedules                              3 6
    Reliability,Reserve Generating_Capacitv and         36
      Scheduling of Outages
         Methods of Determining Reserve Requirements    39
         Reserves for Scheduled Outages                 40
         Coordination for Reliability                   42
         Coordinating Techniques                        46
         Small Systems                                  47

IV  INDUSTRY CATEGORIZATION                             51

    Process Considerations                              51
         Fuel Storage and Handling                      51
         Steam Production                               55
         Steam Expansion                                59
         Steam Condensation                             60
         Generation of Electricity                      63
    Raw Materials                                       63
         Coal                                           63
         Natural Gas                                    64

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                    CONTENTS (continued)


Section                                                        Page

         Fuel Oil                                                65
         Refuse                                                  66
    Information on U.S. Generating^Facilities(Size and Age^      67
        ~Size of Units                                           72
         Age of Facilities                                       72
    Mode of Operation  (Utilization)                              79
         Annual Hours of Operation                               84
         Performance Indices                                     84
              Load Factor                                        86
              Operating Load Factor                              86
              Capacity Factor                                    87
              Operating Capacity Factor                          87
              Use Factor                                         87
    Site Characteristics                                         8 8
    Categorization                                               91
         Chemical"wastes                                         93
         Thermal Discharges                                      96
    Summary                                                     100

                   PART A: CHEMICAL WASTES                      107

A-V WASTE CHARACTERIZATION                                      107
   %
    Introduction                                                107
    Once-Through Cooling Systems                                114
    Recirculating Systems                                       114
    Water Treatment                                             120
         Clarification                                          122
         Softening                                              122
         Ion Exchange                                           124
         Evaporator                                             128
         Character of Water Treatment Wastes                    129
    Boiler or PWR Steam Generator Slowdown                      133
    Eguipment Cleaning                                          136
         Chemical Cleaning Boiler or PWR Steam Generator Tubes  135
              Preoperational Boiler Cleaning Wastes             137
              Operational Boiler Cleaning Wastes                142
                   Composition of Scale                         143
                   Frequency of Boiler Cleanings                143
                   Types of Boiler Cleaning Processes           143
                        Alkaline Cleaning Mixtures with         143
                         Oxidizing Agents for Copper Removal
                        Acid Cleaning Mixtures                  144
                        Alkaline Chelating Rinses               144
                         and Alkaline Passivating Rinses
                        vi

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                    CONTENTS (continued)


Section                                                        Page

                        Methods Using Organic Solvents          145
                        Proprietary Processes                   145
         Condenser Cleaning                                     145
         Boiler Fireside Cleaning                               146
         Air Preheater Cleaning                                 146
         Feedwater Heaters Cleaning                             147
         Miscellaneous Small Equipment Cleaning                 148
         Stack Cleaning                                         148
         Cooling Tower Basin Cleaning                           148
    Ash Handling                                                148
         Coal                                                   149
         Oil                                                    160
    Coalpile Runoff                                             160
    Floor and Yard Drains                                       164
    Air Pollution Control Devices                               167
    Sanitary Wastes                                             170
    Plant Laboratory and Sampling Streams                       171
    Intake Screen Wash                                          172
    Service Water Systems                                       172
    Low Level Rad Wastes                                        173
    Construction Activity                                       179
    Chemical Discharges in General                              180
    Summary of Chemical Usage                                   182
    Classification of Waste Water Sources                       182


A-VI  SELECTION OF POLLUTANT PARAMETERS                         189
    Definition of Pollutants                                    189
    Introduct ion                                                189
    Common Pollutants                                           192
         pH Value                                               192
         Total Dissolved Solids                                 192
         Total Suspended Solids                                 192
    Pollutants from Specific waste Streams                      193
         Biochemical Oxygen Demand  (BOD)                        193
         Chemical Oxygen Demand  (COD)                           193
         Oil and Grease                                         193
         Ammonia                                                193
         Total Phosphorus                                       194
         Chlorine Residuals                                     194
         Metals                                                 194
         Phenols                                                196
         Sulfate                                                196
         Sulfite                                                196
         Boron                                                  197
                        vii

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                    CONTENTS (continued)


Section                                                        Page

         Fluoride                                               197
         Alkaline and Acidity                                   197
         Total Solids                                           197
         Fecal Coliform                                         197
         Total Hardness                                         197
         Chloride and Magnesium                                 198
         Bromide                                                198
         Nitrate and Manganese                                  198
         Surfactants                                            198
         Algicides                                              198
         Other Potentially Significant Pollutants               198
    Selection of Pollutant Parameters                           199
    Environmental Significance of Selected Pollutant            202
      Parameters
         Iron -~Total                                           204
         Polychlorinated Biphenyls                              206
         Chlorine - Free Available, - Total Residual            209
         Chromium - Total                                       211
         Copper - Total                                         212
         Oil and Grease                                         213
         pH, Acidity and Alkalinity                             213
         Phosphorus - Total                                     214
         Total Suspended Solids                                 215
         Zinc - Total                                           216

A-VII CONTBOL AND TREATMENT TECHNOLOGY                          219

    General Methodology                                         219
    Pollutant - Specific Treatment Technology                   220
         Aluminum                           •                    220
         Ammonia                                                220
         Antimony                                               220
         Arsenic                                                220
         Barium                                                 220
         Beryllium                                              220
         Boron                                                  221
         Cadmium                                                221
         Calcium                                                221
         Chlorine Residuals                                     221
         Chromium                                               222
         Cobalt                                                 223
         Copper                                                 223
         Iron                                                   224
         Lead                                                   224
         Magnesium                                              224
                          viii

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                    CONTENTS (continued)


Section                                                        Page

         Manganese                                              224
         Molybdenum                                             224
         Mercury                                                225
         Nickel                                                 225
         Oil and Grease                                         225
         Total Phosphorus (as P)                                 225
         Potassium                                              226
         Polychlorinated Biphenyls (PCB's)                       226
         Selenium                                               226
         Silver                                                 226
         Sodium                                                 226
         Sulfate                                  .              226
         Thallium                                               226
         Tin                                                    227
         Titanium                                               228
         Total Dissolved Solids                                 228
         Total Suspended Solids                                 228
         Vanadium                                               228
         Zinc                                                   228
    Combined Chemical Treatment                                 229
         Precipitation                                          229
         Alkali Selection                                       235
         Aeration                                               236
         Solids Separation                                      238
    Evaporation and Other Processes                             238
    Technology Specific to Powerplant Waste Waters (General)^    239
    Continous Waste Streams                                     243
         Cooling Water Systems                                  243
              Chemical Conditioning                             244
                   Chemical Conditioning of Once-Through        244
                    Systems
                   Chemical Conditioning of Recirculating       256
                    Systems
              Mechanical Cleaning of condenser Tubes            267
                   On-Line Mechanical Cleaning                  270
                   Mechanical Cleaning During Scheduled         274
                    Outages
              Economics of Condenser Cleanliness                275
              Design for Corrosion Protection                   278
                   Corrosion Resistant Materials in Condensers  279
                   Corrosion Resistant Materials in Cooling Towers 279
                   Resistant Pretreatments and Coatings         280
              Saltwater Cooling Towers                          280
              Cooling Tower Blowdown Treatment                  281
         Clarification, Softening and Filtration                287
                              ix

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                    CONTENTS (continued)


section                                                        Page

         Ion Exchange Wastes                                    290
         Evaporator Slowdown                                    294
         Boiler or PWR Steam Generator Slowdown                 294
    Periodic Wastes                                             295
         Maintenance Cleaning Wastes                            295
         Ash Handling Wastes                                    296
         Coal Pile Runoff                                       312
         Floor and Yard Drains                                  318
         Air Pollution Control Devices                          318
         Sanitary Wastes                                        323
         Ohter Wastes                                           323
    Various Waste Streams - Concentration and Recycle           324
    Sludge Disposal                                             329
    Powerplant Wastewater Treatment^Systeins                     336
    Wastewater Management                                       336
    Effluent Reduction Benefits of Waste Water Treatment        343
     to Remove Chemical Pollutants
    Summary                                                     346

A-VIII COST, ENERGY AND NON-WATER QUALITY ASPECTS               355

    Introduction                                                355
    Central Treatment plant Costs                               356
    Costs for Wastes Not Treated at Central Treatment           373
      Plant
         Cooling Water - Once Through Systems                   373
         Cooling water Blowdown - Closed Systems                377
         Sanitary Wastes                                        379
         Materials Storage and construction Runoff              383
         Intake Screen Backwash                                 387
         Radwaste                                               387
         Ash Sluicing Systems                                   387
    Costs of Complete Treatment of Chemical Wastes              400
      for Re-use
    Energy                                                      404
    Non-Water Quality Environmental Impacts                     405
         Intermediate Dewatering Devices                        405
         Evaporation Ponds (Lagoons)                            406
         Landfill                                               406
         Conveyance to Off-Site Disposal                        407

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                    CONTENTS (continued)


Section                                                        .Pa3§


A-IX,X,XI     BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY     409
                AVAILABLE, GUIDELINES AND LIMITATIONS
              BEST AVAILABLE TECHNOLOGY ECONOMICALLY            409
                ACHIEVABLE, GUIDELINES AND LIMITATIONS
              NEW SOURCE PERFORMANCE STANDARDS AND              409
                PRETREATMENT STANDARDS

    Best Practicable Control Technology Currently Available     409
         Cooling Systems         .                               409
         Low-Volume waste Waters                                410
         Once-Through Ash and Air Pollution Control Systems     412
         Rainfall Runoff Waste Water Sources                    412
    Best Available Technology Economically Achievable           412
    New Source Performance Standards                            413
    Application of Effluent Limitations Guidelines              414
      and Standards
    Costs                                                       418
    Energy and Other Ngn-Water^guality                          419
      Environmental Impacts

                  PART B: THERMAL DISCHARGES                    421

B-V WASTE CHARACTERIZATION                                      421

    General                                                     421
    Quantification of Waste Stream Characteristics              421
         Industry-wide variations           ~                   426
         Variations with Industry Grouping                      430
    Effluent Heat Characteristics from Systems                  439
      Other Than Main Condenser Cooling Water
    Environmental Risks of Powerplant Heat Discharges           439

B-VI     SELECTION OF POLLUTANT PARAMETERS                      443

    Rationale                                                   443
    Environmental Significance of Effluent Heat                 445

B-VII CONTROL AND TREATMENT TECHNOLOGY                          447

    Introduction                                                447
    Process Change                                              449
         Background                                             449
         History of Steam Electric Powerplant Cycle             457
         Rankine Cycle                                          460
         Rankine Cycle with Superheat                           460
                        xi

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                    CONTENTS (continued)


Section                                                        gage


         Regenerative Cycle                                     460
         Reheat Cycle                                           463
         Historical Process Changes                             465
         Process Changes for Existing Plants                    467
              Feedwater Heater Additions                        467
              Reduce Backpressure (Condensing Pressure)          467
              Increase Steam Temperature                        469
              Increase Steam Pressure                           469
              Reheat                                            469
              Increase Cooling Gas Pressure                     469
              Drain coolers                                     469
              Drains Pumped Forward                             469
              Superposed Plants                                 469
              Complete Plant Upgrading                          472
         Future Improvement in Present Cycles                   474
              Gas Cycles                                        474
                   Gas Cycle Plants-Base Power                  477
                   Gas Cycle Plants-Peaking Power               477
              Combined Gas-Steam Plants                         477
         Future Generation Processes                            479
              Binary Topping Cycles                             479
              Geothermal Steam                                  430
              MHD                                               480
              Fuel Cells                                        480
    Waste Heat Utilization                                      480
         Agricultural Uses                                      482
         Aquaculture                                            482
         Utilization of Extraction Steam                        433
         Total Energy Systems                                   435
    Cooling Water Treatment                                     486
         General                                                486
         Once-Through (Nonrecirculating Systems)                 487
         Once-Through Systems with Supplemental                 489
           Heat Removal (Helper Systems)                         489
         Closed or Recirculating Systems                        496
           Cooling Ponds                                        497
           Spray Ponds                                          508
           Wet-Type Cooling Towers                              520
              Wet Mechanical Draft Towers                       523
                   Induced Draft - Crossflow                    525
                   Induced Draft - Counterflow                  532
                   Forced Draft                                 533
              Wet-Dry Cooling Towers                            533
              Natural Draft Cooling Towers                      535
           Dry-Type Cooling Towers                              543
           Other Tower Types Used Outside the U.S.              550
                             xii

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                    CONTENTS (continued)


Section                                                        Page

           Survey of Existing Cooling Water Systems             555
           Effluent Heat Reduction for Closed-Cycle Systems     562

B-VIII COST, ENERGY AND NON-WATER QUALITY ASPECTS               565

    Cost and Energy                                             565
         Cost Data-Plant Visits                                 569
         Cost Studies for Specific Plants                       573
         Other Cost Estimates                                   578
         Cost Analyses                                          587
         Energy (Fuel) Requirements                             611
         Loss of Generating Capacity                            614
         Site-Dependent Factors                                 614
              Age                    *                           615
              Size                                              621
              Site-Dependent Factors in General                 621
              Flow Rate                                         626
              Intake Temperature                                626
              Wet-Bulb Temperature                              627
              Back-End Loading                                  627
              Aircraft Safety                                   627
              Miscellaneous Factors                             628
              Relative Humidity                                 628
              Land Requirements                                 628
    Non-Water Quality Environmental Impact                      636
      of Control and Treatment Technology
         Drift                                                  636
         Fogging                                                643
         Noise                                                  652
         Height         «                                       655
         Consumptive Water Use                                  655
         Slowdown                                               665
         Aesthetic Appearance                                   666
         Icing Control                                          668
         Non-Water Quality Environmental Aspects                669
           of Spray Cooling Systems
         Non-Water Quality Environmental Aspects                672
           of Surface Cooling
    Comparison of Control Technologies                          673
    Costs Versus Effluent Reduction Benefits                    673
    Considerations of Section 316 (a)                            679
                          xiii

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                    CONTENTS  (continued)


Section                                                         Pagg

B-IX,X,XI     BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY      681
                AVAILABLE, GUIDELINES AND LIMITATIONS
              BEST AVAILABLE TECHNOLOGY ECONOMICALLY             681
                ACHIEVABLE, GUIDELINES AND LIMITATIONS           681
              NEW SOURCE PERFORMANCE STANDARDS AND
                PRETREATMENT STANDARDS

    Limitations                                                  681
    Factors                                                      683

XII      ACKNOWLEDGMENTS                                         701

XIII     REFERENCES                                              711

XIV      GLOSSARY                                                753

Appendix 1    Industry Inventory

Appendix 2    Reliability Coordination Organizations
                            xiv

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                          FIGURES
Number                Title                              Page
III-1     Projected Total U.S. Energy Flow                 22
          Pattern  (1980)
III-2     Condensed Construction Schedule,                 37
          200 Mw Oil-Fired Unit
          •
III-3     Typical LWR Nuclear Plant Project                38
          Schedule, Highlights Only
III-'*     Regional Reliability Versus Percent Reserve      41
IV-1      Schematic Flow Diagram, Typical Steam            52
          Electric Generating Plant
IV-2      Power Cycle Diagram, Fossil Fuel                 53
IV-3      Power Cyle Diagram, Nuclear Fuel                 54
IV-1    '  Typical Boiler for a Coal-Fired Furnace          57
IV-5      Schematic Cooling Water Circuit                  62
IV-6      Cumulative Frequency Distribution of Entire      69
          Powerplant Inventory for All EPA Regions
IV-7      Cumulative Frequency Distribution of Fossil-     70
          Steam Powerplants for All EPA Regions
IV-8      Cumulative Frequency Distribution of Nuclear-    71
          Steam Powerplants for All EPA Regions
IV-9      Largest Fossil-Fueled -Steam Electric             73
          Turbine-Generators in Service (1900-1990)
IV-10     Heat Rates of Fossil-Fueled Steam                76
          Electric Plants
IV-11     Heat Rate vs Unit Capacity                       77
IV-12     Heat Rate vs Unit Age                            78
A-V-1     Typical Flow Diagram, Steam Electric            109
          Powerplant (Fossil-Fueled)
A-V-2     Simplified Water System Flow Diagram            110
          for a Nuclear Unit
                        XV

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                    FIGURES  (continued)

Number                Title                              Page

A-V-3     Nomogram to Determine Langelier                 118
          Saturation Index

A-V-1     Clarification Process                           123

A-V-5     Filtration Process                              123

A-V-6     Ion Exchange Process, Cationic and              i25
          Anionic Type

A-V-7     Ion Exchange Process, Mixed Resin Type          126

A-V-8     Evaporation Process                             130

A-V-9     Typical Ash Pond                                150

A-V-10    Flow Diagram - Air Pollution Control            169
          Scrubbing Device at Plant 4216

A-V-11    Liquid Radioactive Waste Handling               176
          System PWR Nuclear Plants

A-V-12    Liquid Radioactive Waste Handling System        178
          1100 Mw BWR Nuclear Plant

A-VTI-1   Effect of pH on Phosphorus Concentration        227
          of Effluent from Filters Following Lime
          Clarifier

A-VII-2   Solubility of Copper, Nickel, chromium,         230
          and Zinc as a Function of pH

A-VII-3   Theoretical Solubilities of Metal Ions          231
          as a Function of pH

A-VII-4   Experimental Values - Solubility of             232
          Metal Ions as a Function of pH

A-VII-5   Experimentally Determined Solubilities          233
          of Metal Ions as a Function of pH

A-VII-6   Change in the Solubilities of Zinc,             234
          Cadmium, Copper, and Nickel
          Precipitates (Produced with Lime
          Additions) as a Function of Standing
          Time and pH Value

A-VII-7   Brine Concentrator                              240
                      xvi

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                     FIGURES  (continued)

 Number                Title                               Page

A-VII-8   Typical Powerplant Cooling Water Circuit         246

A-VII-9   Concentration of Residual Chlorine in Cooling    248
          Tower Slowdown Versus Time

A-VII-10  Chlorine Peed Control, Once-Through              251
          Condenser Cooling Water

A-VII-11  Typical Powerplant Once-Through Fresh            253
          or Saltwater Cooling Systems, Points
          of Chlorine Application

A-VII-12  Recirculated Powerplant Cooling Water            259
          Systems, Points of Chlorine Application


A-VII-13  Recirculating Condenser Cooling                  265
          System, pH Control of Slowdown

A-VII-1U  Schematic Arrangement                            271
          Amertap Tube Cleaning System

A-VII-15  Reverse Flow Piping                              273

A-VII-16  Tube Cleanliness Versus Cost of                  277
          Reduced Generating Efficiency

A-VII-17  Cooling Tower Blowdown Chromate                  285
          Reduction System

A-VII-18  Typical Process Flow Diagram,                    286
          Chromate Removal System

A-VII-19  Flow Diagram of the Primary Water                288
          Treatment Plant, Mohave Generating
          Station

A-VII-20  Possible Combinations of Concentration           289
          and Evaporation-Crystallization Processes
          For Complete Treatment of Cooling
          Tower Blowdown

A-VII-21  Clarification Waste Treatment Process            291

A-VII-22  Ion Exchange Waste Treatment Process             292

A-VII-23  Neutralization Pond                              293

A-VII-2U  Tube Settler for Ash Sluice Water                302
                          xvii

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                    FIGURES  (continued)

Number                Title                               Page

A-VII-25  Flow Diagram, Recirculating Bottom Ash           306
          System at Plant No. 3630

A-VII-26  Flow Diagram, Recirculating Bottom Ash           307
          System at Plant No. 5305

A-VII-27  Ash Sedimentation System - Plant No. 5305        308

A-VII-28  Ash Handling System - Plant No. 3626             309

A-VII-29  Ash Handling System, Oil Fuel Plant              311
          - Plant No. 2512

A-VII-30  Cost of Neutralization Chemicals                 314

A-VII-31  Comparison of Lime, Limestone, and               315
          Soda Ash Reactivities

A-VII-32  Comparison of Settling Rate                      316

A-VII-33  Coal Pile - Plant No. 5305                       317

A-VII-3a  Cylindrical Air Flotation Unit                   319

A-VII-35  Typical A.P.I. Oil-Water Separator               319

A-VII-36  Oil Separator and Air Flotation Unit             320
          - Plant No. 0610

A-VII-37  Corrugated Plate Type Oil Water                  321
          Separator

A-VII-38  Oil Water Separator                              322

A-VII-39  Vapor - Compression Evaporation                  325
          System (Case I)

A-VII-40  Vapor - Compression Evaporation                  327
          System (Case II)

A-VII-U1  Sewage and Waste Water Disposal for a            337
          Typical Coal-Fired Unit, 600 Mw

A-VII-42  Recycle of Sewage and Waste Water for a          338
          Typical Coal-Fired Unit, 600 Mw

A-VII-U3  Recycle Water System, Plant No. 2750             340

A-VIII-1  Flow Sheet, Coal Fired Plant                     357
          Central Treatment Plant
                        xviii

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                    FIGURES  (continued)

Number                Title                              Page
A-VIII-2  Cost of Equalization Tanks and                  358
          Oil Removal Tanks

A-VIII-3  Costs of Clarifier, Reactor System,             359
          and Filters

A-VIII-U  Estimated Total Capital Costs of                368
          Central Treatment Plants

A-VTII-5  Annual Costs of Labor, Chemicals and            374
          Power for Chemical Treatment

A-VIII-6  Cost for Coal Pile Run-off Collection           384

A-VIII-7  Materials Storage Area Runoff Treatment         335

A-VIII-8  Flow Sheet, Recalculating Bottom Ash            390
          Sluicing Slowdown Treatment

A-VIII-9  Treatment of Combined Ash Overflow              39 ]_

A-VIII-10 Estimated Total Capital Costs for Materials     395
          Storage and Construction Activities Rainfall
          Runoff Treatment, Recirculating Bottom Ash
          Systems with Slowdown Treatment and Recirculating
          Bottom Ash Systems with Treatment of combined
          Ash Pond Overflow, All for Coal-Fired Plants

A-VIII-11 100 Mw Coal-Fired Steam Electric                402
          Powerpiant. Recycle and Reuse of
          Chemical Wastes

A-VIII-12 100 Mw Oil-Fired Steam Electric                 403
          Powerplant, Recycle and Reuse of
          Chemical Wastes

A-X-1     Hypothetical Powerplant Water Flows             4^5

B-V-1     Onit Condenser Delta  (T)                        422

B-V-2     Unit Heat Rate Distribution                     424

B-V-3     Maximum Summer Outfall Temperature              427

B-V-4     Delta (T) vs Onit Age                           431

B-V-5     Base Unit Heat Rates                            433

B-V-6     Cycling Unit Heat Rates                         434
                         xix

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                    FIGURES  (continued)
Number                Title
B-V-7     Peaking Unit Heat Rates
B-V-8     Base Unit Condenser Delta (T)
B-V-9     Cycling Unit Condenser Delta (T)
B-V-10    Peaking Dnit Condenser Delta (T)
B-VII-1   Energy Flow for a Powerplant
B-VII-2   Energy Balance for a Powerplant
B-VII-3   Powerplant Violating Second Law
B-VII-4   Powerplant Violating First Law
B-VII-5   Powerplant Conforming to First
          and Second Law
B-VII-6   Carnot Cycle Steam Powerplant
B-VII-7   Rankine Cycle  Powerplant
B-VII-8   Rankine Cycle with Superheat
          Powerplant
B-VII-9   Regenerative Cycle Powerplant
B-VII-10  Reheat Cycle Powerplant
B-VII-11  Drain Cooler Addition to Powerplant
B-VII-12  Drains Pumped Forward in Powerplant
B-VII-13  Superposed Plant Addition
B-VII-1U  Simple Brayton Cycle Gas Turbine
          Powerplant
B-VII-15  Brayton Cycle with Regenerator Gas
          Turbine Powerplant
B-VII-16  Combined Gas-Steam Powerplant
B-VII-17  Once-Through (Open) Circulating
          Water System
B-VII-18  Once-Through (Open) System with
          Helper Cooling System Installed
Page
 435
 436
 437
 438
 452
 452
 454
 454
 455

 456
 461
 462

 464
 466
 470
 471
 473
 475

 476

 478
 488

 491
                        xx

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                    FIGURES  (continued)
Number                Title                              Page
B-VII-19  Cooling System Capable of Both                  492
          Open and Closed Mode Operation
B-VII-20  Plant Layout at Plant No. 2119                  493
B-VII-21  Seasonal Variation of Helper Cooling            495
          Tower
B-VII-22  Cooling Canal - Plant No. 1209                  499
B-VII-23  Chart for Estimating Cooling Pond               502
          Surface Heat Exchange Coefficient
B-VII-24  Cooling Pond Surface Area vs Heat               504
          Exchange Coefficient
B-VII-25  Determination of Surface Temperature            505
          Increase Resulting From Thermal
          Discharge of Station
B-VII-26  Determination of Average Surface                506
          Temperature Increase Resulting
          From Thermal Discharge of Station
B-VII-27  Estimation of Capital Cost of                   507
          Cooling Pond
B-VII-28  Dnitized Spray Module                           510
B-VII-29  Four Spray Module                               511
B-VII-30  Spray Canal - Plant No. 0610                    512
B-VII-31  Spray Modules - Plant No. 0610                  513
B-VII-32  Graphic Representation of Design                515
          of Spray Augmented Cooling Pond
B-VII-33  Thermal Rotor System                            516
B-VII-34  Double Spray Fixed Thermal Rotor                517
B-VII-35  Graphic Representation of Preliminary           518
          Cost Data on Rotating Disc Device
B-VII-36  Determination of Required Flow per              519
          Disc for Rotating Disc Device
B-VII-37  Counterflow Mechanical Draft Tower              521
                    xxi

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                     FIGURES (continued)
 Number                 Title                              Page
B-VII-38  Crossflow Mechanical Draft Tower                 521
B-VII-39  Crossflow Natural Draft Tower                    522
B-VII-HO  Counterflow Natural Draft Cooling                522
          Tower
B-VII-41  Typical Chart for Determining                    527
          Fating Factor
B-VII-42  Cost Vs Rating Factor,                           528
          Mechanical Draft Tower
B-VII-43  Cooling Tower Performance Curves                 529
B-VII-UU  Comparison of K-Factor and Rating                530
          Factor for the Performance of
          Mechanical Draft Cooling Towers
B-VII-45  Graph Showing Variation of Cost of               531
          Mechanical Draft Cooling Towers
          with Water Flow
B-VII-U6  Mechanical Forced Draft Cooling                  534
B-VII-U7  Parallel Path Wet-Dry Cooling                    534
          Tower Psychrometrics
B-VII-U8  Parallel Path Wet-Dry Cooling                    536
          Tower for Plume Abatement
B-VII-U9  Parallel Path Wet-Dry Cooling                    537
          Tower (Enlarged Dry Section)
B-VII-50  Typical Natural Draft Cooling                    539
          Towers - Plant No. 4217
B-VII-51  Hyperbolic Natural Draft Crossflow               540
          Water Cooling Towers, Typical Cost
          Performance Curves for Budget
          Estimates
B-VII-52  Hyperbolic Natural Draft Crossflow               541
          Water Cooling Towers, Typical Cost
          Performance Curves for Budget
          Estimates
B-VII-53  Fan-Assisted Natural Draft Cooling               542
          Tower
                       xxii

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                    FIGURES (continued)

Number                Title                              Page

B-VII-54  Direct, Dry-Type Cooling Tower                  544
          Condensing System with Mechanical
          Draft Tower

B-VII-55  Indirect, Dry-Type Cooling Tower                545
          Condensing System with Natural-
          Draft Tower

B-VXI-56  Temperature Diagram of Indirect Dry             546
          Cooling Tower Heat-Transfer System

B-VII-57  Representative Cost of Heat Removal             543
          With Dry Tower Systems for Nuclear
          Plants

B-VII-58  Steam Type Direct Contact Condenser             549

B-VII-59  Effect of Turbine Exhaust Pressure on           551
          Fuel Consumption and Power Output

B-VII-60  Section Across a Circular Mechanical            552
          Draft Cooling Tower

B-VII-61  Frimmersdorf Power Station                      553

B-VII-62  Cable Tower                                     554

B-VII-63  Cooling Tower with Noise Control                555
          at Lichterfelde Plant

B-VIII-1  Example of Optimization of Net Unit             570
          Power Output by Reduction of Cooling
          Tower Fans

B-VlII-la Salinity Effects on Cooling Tower               583
          Size and Costs

B-VIII-2  Additional Generating Costs for                 601
          Mechanical Draft Towers, Base-Load
          Unit, 300 Mw, 6 Year Remaining Life

B-VIII-3  Additional Generating Costs for                 601
          Mechanical Draft Towers, Base-Load
          Unit, 300 Mw, 18 Year Remaining Life

B-VIII-U  Additional Generating Costs for                 601
          Mechanical Draft Towers, Base-Load
          Unit, 300 Mw, 30 Year Remaining Life
                        xxiii

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                    FIGURES  (continued)

Number                Title                              Page

B-VIII-5  Additional Generating Costs for                 601
          Mechanical Draft Towers, Base-Load
          Unit, 300 Mw,  18 Year Remaining Life

B-VIII-6  Additional Generating Costs for                 601
          Mechanical Draft Towers, Base-Load
          Unit, 300 Mw,  30 Year Remaining Life

B-VIII-7  Additional Generating Costs for                 603
          300 Mw Cyclic  Unit, Mechanical
          Draft Towers,  6 Year Remaining Life

B-VIII-8  Additional Generating Costs for                 603
          300 Mw Cyclic  Unit, Mechanical
          Draft Towers,  18 Year Remaining Life

B-VIII-9  Additional Generating Costs for                 603
          300 Mw Cyclic  Unit, Mechanical
          Draft Towers,  30 Year Remaining Life

B-VIII-10 Additional Generating Costs for                 603
          300 Mw Peaking Unit, Mechanical
          Draft Towers,  6 Year Remaining Life

B-VIII-11 Additional Generating Costs for                 603
          300 Mw Peaking Unit, Mechanical
          Draft Towers,  18 Year Remaining Life

B-VIII-12 Additional Generating Costs for                 603
          300 Mw Peaking Unit, Mechanical
          Draft Towers,  30 Year Remaining Life

B-VIII-13 Variation of Additional Generation              604
          Cost with Capacity Factor

B-VIII-1** Additional Generating Costs for 800 Mw          606
          Nuclear Unit,  Mechanical
          Draft Cooling  Towers, 18 Year
          Remaining Life

B-VIII-15 Additional Generating Costs for 800 Mw          606
          Nuclear Unit,  Mechanical
          Draft Cooling  Towers, 30 Year
          Remaining Life

B-VIII-16 Turbine Exhaust Pressure Correction             612
          Factors (Example, Plant No. 3713)

B-VIII-17 Costs/Benefits of Retrofitting Versus           620
          Age of Unit
                       xxiv

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                    FIGURES  (continued)

Number                Title                              Page
B-VIII-18 Percentage Distribution of 1983                 622
          Generation By Annual Cost of
          Closed-Cycle Cooling

B-VIII-19 Capital Costs of Retrofitting Mechanical        623
          Draft Cooling Towers to Units Placed into
          Service After 1970 Versus Size of Unit

B-VIII-20 Broadside Multiple Tower Orientation            632

B-VIII-21 Longitudinal Multiple Tower Orientation         633

B-VIII-22 Ground-Level Salt Deposition Rate from          641
          a Natural-Draft Tower as a Function of
          the Distance Downwind: A comparison
          Between various Prediction Methods

B-VIII-23 Modified Psychrometric Chart                    644

B-VIII-24 Graphical Distribution of Potential             646
          Adverse Effects From cooling Towers
          Based on Fog, Low-Level Inversion and
          Low Mixing Depth Frequency

B-VIII-25 Location of Natural Draft Cooling               649
          Towers Through 1977

B-VIII-26 Fan Cost Versus Noise Reduction                 654

B-VIII-27 Heat Transfer Mechanisms With                   657
          Alternative Cooling Systems

B-VIII-28 Water Consumption versus                        660
          Meteorology and Cooling Range

B-VIII-29 Regions Upon Which Water Consumption            662
          Studies Have Been Based

B-VIII-30 Additional Cost Versus Heat Discharged          675

A-2-1     Formal Coordinating Organizations or           A2-1
          Power Pools

A-2-2     Informal Coordinating Groups                   A2-2

A-2-3     National Electric Reliability Council          A2-3
          Regions
                       XXV

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                           TABLES

 Number                     Title                        Page

I1-1      Summary of Effluent Limitations Guidelines        4
          and Standards for Pollutants Other Than Heat

II-2      Summary of Effluent Limitations Guidelines        5
          and Standards for Heat

III-1     Principal Statutory Considerations               10

III-2     Summary Description Electrical Power             16
          Generating Industry (Year 1970)

III-3     Projected Growth of Utility Electric             18
          Generating Capacity

III-U     FPC Projection of Fuel Use                       19
          in Steam Electric Powerplants

III-5     FPC Projected Annual Fuel Requirements           21
          for Steam Electric Powerplants

IV-1      Industry Inventory Summary                       68

IV-2      Distribution of Installed Generating             74
          Capacity in the U.S. By Size for Various
          Years When Equipment Was First Placed
          In Service

IV-3      Urban Steam Electric Powerplants                 85

IV-4      Characteristics of Units Based on                89
          Annual Hours of Operation

IV-5      Chemical Waste Categories                        94

IV-6      Applicability of Chemical Waste                  95
          Categories by Fuel Type

IV-7      General Subcategorization Rationale             101

IV-8      Subcategorization Rationale for Heat            102

IV-9      Subcategorization Rationale for Pollutants      103
          Other Than Heat

IV-10     Distribution of U.S. Generating Capacity by     105
          Age and Capacity Factor
                          xxvi

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                      TABLES (continued)

 Number                      Title                        page

A-V-1     Recirculating Water Quality Limitations          117

A-V-2     Typical Characteristics of Powerplant Water      121
          Supplies

A-V-3     Typical Water Treatment Waste Water Flows        131

A-V-U     Arithmetic Mean and Deviation of                 134
          Selected Water Treatment Waste Para-
          meters

A-V-5     Chemical Waste Characterization,                 138
          Boiler Tubes* Cleaning

A-V-6     Chemical Waste Characterization,                 141
          Air Preheater Cleaning, Boiler
          Fireside Cleaning

A-V-7     Constituents of Coal Ash                         152

A-V-8     Time of Flow for Ash Handling Systems            153

A-V-9     Chemical Waste Characterization,                 154
          Ash Pond Overflow - Net Discharge

A-V-10    Coal Pile Drainage                               162

A-V-11    Chemical Waste Characterization                  165
          Coal Pile Drainage

A-V-12    Equipment Drainage, Leakage                      166

A-V-13    Total Metals Discharged from Powerplants         181
          in the U.S.  (1973) Compared to Other
          Industrial Sources

A-V-1U    Total Iron and Copper Discharges from            181
          Coal-Fired Powerplants in the U.S.  (1973)

A-V-15    Chemicals Used in Steam Electric Powerplants     183

A-V-16    Chemicals Associated with Nuclear                184
          Power Plants

A-V-17    Use of High Tonnage Chemical Additives           185
          by Steam Electric Powerplants (1970)

A-V-18    Chemical Composition of Trade-Name               186
          Microorganism Control Chemicals
                           xxvii

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                      TABLES (continued)
 Number                      Title                        Page
A-V-19    Class of Various Waste Water Sources             187
A-V-20    Typical Chemical Wastes from a Coal-             188
          Fired Powerplant
A-VI-1    Applicability of Parameters to Chem-             190
          ical Waste Streams
A-VI-2    Chemical Wastes - Number of Plants               191
          with Recorded Data
A-VI-3    Selection of Pollutant Parameters                200
A-VI-1*    Selected Pollutant Parameters                    203
A-VII-1   Comparison of Alkaline Agents                    237
          for Chemical Treatment
A-VII-2   Operating Data, Typical Powerplant               246
          Cooling Water Chlorination, Open
          Once-Through Cooling Systems
A-VII-3   Chemical Conditioning of a Cooling Tower         257
          System Using CrOJJ - PO.4
A-VII-H   Chemical Conditioning of a Cooling Tower         257
          System Using Organic Phosphate
A-VII-6   No Chemical Conditioning of Cooling Tower        268
          System Except for Alkalinity Control, But
          Using On-Line Mechanical Cleaning Condenser
          Tubes
A-VII-7   Complete Chemical Conditioning of Cooling        268
          Tower System At "Zero" Discharge with
          Sidestream Treatment of Tower Waste and
          On-Line Mechanical Cleaning Condenser Tubes
A-VII-8   Comparitive Capital Costs of Condenser           276
          Cleaning Systems
A-VII-9   Comparative Annual Costs                         276
A-VII-10  Recommended Construction Materials for           282
          Cooling Tower Operating with Salt Water
A-VII-11  Waste Disposal Characteristics of Typical        283
          Cooling Tower Inhibitor Systems
A-VII-12  Ash Pond Performance                             297
                         xxviii

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                     TABLES  (continued)

Number                      Title                        Page
A-VII-13  Summary of EPA Data Verifying                    298
          Ash Pond Performance, Plant No. 0107

A-VII-1<»  Ash Pond Effluent Total                          300
          Suspended Solids


A-VII-15  Performance of Tube settlers for Ash             304
          Sluice Water

A-VII-16  RCC Brine concentrator System Chemistry          325
          (Case I)

A-VII-17  RCC Brine Concentrator System Chemistry          323
          (Case II)

A-VII-18  Ash Collection and Utilization, 1971             330

A-VII-19  Known Uses for Ash Removal From Plant            330
          at No Cost to Utility

A-VII-20  Extent of Present Use of Chemical Waste          344
          Disposal Methods in Coal-Fired Powerplants
          (1973)

A-VII-21  Chemical Wastes - Control and                    347
          Treatment Technology

A-VII-22  Flow Rates - Chemical Wastes                     349

A-VII-23  Costs/Effluent Reduction Benefits,               350
          Control and Treatment Technology for
          Pollutants Other Than Heat, High
          Volume Waste Streams

A-VII-2U  Costs/Effluent Reduction Benefits,               351
          Control and Treatment Technology for
          Pollutants Other Than Heat,
          Intermediate Volume Waste Streams

A-VII-25  Costs/Effluent Reduction Benefits,               352
          Control and Treatment Technology for
          Pollutants Other Than Heat,
          Low volume waste Streams

A-VII-26  Costs/Effluent Reduction Benefits,               353
          Control and Treatment Technology for
          Pollutants Other Than Heat,
          Rainfall Runoff Waste Streams
                         xxix

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                     TABLES  (continued)

 Number                       Title                        Page

A-VIII-1  Estimated Equipment Costs, Central               360
          Treatment Plant for Coal-Fired Powerplants

A-VIII-2  Estimated Equipment Costs, Central               361
          Treatment Plant for Oil-Fired Powerplants

A-VIII-3  Estimated Equipment Costs, Central               362
          Treatment Plant for Gas-Fired Powerplants

A-VIII-U  Estimated Equipment Costs, Central               363
          Treatment Plant for Nuclear Powerplants

A-VIII-5  Estimated Total Capital Costs, Central           364
          Treatment Plant for Coal-Fired Powerplants

A-VIII-6  Estimated Total Capital Costs, Central           365
          Treatment Plant for Oil-Fired Powerplants

A-VIII-7  Estimated Total Capital Costs, Central           356
          Treatment Plant for Gas-Fired Powerplants

A-VIII-8  Estimated Total Capital Costs, Central           357
          Treatment Plant for Nuclear Powerplants

A-VIII-9  Estimated Annual Costs, Central Treatment        369
          Plant for Coal-Fired Powerplants

A-VIII-10 Estimated Annual Costs, Central Treatment        370
          Plant for Oil-Fired Powerplants

A-VIII-11 Estimated Annual Costs, Central Treatment        371
          Plant for Gas-Fired Powerplants

A-VIII-12 Estimated Annual Costs, Central Treatment        372
          Plant for Nuclear Powerplants

A-VIII-13 Capital and Operating Costs for On-Line          375
          Tube Cleaning Equipment

A-VIII-14 Typical Sponge Rubber Ball Tube Cleaning         375
          System Costs

A-VIII-15 Costs Comparison of Alternative Tube             373
          Material

A-VIII-16 Capital Investment Costs for Chromate            390
          Reduction Systems

A-VIII-17 Variable Operating Costs for Materials           330
          and Supplies, Chromate Reduction Systems
                       XXX

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                     TABLES  (continued)

Number                      Title


A-VI1I-18 Units Costs of Chrornate Reduction Systems       381

A-VIII-19 Slowdown Treatment System Costs             •    382

A-VIII-20 Estimated Costs, Materials Storage and          338
          Construction Activities Runoff Treatment
          (Coal-Fired Plant)

A-VIII-21 Estimated Equipment Costs, Recirculating        392
          Bottom Ash Systems and Treatment of Bottom
          Ash Slowdown

A-VIII-22 Estimated Equipment Costs, Recirculating        393
          Bottom Ash Systems and Treatment of
          Combined Ash Pond Overflow

A-VIII-23 Estimated Capital Costs, Recirculating          394
          Bottom Ash Systems and Treatment of
          Bottom Ash Slowdown

A-VIII-24 Estimated Capital Costs, Recirculating          395
          Bottom Ash Systems and Treatment of
          Combined Ash Pond Overflow

A-VIII-25 Estimated Annual Costs, Recirculating           397
          Bottom Ash Systems and Treatment of
          Bottom Ash Slowdown

A-VIII-26 Estimated Annual Costs, Recirculating           393
          Bottom Ash Systems and Treatment of
          Combined Ash Pond Overflow

A-X-1     Effluent Limitations for Hypothetical Plant     415

B-V-1     Efficiencies, Heat Rates, and Heat              425
          Rejected by Cooling Water

B-V-2     Plant Visit Thermal Data                        428

B-V-3     Typical Characteristics of Waste                440
          Heat Rejection

B-V-1     Total Plant Thermal Discharges                  441

B-VII-1   Efficiency Improvements                         468

B-VII-2   Energy Demand by Heat Using                     434
          Applications (1970)
                      xxxi

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                     TABLES  (continued)

Number                       Title                        Page


B-VII-3   Oses of Various Types of                        557
          Cooling Systems

B-VII-4   Extent to Which Steam Electric                  558
          Powerplants are Already Committed
          to the Application of Thermal
          Control Technologies

B-VII-5   Cooling Systems for Plants 300 Mw and           559
          Larger Under Contruction

B-VII-6   cooling Water Systems Data, Plants              551
          Visited

B-VII-7   Effects of Cycles of Concentration on           553
          Cooling System Losses, Makeup Required,
          Reduction in Effluent Heat

B-VII-8   Effects of Cycles of Concentration on           554
          Heat Discharged From a 1000 Mw Power Station

B-VIII-1  Cooling Water Systems - Cost Data,              572
          Plants Visited

B-VIII-2  Estimated Costs of Typical Installations of     577
          Backfitting Closed-Cycle cooling Systems to
          Once-Through Cycle Plants

B-VIII-3  Comparative Cost Estimates of New               579
          Nuclear-Fueled Plant Cooling Systems

B-VIII-U  Comparative Costs Estimates for New             580
          Fossil-Fueled Plant Cooling Systems

B-VIII-5  Cost Estimates of Retrofitted Cooling           581
          Systems for Specific Generating Stations

B-VIII-6  Cost Estimates of New Plant Cooling             582
          Systems for Specific Generating Stations

B-VIII-7  Capital Costs of selected Cooling Ponds         584

B-VIII-8  Thermal Control Costs for New Plants            586

B-VIII-9  Cost of Cooling System Equipment                589

B-VI11-10 Hypothetical Plant Operating Parameters         591

B-VIII-11 Revised Plant Operation Parameters              591
                       xxxii

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                     TABLES  (continued)

Number                      Tide

B-VIII-12 Typical Plant Characteristics                   593

B-VIII-13 Assumed Increase in Heat Rate Compared          595
          to Base Heat Rate as a Function of the
          Turbine Exhaust Pressure

B-VIII-14 Cost Assumptions                                597

B-VIII-15 Cooling Tower Economic Analysis                 gOO

B-VIII-16 Comparison of Burns and Roe Economic Analyses of  507
          Retrofitting Cooling Towers Wtih Sargent
          and Lundy Analysis

B-VIII-17 Comparison of Utility Survey of Retrofitting
          Costs With EPA Cost Curves

B-VIII-18 Energy  (Fuel) Consumption Penalty
          Due to Increased Turbine Backpressure
          from Closed-Cycle cooling System

B-VIII-19 Computer Simulation of Costs of
          Retrofitting Cooling Towers,Mechanical
          Draft, 411 Mw Units, 72X Capacity Factor

B-VIII-20 Computer Simulation of Costs of Retrofitting    617
          Cooling Towers, Mechanical Draft, 535 Mw
          Units, 44% Capacity Factor

B-VIII-21 Computer Simulation of Costs of Retrofitting    618
          Cooling Towers Natural Draft, 411 Mw Units,
          72% Capacity Factor

B-VIII-22 Computer Simulation of Costs of Retrofitting    619
          Cooling Towers, Mechanical Draft, 82°F Wet
          Bulb, 78° Stream Temperature, 600 gpm/Mw

B-VIII-23 Summary of Selected Utilities Capital Costs,    625
          Capability Losses and Energy Losses for
          Mechanical Draft and Natural Draft Cooling
          Towers  (1973 Dollars)

B-VIII-24 Effluent Heat, Applicability of                 629
          Control and Treatment Technology

B-VIII-25 Solids in Drift From Cooling Towers             638
                        xxxiii

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                     TABLES  (continued)

Number                      Title                        Page


B-VIII-26 Factors Affecting Dispersion and                640
          Deposition of Drift from Natural-Draft
          and Mechanical-Draft Cooling Towers

B-VIII-27 Energy Production of Some Natural               551
          and Artificial Processes at Various
          Scales

B-VIII-28 Evaporation Rates for Various Cooling           658
          Systems

B-VIII-29 comparative Utilization of Natural              559
          Resources With Alternative Cooling
          Systems for Fossil-Fuel Plant with
          680 Mw Net Plant Output

B-VIII-30 Control and Treatment Technologies              674
          for Heat: Costs, Effluent Reduction
          Benefits, and Non-Water Quality
          Environmental Impacts

B-VIII-31 Cost Versus Effluent Reduction Benefits,        676
          0-100* Removal of Heat

B-VIII-32 Incremental Cost of Application of              677
          Mechanical Draft Evaporative Cooling
          Towers to Nonnew Units (Basis 1970 Dollars)

B-VIII-33 Incremental Cost of Application of              678
          Mechanical Draft Evaporative Cooling
          Towers to New Units (Basis 1970 Dollars)

B-VIII-34 Timing for Cases Leading to Significant         680
          Thermal Controls

A-2-1     Members of Formal Coordinating                 A2-4
          Organizations or Power Pools (1970)

A-2-2     Informal Coordinating Organizations            A2-5
          or Power Pools (1970)

A-2-3     Multiple Memberships in Informal               A2-6
          Coordinating Organizations or Power Pools

A-2-4     Individual Members of Regional Reliability     A2-7
          Councils
                         xxxiv

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                         SECTION I

                        CONCLUSIONS
For   the  purpose  of  establishing  effluent  limitations,
guidelines and standards of performance for  steam  electric
powerplants,  it  has been found that separate consideration
must be given to effluent heat and to pollutants other  than
heat, and these are therefore discussed in separate parts of
this report.

The  framework  for  establishing limitations for pollutants
other than heat (chemical-type wastes) has been based on the
types of waste streams generated in  each  plant,  which  in
turn  are dependent on fuels used, processes employed, plant
site  characteristics  and   waste   control   technologies.
Chemical-type wastes include wastes from the water treatment
system,   power  cycle  system,  ash  handling  system,  air
pollution  control  system,  coal  pile,  yard   and   floor
drainage,, condenser cooling system and miscellaneous wastes.

Significant   factors  for  limitations  for  effluent  heat
(thermal discharges)  are  utilization,  age,  and  size  of
facilities.

A  survey  of  current industry practices has indicated that
many plants provide only minimal treatment of chemical  type
wastes  at  the  present  time,  although  some  of the more
recently constructed  plants  employ  elaborate  re-use  and
recycle  systems  as  a  means of water management.  Current
industry practice as far as thermal discharges are concerned
is  that  they  have  been  successfully  controlled   where
required  by  environmental considerations or at sites where
the lack of sufficient  naturally  available  cooling  water
made once-through cooling systems impractical.

Current  treatment  and  control  technology  in the general
field of waste treatment includes many processes which could
be  applied  by  powerplants  to  reduce  the  discharge  of
chemical  pollutants.   It  is therefore concluded that best
practicable control technology  currently  available  to  be
applied  no later than July 1, 1977, consists of the control
and treatment of chemical-type wastes to achieve significant
reductions  in  the  level  of  pollutants  discharged  from
existing  sources.  It is also concluded that best available
technology economically achievable to be  applied  no  later
than  July 1, 1983, for chemical-type wastes is reflected in
addition by recycle of bottom ash  transport  water  and  by
chemical  treatment  of  cooling  tower  blowdown  to remove

-------
chromium, phosphorus and zinc.  Standards of performance for
new sources will provide for essentially the  same  effluent
levels as best available technology, however, limitations on
cooling  tower  blowdown  are  based on design for corrosion
prevention  rather  than  the  addition  of  chemicals   for
corrosion inhibition.

For  thermal  effluents,  it is concluded that technology is
currently available and is widely utilized in  the  industry
to  achieve  any desired or necessary degree of reduction of
the thermal component of  powerplant  discharges,  including
essentially  the complete elimination of thermal discharges.
The  technological  basis  for  best  available   technology
economically   achievable,   and   new   source  performance
standards  consists  of  closed-cycle  evaporative   cooling
systems  such as mechanical and natural draft cooling towers
and cooling ponds, lakes and canals.

The designation of specific control and  treatment  as  best
practicable  control  technology  currently  available, best
available technology  economically  achievable,  or  as  the
basis for new source standards for both chemical and thermal
discharges  is  intended  to satisfy sections 304 and 306 of
the Act.  Technology so designated provides  the  basis  for
establishment  of thermal and chemical effluent limitations,
guidelines and standards, in that the technology selected is
available   and   capable   of   meeting   the   recommended
limitations.    However,   the   designation   of   specific
technology as "best practicable", etc., does not  mean  that
it  alone must be utilized to meet the effluent limitations.
Any technology capable of meeting  the  limitations  may  be
employed   by   any  powerplant  so  long  as  the  effluent
limitations are achieved.

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                         SECTION II

                      RECOMMENDATIONS

As a result of the findings  and  conclusions  contained  in
this   report,  the  effluent  limitations,  guidelines  and
standards of performance recommended for the steam  electric
power  generating  point source category, in compliance with
the mandates of the  Federal  Water  Pollution  Control  Act
Amendments of 1972, are summarized in Tables II-1 and II-2.

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                                 Table II-2
                                                                         #
       SUMMARY OF EFFLUENT LIMITATIONS GUIDELINES AND STANDARDS FOR HEAT
  All no discharge limitations allow for blowdown to be discharged at a temperature not
  to exceed the cold-side temperature, except where a unit has existing closed-cycle
  cooling blowdown may exceed the cold-side temperature. All limitations for existing
  units to be achieved by no later than July 1,  1981, except where system reliability
  would be seriously impacted the compliance date can be extended to no later than July 1, 1983.
EXISTING GENERATING UNITS

   Capacity 500 Mw and greater
      Placed into service prior to January 1, 1970
      Placed into service January 1, 1970 or thereafter
   Capacity 25 Mw to 499 MW
      Placed into service prior to January 1, 1974
      Placed into service January 1, 1974 or thereafter

   Capacity less than 25 Mw
NO LIMITATION,
NO DISCHARGE


NO LIMITATION,
NO DISCHARGE

NO LIMITATION
    * Note: Exceptions prescribed on a case-by-case basis for units in systems of
            less than 150 Mw capacity, units with cooling ponds or cooling lakes,
            units without sufficient land available, units with blowdown TDS 30,000
            mg/1 or greater and neighboring land within 500 ft of cooling tower(s),
            and units where FAA finds a hazard to commercial aviation would exist.
NEW SOURCES
NO DISCHARGE
 # Note: No effluent limitations on heat from sources other than main condenser
         cooling water

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                        SECTION III

                        INTRODUCTION
General Background

The involvement of the Federal Government in water pollution
control  dates back to 1948, when Congress enacted the first
comprehensive measure aimed specifically  at  this  problem.
At  that  time the Surgeon General, through the U. S. Public
Health Service, was authorized to assist states  in  various
ways  to  attack  the  problem.  The emergence of a national
water pollution control program came about with  the  enact-
ment  of the Water Pollution Control Act of 1956  (Public Law
84-660)  which to this date remains the basic  law  governing
water  pollution.  This law set up the basic system of tech-
nical and financial assistance to states and municipalities,
and established enforcement procedures by which the  Federal
Government could initiate legal steps against polluters.

The  present  program dates back to the Water Quality Act of
1965 and the Clean Water Restoration Act of 1966.  Under the
1965 Act, the states were required to  adopt  water  quality
standards  for  interstate  waters,  and  to  submit  to the
Federal Government, for approval,  plans  to  implement  and
enforce  these  standards.   The 1966 Act authorized massive
Federal  participation  in  the   construction   of   sewage
treatment  plants.   An  amendment, the Water Quality Act of
1970,  extended  Federal  activities  into  such  areas   as
pollution by oil, hazardous substances, sewage from vessels,
and mine drainage.

Originally,  pollution control activities were the responsi-
bility of the U. S. Public Health  Service.   In  1961,  the
Federal  water  Pollution Control Administration  (FWPCA) was
created in the Department of Health, Education, and Welfare,
and in 1966, the FWPCA was transferred to the Department  of
the  Interior.   The  name  was changed in early 1970 to the
Federal Water Quality Administration and in  December  1970,
the Environmental Protection Agency  (EPA) was created by Ex-
ecutive  Order  as an independent agency outside the Depart-
ment of the Interior.  Also  by  Executive  Order  11574  on
December  23,  1970,  President Richard M. Nixon established
the Permit  Program,  requiring  all  industries  to  obtain
permits for the discharge of wastes into navigable waters or
their tributaries under the provisions of the 1899 River and
Harbor  Act   (Refuse  Act).   The permit program immediately
became involved in legal problems resulting eventually in  a
ruling  by  a  Federal  court  that  effectively stopped the

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issuance of a significant number  of  permits,  but  it  did
result  in  the filing with EPA, through the U.S. Army Corps
of Engineers, of applications  for  permits  which,  without
doubt,  represent  the irost complete inventory of industrial
waste discharges yet compiled.  The  granting  of  a  permit
under  the  Refuse  Act was dependent on the discharge being
able to meet applicable water quality  standards.   Although
EPA  could  not  specify  methods  of  treatment, they could
require minimum effluent  levels  necessary  to  meet  water
quality standards.

The  Federal  Water Pollution Control Act Amendments of 1972
(the "Act") made a number  of  fundamental  changes  in  the
approach to achieving clean water.  One of the most signifi-
cant  changes  was from a reliance on water quantity related
effluent  limitations  to  a  direct  control  of  effluents
through   the  establishment  of  technology-based  effluent
limitations to form an additional basis, as a  minimum,  for
issuance of discharge permits.  The permit program under the
1899  Refuse  Act was placed under full control of EPA, with
much of the responsibility to be delegated to the States.

Purpose and Authority

The  Act  requires  the  EPA  to  establish  guidelines  for
technology-based effluent limitations which must be achieved
by  point sources of discharges into the navigable waters of
the United States.  Section 301(b) of the Act  requires  the
achievement  by  not  later  than  July 1, 1977, of effluent
limitations for point sources,  other  than  publicly  owned
treatment  works,  which are based on the application of the
best practicable control technology currently  available  as
defined  by  the Administrator pursuant to Section 304(b) of
the Act.  Section 301 (b) also requires  the  achievement  by
not  later  than  July  1, 1983, of effluent limitations for
point sources, other than publicly  owned  treatment  works,
which  are  based  on  the application of the best available
technology economically  achievable  which  will  result  in
reasonable  further  progress  toward  the  national goal of
eliminating the discharge of all pollutants,  as  determined
in  accordance  with regulations issued by the Administrator
pursuant to Section 304(b) of the Act.  Section 306  of  the
Act  requires  the  achievement  by new sources of a Federal
standard of performance providing for  the  control  of  the
discharge  of  pollutants which reflects the greatest degree
of effluent reduction which the Administrator determines  to
be  achievable through the application of the best available
demonstrated  control   technology,   processes,   operating
methods,    or    other   alternatives,   including,   where
practicable,  a  standard   permitting   no   discharge   of

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pollutants.  Section 304(b)  of the Act requires the Adminis-
trator to publish within one year of enactment of  the  Act,
regulations  providing  guidelines  for effluent limitations
setting forth the degree of  effluent  reduction  attainable
through  the  application  of  the  best practicable control
technology currently available and the  degree  of  effluent
reduction  attainable  through  the  application of the best
control measures and practices achievable  including  treat-
ment   techniques,   process   and   procedure  innovations,
operation methods and other alternatives.   The  regulations
proposed  herein  set forth effluent limitations, guidelines
pursuant to Section SOU (b) of the Act for the steam electric
powerplant industry.

Section 306 of the Act requires  the  Administrator,  within
one  year  after a category of sources is included in a list
published pursuant to Section 306 (b) (1) (A) of the Act,  to
propose   regulations   establishing  Federal  standards  of
performances for new sources within  such  categories.   The
Administrator  published  in the Federal Register of January
16, 1973 (38 F.R. 1624), a list  of  27  source  categories.
Publication  of  the  list  constituted  announcement of the
Administrator's intention  of  establishing,  under  Section
306,  standards  of  performance  applicable  to new sources
within the steam  electric  powerplants  industry  category,
which  was  included  within  the list published January 16,
1973.  See Table  III-1  for  a  summary  of  the  principal
statutory considerations.

Section  304 (c)  of  the  Act  requires the Administrator to
issue informaton on the processes, procedures  or  operating
methods  which result in the elimination or reduction in the
discharge  of   pollutants   to   iirplement   standards   of
performance  under section 306 of the Act.   Such information
is to include technical and other data, including costs,  as
are  available  on  alternative  methods  of  elimination or
reduction of the discharge of pollutants.

Section 316 (a) of the Act provides that whenever  the  owner
or  operator  of  any  point  source  can demonstrate to the
satisfaction of the Administrator that any effluent  limita-
tion  proposed  for  the control of the thermal component of
any discharge will require more stringent  control  measures
than  are necessary to assure the protection and propagation
of a balanced, indigenous population of shellfish, fish  and
wildlife  in  and  on  the  body  of  water  into  which the
discharge is to be made the Administrator  may  impose  less
stringent limitations with respect to the thermal component,
(taking   into  account  the  interaction  of  such  thermal
component  with  other  pollutants)  that  will  assure  the

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                                                           Table  III-l
                                                     PRINCIPAL STATUTORY CONSIDERATIONS
STATUTORY
BASIS' General Description Process Changes Cost
Process
Employed, Age
& Size of Equip-
ment & Facilities.
Non Water Quality
Environmental
Impact & Energy
Control Technology
Currently Available

304(b)(l)(A)

[Existing Sources]
1. Achieve by 1977
2. Generally average
of best existing per-
formance; high con'
fidence in engineering
viability.
3. Where treatment
uniformly inadequate
a higher degree of
treatment may be
required if practic-
able [compare exist-
ing treatment of
similar wastes].	
Normally does not
emphasize in-process
controls, except
where presently
commonly practiced.
Balancing of
total cost of
treatment against
effluent reduc-
tion benefits.
 Age,  size &
 process  employed
 may require
 variations in
 discharge limits
 (taking  into account
 compatibility of costs
 and process technology)
Assess impact of
alternative controls
on air, solid waste,
noise, radiation
and energy require-
ments.
Best Available
Technology
Economically
Achievable

304 (b> (1KB)

[Existing Sources]
1. Achieve by 1983.
2. Generally best
existing performance
but may include tech-
nology which is capable
of being designed,
though not yet in
place; further
development work could
be required,
Emphasizes both
in-process and end-
of-process control.
Costs considered
relative to broad
test of reason?  •
ableness.
Age, size &
process employed
may require
variations in
discharge limits
(taking into account
compatibility of costs
and process technology)
Assess impact of
alternative controls
on air, solid waste
noise, radiation and
energy requirements.
Standards of
Performance Best
Available
Demonstrated Con*
trol Technology

306
[New Sources]
1. Achieved by sources
for which "construc-
tion" commences after
proposal of regula-
tions.
2. Generally same
considerations as  for  1983;
more critical analysis
of present availability.
Emphasizes process
changes.
Cost considered
relative to broad
test of reasonable-
ness.
                                               N/A
                          Assess impact of
                          alternative controls
                          on air, solid waste,
                          noise, radiation
                          and energy require-
                          ments.

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protection   and   propagation  of  a  balanced,  indigenous
population of shellfish, fish, and wildlife in and  on  that
body of water.

The  Act  defines  a  new  source  to  mean  any source, the
construction of which is commenced after the publication  of
proposed  regulations prescribing a standard of performance.
Construction means any placement, assembly, or  installation
of    facilities   or   equipment   (including   contractual
obligations to purchase such facilities or equipment) at the
premises  where  such  equipment  will  be  used,  including
preparation work at such premises.

Scope of Work and Technical Approach

This document was developed, specifically, for effluent dis-
charge   from   steam  electric  powerplants  covered  under
Standard Industrial Classification (SIC) 1972 Industry  Nos.
4911  and  4931,  relating to liquid discharges to navigable
waters of the United States.

Industry No. 4911 encompasses establishments engaged in  the
generation,  transmission  and/or   distribution of electric
energy   for   sale.    Industry   No.   4931    encompasses
establishments   primarily  engaged  in  providing  electric
service in combination with other  services,  with  electric
services  as  the  major part though less than 95 percent of
the total.  The S.I.C. Manual (1972)  recommends  that,  when
available,  the  value  of  receipts  or revenues be used in
assigning industry codes for transportation,  communication,
electric, gas, and sanitary services.

The study was limited to powerplants comprising the electric
utility   industry,  and  did  not  include  steam  electric
powerplants in industrial, commercial or  other  facilities.
Electric  generating  facilities  other than steam electric,
such as combustion gas turbines, diesel  engines,  etc.  are
included   to   the  extent  that  power  generated  by  the
establishment  in  question  is  primarily   through   steam
electric processes.

This  report  covers  effluents  from both fossil-fueled and
nuclear plants and  excludes  the  radiological  aspects  of
effluents.

The  Act  requires  that in developing effluent limitations,
guidelines  and  standards  of  performance  for   a   given
industry,  certain  factors  must be considered, such as the
total cost of the application of technology in  relation  to
the  effluent  reduction  benefits  to  be  achieved, age of
                            11

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equipment and facilities,  processes  employed,  engineering
aspects  of  the  application  of  various  types of control
techniques, process changes, non-water quality environmental
impact (including energy requirements)  and  other  factors.
For  steam  electric powerplants, formal segmentation of the
industry based on all the factors mentioned in the  Act  has
been  found  to  be  inapplicable.   However,  the two basic
aspects of the effluents produced by the industry,  chemical
aspects  and  thermal  aspects,  were  found to involve such
divergent considerations that a  basic  distinction  between
guidelines  for  chemical  wastes and thermal discharges was
determined to be most useful in achieving the objectives  of
the    Act.    Accordingly,   this   report   covers   waste
categorization,  control  and   treatment   technology   and
recommendations  for  effluent  limitations for chemical and
other nonthermal aspects of waste discharge in  Part  A  and
similar subjects for thermal aspects of discharges in Part B
of this report considering the factors cited in the Act.

Section  502 (6)  of  the  Act  defines the term pollutant in
relation to the discharge into water of  certain  materials,
substances   and   other  constituents  of  discharge.   The
inclusion of heat in the list cf  pollutants  indicates  the
clear  intention  on  the  part  of  Congress  to  have this
pollutant included in the same manner as other pollutants in
the establishment  of  effluent  limitation  guidelines  and
standards  of  performance.   Other  recognition  of heat in
special provisions of the Act is in Sections 104 (t) and 316.

Section 104 (t) requires the EPA Administrator in cooperation
with other agencies and organizations to conduct  continuing
comprehensive  studies of the effects and methods of control
of thermal discharges.  The studies  are  to  include  cost-
effectiveness  analysis and total impact on the environment.
The Act states that they are to be used by EPA  in  carrying
out   Section   316  of  the  Act,  and  by  the  States  in
establishing water quality standards.  However it  does  not
indicate that the studies are to be utilized in establishing
effluent limitation guidelines and standards of performance.
Section  316 (a)  does provide for individual variances to be
granted from effluent  guidelines  for  thermal  discharges,
where  such  a  variance  will  assure  the  protection  and
propogation  of  a  balanced,   indigenous   population   of
shellfish, fish and wildlife in and on that body of water.

Consequently,  the  Act  requires  effluent  guidelines  and
standards of performance for heat to  be  developed  in  the
same  manner  as  for  other pollutants, but also allows for
individual relief from the guidelines  and  standards  under
Section  316.  In this context, this report only contains an
                           12

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evaluation of control and treatment technology  for  thermal
discharges  which  reduces or eliminates the amounts of heat
discharged.  Consideration  of  mixing  zone  technology  is
therefore not included, since mixing zones do not reduce the
effluent  heat  but rely in part upon the dilution effect of
the receiving water to decrease the overall receiving  water
temperatures   to   meet  applicable  limitations  based  on
environmental criteria.  Therefore they do not qualify as  a
control  or  treatment  technology  for the establishment of
technology-based   effluent   limitations   guidelines    or
standards of performance.

The  effluent  limitations   and  standards  of  performance
recommended herein  have  been  developed  from  a  detailed
review of current practices in the steam electric powerplant
industry.   A  critical  examination  was  made of treatment
methods now in use in the industry and methods used in other
industries to achieve solutions to problems similar to those
encountered in steam electric powerplants.  As part  of  the
review  of  current  practices,  applications  for discharge
permits filed in accordance with other provisions of the Act
were examined.  There is also a  volumuous  literature  base
and  on-going reseach development and demonstration programs
in this and related technical areas.  Also as part  of  this
effort  visits  were  made  to  35 plants, with at least one
plant visit to each of the ten EPA regions.  Six plants were
visited outside the U.S.  Sampling programs  were  conducted
at  plants  where  it  was  felt that sufficient information
could be obtained to  document   treatment  practices.   The
plants visited are listed below:
    Beznau, Dottingen,Switzerland
    B.F. Cleary, Taunton, Massachusetts
    Big Brown, Fairfield, Texas
    Brayton Point, Somerset, Massachusetts
    Canal, Sandwich, Massachusetts
    Centralia, Centralia, Washington
    Cherokee, Denver, Colorado
    Chesterfield, Chester, Virginia
    Dresden, Morris, Illinois
    Dunkirk, Dunkirk, New York
    Fremont No. 1, Fremont, Nebraska
    Fremont No. 2, Fremont, Nebraska
    Fort Calhoun, Fort Calhoun, Nebraska
    Greene county, Demopolis, Alabama
    Holtwood, Holtwood, Pennsylvania
    Keystone, Shelocta, Pennsylvania
    Lichterfelde, West Berlin
    Marshall, Terrell, North Carolina
                           13

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    Milliken, Ludlowville, New York
    Mohave, Davis Dam, Nevada
    Morgantown, Newburg, Maryland
    North Omaha, Omaha, Nebraska
    Palisades, Benton Harbor, Michigan
    Paradise, Drakesboro, Kentucky
    Pittsburg, Pittsburg, California
    Preussag, Ibbenburen, West Germany
    Quad Cities, Cordova, Illinois
    Rancho Seco, Rancho Seco, California
    Roseten, Roseton, New York
    Rugeley, Town of Rugeley, England
    Sanford, Sanford, Florida
    Turkey Point, Florida City, Florida
    Valmont, Valmont, Colorado
    Volkswagenwerk, Wolfsburg, West Germany
    Westfalen, Schmehausen, west Germany
    Will County, Joliet, Illinois

The  economic analyses contained in this report pertain only
to costs related to control and treatment technology for the
reduction and elimination of  the  discharge  of  pollutants
from  steam  electric  powerplants.   Benefits  derived from
associated costs are simply the reduction and/or elimination
of  pollutant  discharges.   Cost-benefit   analysis   which
consider   environmental   effects,   benefits  to  society,
economic impact, etc. are beyond the scope of this report.

In arriving  at  recommendations  fcr  effluent  limitations
guidelines  and  standards of performance, extensive use has
been made of prior studies in this area made  for  EPA,  in-
house  information  developed by EPA,  information developed
by industry sources,  and  comments  submitted  by  numerous
Federal and State agencies, industrial and other groups, and
others.

Industry Description

Steam  electric powerplants are the production facilities of
the electric power industry.  The industry also provides for
the transmission and distribution of electric  energy.   The
industry  is  made  up  of  two basically distinct ownership
categories,  investor-owned  and  publicly-owned,  with  the
latter  further  divided  into Federal agencies, non-Federal
agencies, and cooperatives.  About two-thirds  of  the  3400
systems  in  the United States perform only the distribution
function, but many perform all three  functions,  production
(generally  referred  to  as  generation), transmission, and
distribution.  In general, the larger systems are vertically
integrated,  while  the  smaller  systems,  largely  in  the
                           14

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municipal and cooperative categories, rely on firm purchases
to  meet  all  or  part  of their requirements.  Many of the
systems  are  interconnected,  and  can,   under   emergency
conditions, obtain power from other systems.

Historically, the industry started around 1880 with the con-
struction of Edison's steam electric plant in New York City.
For  the  next  sixty  years,  growth  was  continuous,  but
unspectacular, due to the fairly limited demand  for  power.
However,  since  1940  the  annual  per capita production of
electric energy has grown at a rate of about six percent per
year, and  the  total  energy  consumption  by  about  seven
percent.   In 1970, there were about one thousand generating
systems in the United States.  These systems had a  combined
generating  capacity  of 340,000 megawatts  (Mw) and produced
1,530,000,000 megawatt hours (Mwh) of energy.   A  breakdown
of  the  capacity  and production by ownership categories is
given in Table III-2.

The industry produces, transmits and  distributes  a  single
product, electric energy.  The product is distinguished from
other  products of the American industry by the fact that it
cannot be economically stored, and that the industry must be
ready to produce at  any  give  time  all  the  product  the
consumer desires to utilize.  While some industrial power is
sold  on a so-called "interruptible" basis, the total amount
sold on this basis is insignificant compared to the  overall
power  consumption.  The ability of the industry to meet any
instantaneous demand is the criterium for  what  constitutes
satisfactory  performance  in the industry and is the single
most significant factor in determining the need for new gen-
erating facilities.

Other special considerations involved in a discussion of the
industry relate to its role as a public utility, a monopoly,
and a regulated industry.  As a public  utility,  its  major
objective  is  to  provide a public service.  It must supply
its product to all customers  within  its  assigned  service
area,  but  it cannot discriminate between customers, and it
must supply its product to  all  customers  within  a  given
class  at  equal  cost.   As  a  monopoly,  the  industry is
generally assigned a service area, but within that  area  is
exempt  from competition except perhaps for competition with
other sources of  energy,  particularly  in  the  industrial
area.   However,  in  return for the granting of a monopoly,
the industry is required to furnish service.  Thus it cannot
cease to service a certain area when such service appears to
be unprofitable.  Finally, in view  of  its  position  as  a
public  utility  and a monopoly, both the quality of service
it must provide and the rates it may charge for its  service
                            15

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                                    Table III-2
                              SUMMARY DESCRIPTION
                      ELECTRICAL POWER  GENERATING INDUSTRY (YEAR 1970)

                  Number  of plants  (stations).	approx.  1000
                  Number  of generating units.	approx.  3000
   OWNERSHIP
 Investor
 Federal
 Public (non-Fed)
 Cooperative	
NUMBER OF SYSTEMS*
       250
         2
       700
        65
  GENERATING CAPACITY, Mw*
      265,000
       40,000
       35,000
 	5,000	
GENERATION, 10 Mwh*
     1,180
       190
       140
        22
   CUSTOMERS
  Residential
  Commercial
  Industrial
  Other
    NUMBER
 55,000,000
  8,000,000
    400,000
ENERGY SOLD, Mwh
  450,000,000
  325,000,000
  575,000,000
   60,000,000
PROJECTED GROWTH
     1970
     1980
     1990
     INSTALLED CAPACITY, Mw
          266,000
          540,000
        1.057.000	
   FUEL USED
     Coal
     Natural Gas
     Oil
     Nuclear	
     PERCENT HEAT INPUT
           54
           29
           15
    	2	
    COST (YEAR 1968)
      Production
      To Customers
            rnills/^
               7.7
              15.4
   * Note: Includes some hydroelectric and  internal  combustion.

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are regulated by both State and Federal regulatory agencies.
Since  the  rates  it is allowed to charge are a function of
the cost of providing service, any prudent costs imposed  on
the  industry  by  regulatory  agencies  will  eventually be
passed on  to  the  electricity  consumer.   And  since  the
consumer,  particularly at the retail residential level, has
very few options to the use of electricity, the relationship
between costs and consumption is generally considered to  be
"inelastic"  in the short time, that is, an increase in cost
has little effect on the level of consumption.

The use of electric energy can be divided into  three  major
categories:  industrial,  residential  and  commercial.   In
1965,  industrial  use  accounted  for  41%  of  all  energy
generated.  Residential use accounted for 24% and commercial
use  for  18*.  Another 17% of the energy generated was used
by miscellaneous users for auxiliary operations  within  the
industry  or  lost in transmissions.  Studies by the Federal
Power Commission  (FPC) indicate no change in this basic  use
pattern over the next two decades.

On  the other hand, the total amount of electric energy that
will be used is expected to increase significantly over  the
next two decades.  Again, based on studies by the FPC, it is
believed that the required generating capacity will increase
from  340,000 Mw in 1970 to 665,000 Mw in 1980 and 1,260,000
Mw in 1990.  The industry's 1970 generating facilities would
therefore have to  be  almost  doubled  by  1980  and  again
doubled by 1990.

At  the  present time, steam electric powerplants, including
both fossil-fueled and nuclear-fueled  plants,  account  for
about  79% of total generating capacity and 83% of the total
power generated.  The remainder is accounted for  by  hydro-
electric  generation,  both  of the once-through and pumped-
storage types, and by direct combustion-generation processes
such as gas turbines and diesel  engine  driven  generators.
Table  III-3,  taken  from  reports  of  the  FPC, shows the
projected growth of generating capacity over  the  next  two
decades.

Four  basic  fuels  are  used in steam electric powerplants,
three fossil fuels-coal, natural gas and oil - and  uranium,
presently  the  basic  fuel  of  nuclear power.  A potential
fuel, reclaimed refuse, is being burned at one  experimental
facility,  but  is  not likely to have a major impact on the
industry within the foreseeable future.  Table III-U,  again
from  FPC  reports, shows the projected distribution of fuel
use for steam electric power generation  for  the  next  two
decades.
                          17

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                                                        TABLE  III-  3
                              PROJECTED GROWTH OF  UTILITY  ELECTRIC  GENERATING  CAPACITY
                                          (Figures in  thousands  of  megawatts)
oo
Type of Plant
Fossil Steam
Nuclear Steam
Subtotal Steam
Hydroelectric-
conventional
Hydroelectric-
pumped storage
Gas-Turbine and Diesel
TOTALS
1970 (actual)
% of
Capacity Total
260 76
6 2
266 78
52 15
4 1
19 6
341 100
1980
% of
Capacity Total
393 59
147 22
540 81
68 10
27 4
31 5
666 100
1990
% of
Capacity Total
557 44
500 40
1,057 84
82 6
71 6
51 4
1,261 100
               Notes:   (1)    These projections are keyed  to  the electrical energy demand projections made
                              by Regional Advisory Committee  studies  carried out  in the 1966-1969 period.
                        (2)    The projections are premised on an average  gross reserve margin of 20%.
                        (3)    Since different types of  plants are operated at different capacity factors,
                              this capacity breakdown is not  directly representative of share of kilowatt-hours
                              production.  For example, since nuclear plants are  customarily used in base-load
                              service and therefore operate at comparatively high capacity factors,  nuclear
                              power's contribution to total electricity production would be higher than its
                              capacity share.

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            Table  III-4
FPC PROJECTION  OF  FUEL USE IN STEAM ELECTRIC
            POWERPIANTS
Fuel
Coal
Natural Gas
Fuel Oil
Nuclear
1970
54%
29
15
2
1980
41%
14
14
31
1990
30%
8
9
53

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Table III-5 shows the projected annual fuel requirements for
steam  electric  powerplants over the next two decades.  See
also Figure  III-1  for  a  graphical  presentation  of  the
projection,  by the Joint Committee on Atomic Energy, of the
U.S. energy flow pattern for 1980.  Although their share  of
the total fuel use is declining, the actual use of all three
fossil  fuels  is  projected  to continue to increase.  Most
significant is the fact that  utility  consumption  of  coal
will more than double although coal's share of the total use
will  decrease from 5H* to 31%.  These projections assume no
major slippages in the construction  of  nuclear  generating
plants.   Should  such  slippages occur, it is possible that
coal will be called upon to assume an even greater  role  in
meeting the nation's energy needs.

Coal  is  the most abundant of the fossil fuels.  Nationwide
it  is  estimated  that  proven  recoverable  reserves   are
sufficient  to  supply  our  needs  for  the next 200 to 300
years.  A problem with coal is that it  varies  in  chemical
properties and its geographic distribution does not coincide
with  the geographic distribution of the demand for electric
energy.  A primary concern is  the  sulfur  content  of  the
coal.   Most  of  the  Eastern  coal  is  too high in sulfur
content to meet the increasingly stringent limits on  sulfur
dioxide in stack gases.

Sulfur  dioxide  removal  systems  are  being  employed at a
number of powerplants.  All indications are that limitations
on sulfur  dioxide  emissions  will  substantially  increase
production  costs in coal-burning powerplants.  In the West,
there are large deposits of low sulfur coal,  but  here  the
cost  of  either  shipping the coal or transmitting electric
energy  are  substantial.   The  possibilities  of   further
environmental   restrictions   as   much   as   the   actual
environmental regulations now in force has possibly resulted
in the conversion of a large number of coal  burning  plants
to  other  forms of fossil fuel, and the construction of new
generating  facilities  using   less   abundant   but   more
environmentally acceptable fuels.

Both  natural  gas and low sulfur residual oils are in short
supply.  The natural gas situation was initially felt to  be
more   critical   and  some  generating  plants  were  being
converted from natural  gas  to  fuel  oil.   The  1970  FPC
projections  indicated  that  natural  gas utilization would
remain fairly constant and that the use of  fuel  oil  would
increase  at approximately the same rate as the use of coal.
All of these projections were based on the  assumption  that
there would be no additional governmental actions regulating
the  utilization  of  fuels and that nothing would happen to
                          20

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                   Table III- 5
FPC PROJECTED ANNUAL FUEL REQUIREMENTS FOR
     STEAM ELECTRIC POWERPLANTS
Fuel
Coal
Natural Gas
Fuel Oil
u^o^
3 8

Measure
10 tons
12
10 cubic feet
10 barrels
10 tons to diffusion
plants without re-
cycle of plutoniutn
1970
332
3.6
331
7.5


1980
500
3.8
640
41


1990
500
3.8
800
127



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                                                   Figure   III-l


                                    PROJECTED TOTAL  U0S0  ENERGY FLOW PATTERN  (1980)
234
      HYDROELECTRIC
       GEOTHERMAL
      NUCLEAR
      GAS

      (IMPORTS)
      GAS

      (DOMESTIC)
ro
ro
      COAL
      OIL

      (IMPORTS)
      OIL

      (DOMESTIC)
                                                                 (UNITS: MILLION BBLS/DAY OIL EQUIVALENT)

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affect our present heavy reliance  on  foreign  sources  for
fuel   oil.   Subsequently,  the  fuel  oil  problem  became
critical, projections were altered and certain  plants  were
considered for reconversion to coal.

Finally, the projected growth of nuclear generating capacity
is dependent in the short run on the discovery of additional
deposits   of  low-cost  uranium  and  the  construction  of
additional ore processing facilities.  In the long  run,  it
is  dependent  on  the  successful  development  and  use of
breeder reactor systems.  The United States may have a full-
scale breeder plant in operation in the 1980's.

In summary, this report deals with the setting  of  effluent
guidelines for an industry with many complex aspects.  It is
a  public  utility and therefore is regulated both as to the
quality of its service and the rates it can charge  for  the
service.   While  regulation limits the rates it can charge,
it also insures that  any  prudently  increased  costs  will
eventually  be passed on to the retail customer.  Except for
some competition in the industrial use of electricity, there
is little competition for the use of its  product.   On  the
other  hand,  the  industry  itself  has little mobility.  A
powerplant generally cannot be moved and a  generating  unit
can  be  shut  down  only  when  an equivalent unit has been
provided.  Since its product cannot be stored  and  must  be
produced  to meet a fluctuating demand, much of its capacity
is used only  part  time.   With  suitable  sites  near  the
centers  of demand largely used up, it has to go further and
further from its demand to  obtain  satisfactory  generating
sites,  and  even  then  is often encountering pressure from
environmental groups opposed to the construction of the  new
facilities.   In addition, because of planning, construction
and design problems  with  regard  to  a  number  of  plants
already  sited,  delays  are  resulting for some major power
plant  installations.   Generally,  the  slippage   in   the
schedules  for  new powerplants is requiring the industry to
continue to operate some of the older, less  efficient,  and
perhaps     less    environmentally    acceptable    plants.
Amplification of the "energy crisis" has evoked considerable
attention, constraints, and changes  in  the  industry.   In
addition  to  some  shifts  in  fuel and fuel costs, reduced
projections for the  demand  for  electricity  and  possibly
other  factors  have  caused  at  least  one major system to
announce a slowdown in planned expansion  resulting  in  the
delay in construction of  generating units.

The  setting of effluent standards for steam electric power-
plants has therefore involved  a  large  number  of  complex
factors,  many  of  which  do  not  apply  to a conventional
                          23

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manufacturing   industry   producing    a    non-perishable,
transportable product in a competitive market.

Process Description

The  "production"  of  electrical energy always involves the
utilization and conversion of seme ether form of energy.

The  three  most  important  sources  of  energy  which  are
converted to electric energy are the gravitational potential
energy of water, the atomic energy of nuclear fuels, and the
chemical  energy  of fossil fuels.  The utilization of water
power involves the transformation of one form of  mechanical
energy  into  another  prior  to  conversion  to  electrical
energy, and can be accomplished at greater than  90  percent
of  theoretical  efficiency.  Therefore, hydroelectric power
generation involves only a  minimal  amount  of  waste  heat
production  due  to  conversion inefficiencies.  Present day
methods of utilizing the energy  of  fossil  fuels,  on  the
other  hand,  are based on a combustion process, followed by
steam generation to convert the heat first  into  mechanical
energy  and  then  to  convert  the  mechanical  energy into
electrical energy.  Nuclear processes as generally  utilized
also  depend  on  the conversion of thermal energy  (heat) to
mechanical energy via a steam cycle.  Although  progress  in
powerplant  development  has been rapid, a large part of the
energy released by the fuel as heat at  a  high  temperature
level,  in  even the most efficient plants, is not converted
to useful electrical energy, but is exhausted as heat  at  a
lower  temperature level.  This is due to the limitations of
the second law of thermodynamics  which  can  be  stated  as
follows:  A  reversible  heat - engine can generate work from
high-temperature heat only at the  expense  of  rejecting  a
part  of  this  heat  to a lower-temperature reservoir.  The
fraction of the high-temperature heat which is converted  to
work  is (T-t)/T, where T is the absolute temperature of the
high-temperature  heat  source  and  t   is   the   absolute
temperature of the lower-temperature heat sink.

Where  a  water-steam cycle is used to convert heat to work,
the maximum theoretical efficiency that can be  obtained  is
limited  by  the  temperatures  at  which  the  heat  can be
absorbed by the steam and discarded to the environment.  The
upper temperature is limited by the temperature of the  fuel
bed  and  the  structural  strength and other aspects of the
boiler.   The  lower  temperature  is  ideally  the  ambient
temperature  of  the  environment,  although  for  practical
purposes the  reject  temperature  must  be  set  by  design
significantly   above   the   highest   anticipated  ambient
temperature.  Within these temperatures it can be shown that
                         24

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the conversion of heat into any  other  form  of  energy  is
limited  to  efficiencies  of about 40 percent regardless of
any improvements to the present day machines employed.   The
limited  boiler  temperature  utilized  by present day light
water nuclear powerplants is the major reason of  the  lower
efficiency of these plants compared to fossil-fueled plants.
For any steam electric power generation scheme, therefore, a
minimum  of  about 60 percent of the energy contained in the
fuel must be rejected to the environment as waste heat.  The
extent  to  which  existing  and   future   steam   electric
powerplants   approach   this   theoretical  limit  will  be
discussed later in this report, as will alternate methods of
converting fuel energy  to  electric  energy  which  do  not
employ  a steam cycle and therefore are not limited to steam
cycle efficiencies.

Fossil-fueled steam electric  powerplants  produce  electric
energy  in  a  four  stage  process.   The  first  operation
consists of the burning of the fuel  in  a  boiler  and  the
conversion  of  water  into steam by the heat of combustion.
The second operation  consists  of  the  conversion  of  the
high-temperature  high-pressure steam into mechanical energy
in a steam  turbine.   The  steam  leaving  the  turbine  is
condensed to water, transferring heat to the cooling medium,
which  is  normally  water.   The turbine output is conveyed
mechanically to a generator, which converts  the  mechanical
energy  into  electrical  energy.   The  condensed  steam is
reintroduced into the boiler to complete the cycle.

Nuclear powerplants utilize a similar cycle except that  the
source  of  heat  is atomic interactions due to nuclear fuel
rather than combustion of fossil fuel.  Water serves as both
moderator and coolant  as  it  passes  through  the  nuclear
reactor  core.   In  a pressurized water reactor, the heated
water then passes through a separate heat  exchanger,  where
steam  is produced on the secondary side.  This steam, which
contains no radioactive materials, drives the turb' ie.  In a
boiling water reactor, steam is generated  directl,  in  the
reactor  core  and  is  then  piped directly to the turbine.
This arrangement results in some radioactivity in the  steam
and  therefore requires some shielding of the turbine.  Long
term fuel performance and thermal efficiencies  are    .milar
for the two types of nuclear systems.

The theoretical water-^steam cycle employed in steam electric
powerplants is known as the Rankine cycle.  Actual cycles in
powerplants  only  approach  the  performance of the Rankine
cycle because of practical considerations.  Thus,  the  heat
absorption  does  not  occur  at  constant  temperature, but
consists of heating of the  liquid  to  the  boiling  point.
                            25

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converting  of  liquid  to  vapor  and superheating (heating
above the saturation  equilibrium  temperature)   the  steam.
Superheating  is necessary to prevent excess condensation in
the turbines and results in an increase in cycle efficiency.
Reheating, the raising of the temperature  above  saturation
of   the   partially  expanded  steam,  is.  used  to  obtain
improvements in  efficiency  and  again  to  prevent  excess
condensation.   Preheating,  bringing  of condensate to near
boiling temperatures with waste heat, is also used for  this
purpose.   Condensers  cannot  be  designed  to  operate  at
theoretically  optimum  values  because  it  would   require
infinitely  large  equipment.  All of these divergences from
the optimum  theoretical  conditions  cause  a  decrease  in
efficiency  and  an  increase in the amount of heat rejected
per unit of production.  As a result,  only  a  few  of  the
larger  and  newer  plants  approach  even  the efficiencies
possible under the ideal Rankine cycle.  Also as a result of
second law limitations, modifications of the steam cycle  of
an  existing  plant  are not likely to result in significant
reductions in heat rejection.

Alternate Processes

Alternate processes for generating electric  energy  can  be
divided   into  three  distinct  groups.   The  first  group
includes those processes that are presently  being  used  to
generate  significant  amounts  of  electrical energy.  This
group includes hydroelectric  power  generation,  combustion
gas turbines, and diesel engines.  The second group includes
processes  that  seek to improve on the steam electric cycle
by utilizing new fuels or new energy technology.  This group
includes liquid  metal  fast  breeder  reactors,  geothermal
generation,  utilization  of solar energy, and various forms
of combining cycles to obtain  greater  thermal  efficiency.
The  last  group  includes  those systems, also mostly still
under development,  that  seek  to  eliminate  the  inherent
limitations  of  the conventional Rankine cycle by providing
for some alternative type of  conversion of chemical  energy
into     electrical    energy.     This    group    includes
magnetonydrodynamics, electrogasdynamics and fuel cells.

Presently Available Alternate Processes

Hydroelectric Power

Hydroelectric developments harness  the  energy  of  falling
water  to  produce  electric  power,  and  have  a number of
distinct advantages over steam electric  plants.   Operation
and  maintenance  costs  are  generally lower.  Although the
initial capital cost may be higher,  hydroelectric  develop-
                            26

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ments  have longer life and lower rates of depreciation, and
capital charges may therefore be less.  The cost of fuel  is
not  an  item  of  operating  cost.   Both  availability and
reliability are  greater  than  for  steam  electric  units.
Hydroelectric  plants  are  well  suited for rapid start and
rapid changes in power output and are therefore particularly
well  adapted  to  serve   peak   loads.    Best   of   all,
hydroelectric  plants do not consume natural fuel resources,
produce no emissions that affect air quality  and  discharge
no significant amounts of heat to receiving waters.

Unfortunately,  the  availability  of hydroelectric power is
limited  to  locations  where   nature   has   created   the
opportunity  by providing both the stream and the difference
in elevation  to  make  the  energy  extractable.   In  many
instances  this  means generation far away from load centers
with long transmission lines required to bring the energy to
its point  of  use.   At  the  present  time,  hydroelectric
generation  in  the  United States is a major factor only in
the Far West, in New York State, and in some  areas  of  the
Appalachian  Region.  Total hydroelectric capacity installed
at the end of 1970 amounted to 52,300 Mw, amounting to about
15% of the total installed U. S.  generating  capacity.   In
spite  of a projected growth of about 30,000 Mw by 1990, the
share of once-through hydroelectric  power  is  expected  to
decline  to  about  7% by 1990.  The primary reason for this
decline is that the best available sites  for  hydroelectric
power  have  already  been  developed and that the remaining
sites are either too far from load centers or too costly  to
develop.   Development  of  some  sites may be prohibited by
legislation such as the Colorado River Basin Project Act (P.
L. 90-537)  and the Wild and Scenic Rivers Act   (P.  L.   90-
5U2).   Development  of the maximum potential at other sites
may be limited by the Federal Power Act which requires  that
a  project to be licensed or relicensed be best adapted to a
comprehensive plan for the use of the basin's resources.

There is a possibility of importing  substantial  blocks  of
hydroelectric  power from eastern Canada, but the rapid rate
of growth in Canada  has  possibly  been  a  factor  in  the
inability  of  that  country  and the United States to enter
into long-term contracts for the sale of power.  As much  as
5,000  Mw  might be available on a short-term basis of about
twenty years and could be transmitted to load centers in the
Northeastern United States at economically feasible costs.

One form of hydroelectric power, pumped storage projects, is
expected to  play  an  increasing  role  in  electric  power
generation.  In a pumped storage project water is pumped, by
electricity  generated  by  thermal  units, into an elevated
                             27

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reservoir site during off-peak hours and electricity is then
generated by conventional hydro means during the periods  of
peak usage.  Pumped storage plants retain the same favorable
operating   characteristics  as  once-through  hydroelectric
plants.  Their ability to accept or reject large  blocks  of
energy very quickly make them much more flexible than either
fossil-fueled  or  nuclear  plants.   Of  course,  the power
required to pump  the  water  into  the  reservoir  must  be
generated  by  some other generating facility.  Efficiencies
of pumping and of hydroelectric  generation  are  such  that
about  3  kwh  of  .energy  must  be generated for each 2 kwh
recovered, but on many systems the loss of 1 kwh of non-peak
fuel consumption in lieu of 2 kwh  (equivalent)   of  capital
expenditure  for  additional  peak  generating  capacity  is
favorable in the light of overall system economics.

Although the earliest pumped storage project dates  back  to
1929,  total  pumped  storage  capacity  at  the end of 1970
amounted to only 3,700  Mw.   FPC  estimates  indicate  that
pumped  storage  capacity may reach 70,000 Mw by 1990.  This
would represent a higher rate of growth than  the  projected
growth of the entire industry.

Although  hydroelectric plants produce neither air emissions
nor thermal discharges, some proposed  projects  have  drawn
opposition  from  environmental  groups because of the large
volumes of water being drawn through the turbine-pump units,
with the associated potential for damage to marine life, and
the relatively large areas of  uncertainty  surrounding  the
effect  of  artificial  reservoirs  on  groundwater regimen.
Several  of  the  pumped  storage  project  reservoirs  have
required  remedial  measures to reduce leakage of water from
the reservoir.

In  general,  hydroelectric  power   represents   a   viable
alternative   to   fossil-fueled   or  nuclear  steam  cycle
generation  where  geographic,  environmental  and  economic
conditions   are  favorable.   Pumped  storage  additionally
offers an opportunity to improve overall system  performance
and   reliability,   particularly   for  rapid  startup  and
maintenance of reserves ready to be  loaded  on  very  short
notice.

Combustion Gas Turbines and Diesel Engines

Combustion  gas  turbines and diesel engines are devices for
converting the chemical  energy  of  fuels  into  mechanical
energy  by  using  the  Brayton and Diesel thermal cycles as
opposed to the Rankine cycle used with steam.  As  with  the
Rankine  cycle,  the  second  law  of thermodynamics imposes
                            28

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upper limits as their ideal energy  conversion  efficiencies
based  on  the  maximum  combustion temperature and the heat
sink  temperature   (ambient  air).   The  actual  conversion
efficiencies  of  combustion gas turbines and diesel engines
are lower than those  of  the  better  steam  cycle  plants.
Diesel  engines  are used in small and isolated systems as a
principal generator  of  electrical  energy  and  in  larger
systems  for  emergency  or standby service.  Combustion gas
turbines are used increasingly as peaking units and in  some
instances  as  part  of combined cycle plants, where the hot
exhaust gases from  a  combustion  gas  turbine  are  passed
through  a  boiler  to  generate  steam for a steam turbine.
Both types of units  are  relatively  low  in  capital  cost
($/kw),  require  little  operating  labor,  are  capable of
remote controlled operation, and are able to start  quickly.
Since  these  units  typically operate less than 1,000 hours
per year, fuel costs are generally not a deciding factor.

In  a  combustion  gas  turbine,  fuel  is   injected   into
compressed  air  in a combustion chamber.  The fuel ignites,
generating heat and combustion gases, and  the  gas  mixture
expands  to drive a turbine, which is usually located on the
same axle as the  compressor.   Various  heat  recovery  and
staged  compression  and  combustion  schemes  are in use in
order to increase overall efficiency.  Aircraft jet  engines
have been used to drive turbines which in turn are connected
to  electric  generators.   In  such  units,  the entire jet
engine may be removed for maintenance and a spare  installed
with  a  minimum  of  outage  time.  Combustion gas turbines
require little or no cooling water and therefore produce  no
significant thermal effluent.

Diesel engines can be operated at partial or full loads, are
capable  of  being  started  in  a  very short time, and are
ideally suited for peaking use.  Many large  steam  electric
plants  contain diesel generators for emergency shutdown and
startup power if the plant is isolated from outside  sources
of power.

In   1970,   combustion   gas  turbine  and  diesel  engines
represented  6%  of  the  total  United  States   generating
capacity.   This  represented  15,000  Mw  of combustion gas
turbines and 4,000 Mw of diesel engines.

Alternate Processes Under Active Development

Future Nuclear Types

At the present time almost all of the nuclear powerplants in
operation in the United States  are  of  the  boiling  water
                            29

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reactor  (BWR)  or pressurized water reactor (PWR) type.   As
previously discussed some technical aspects of  these  types
of  reactors  limit  their  thermal efficiency to about 30X.
There  are  potential  problems  in   the   area   of   fuel
availability  if the entire future nuclear capacity is to be
met with these types of  reactors.   In  order  to  overcome
these  problems, a number of other types of nuclear reactors
are in various stages  of  development.   The  objective  of
developing  these  reactors  is two-fold, to improve overall
efficiency by being able to produce steam under  temperature
and  pressure  conditions similar to those being achieved in
fossil fuel plants, and to  assure  an  adequate  supply  of
nuclear  fuel at a minimum cost.  Included in this group are
the high temperature gas-cooled  reactor   (HTGR),  the  seed
blanket light water breeder reactor (LWBR), the liquid metal
fast  breeder  reactor  (LMFBR),  and  the  gas-cooled  fast
breeder reactor (GCFBR).  All of these utilize a steam cycle
as the last stage  before  generation  of  electric  energy.
Both the HTGR and the LMFBR have advanced sufficiently to be
considered as potentially viable alternate processes.

The  HTGR  is a graphite-moderated reactor which uses helium
as a primary coolant.  The helium is  heated  to  about  750
degrees centigrade (1400 degrees Fahrenheit), and then gives
up  its  heat  to  a steam cycle which operates at a maximum
temperature of about 550 degrees centigrade  (1,000  degrees
Fahrenheit).   As  a  result,  the  HTGR  can be expected to
produce electric energy at an overall thermal efficiency  of
about  40JS.   One  HTGR is operating in the United States at
this time, with another expected to be  operating  in  1974.
The  thermal  effects of its discharges should be similar to
those of an equivalent  capacity  of  fossil-fueled  plants.
Its  chemical  wastes  will  be  provided  with  essentially
similar treatment systems that are presently being  provided
for BWR and PWR plants.

The LMFBR will have a primary and secondary loop cooled with
sodium,  and  a  tertiary  power  producing loop utilizing a
conventional steam system.  Present estimates are  that  the
LMFBR will operate at an overall thermal efficiency of about
36*,   although   higher   efficiencies  are  deemed  to  be
ultimately  possible.    The   circulating   water   thermal
discharges  of  the  LMFBR  will  initially be about halfway
between those of  the  best  fossil-fueled  plants  and  the
current  generation of nuclear plants.  Chemical wastes will
be similar to those of current nuclear plants.
                              30

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Coal Gasification

The technology  for  producing  from  coal  a  low  Btu  gas
suitable  for  combustion  in  a utility powerplant has long
been available.  Thus far, the economics of  processing  the
coal  at  the  mine and transporting gas to the point of use
have  not  been  sufficiently  favorable  to  lead  to   the
construction   of  large  scale  facilities  based  on  this
process.

The attractiveness of the concept lies in its potential  for
utilizing  the  most  abundant  of  the  fossil fuels, coal,
without the problems usually associated  with  coal,  sulfur
and  particulates  in  the  stack  gases  and  ash  and slag
problems  in  the  boiler.   The  drawbacks  are  that  coal
gasification  only  returns  2  Jew  for  each  3  kw of coal
processed, large capital investments are required,  and  the
resulting cost per Btu is high.

The Federal Government and a number of private organizations
are  supporting  research  and development seeking to reduce
the cost of coal gasification.  There  are  at  least  eight
process  alternates  in  various  stages of development with
different by-products or energy requirements.  Best  current
estimates  are  that low Btu gas could be produced from coal
for about twice the average price currently  (1973)  paid  by
electric  utilities  for  natural  gas.   With an increasing
shortage of natural gas and fuel oil and increasing pressure
on the utilities for environmentally "clean"  generation  of
electric  energy,  coal  gasification could well turn into a
significant  factor  in  the   steam   electric   powerplant
industry.

Combined Cycles

One   possible   avenue   toward   greater  overall  thermal
efficiency lies in first utilizing the hot  gases  generated
by  combustion  of  the fuel in a combustion gas turbine and
then passing the exhaust of  the  turbine  through  a  steam
boiler.  A small number of plants based on this concept have
been  constructed.   One  problem  lies  in  the  fact  that
present-day turbine technology requires a  relatively  clean
gas  or  light  oil  (natural gas or refined oil) fuel.  Gas
turbines are used primarily as  peaking  units  due  to  the
shortage  of natural gas supplies, its high cost per unit of
heating value, and the relatively high maintenance  cost  of
the    equipment.    Thermal   efficiency   is   a   primary
consideration only for base  loaded  units   and  experience
with gas turbines used as base- load units is limited.

A  major advantage of the combustion gas turbine is the fact
that it requires no cooling water.  Conversion  of  existing
                           31

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units  or  plants  to  combined  cycle  offers,  at least in
theory, the  potential  for  reducing  the  thermal  effects
associated with a given production of electrical energy.  In
practice,   the   modification   of  existing  equipment  is
generally  likely  to  be  technically  difficult,  if   not
impossible, and of doubtful economic viability.

One  form  of combining cycles that holds special attraction
is the utilization of municipal refuse as a source of energy
for the production of steam and electrical power.  Municipal
refuse has an average heating  value  of  about  12,000  J/g
(5000  Btu/lb).   Many  municipalities  have  been forced to
incineration of their refuse  by  the  growing  scarcity  of
available  and environmentally acceptable sites for landfill
operations.  In European countries, higher  fuel  costs  and
lower  wages  have  resulted  in  economics favorable to the
recovery of heat from the incineration of  refuse.   In  the
United  States,  general  practice  has  been  to incinerate
refuse  in  refractory  furnaces  without  attempt  at  heat
recovery,  although several large municipal incinerators now
generate steam.

Plant No. 2913 has been converted to accept a mixture of  10
to  20X  shredded  refuse  and 80 to 90% powdered coal.  The
refuse has previously been processed to remove a portion  of
the  ferrous metals.  The operation appears to be reasonably
successful.  However, the modifications to both  the  refuse
disposal  operations  and  the production of electric energy
are such that the economics must be carefully  evaluated  in
each individual case.

Future Generating Systems

Magnetonydrodynamics

Magnetohydrodynamic    (MHD)  power  generation  consists  of
passing a hot ionized gas or liquid metal through a magnetic
field to generate direct  current.   The  concept  has  been
known  for  many  years, although specific research directed
towards the development of  viable  systems  for  generating
significant  quantities  of electric energy has only been in
progress for the past ten years.

The promise of MHD lies in its potential  for  high  overall
system  efficiencies, particularly if applied as a "topping"
unit in conjunction with a conventional steam turbine.   The
exhaust from a MHD generator is still at a sufficiently high
temperature  to  be  utilized  in  a waste heat boiler.  The
combined MHD-steam cycle  could  result  in  overall  system
                           32

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efficiencies  of  50  to 60% and would require substantially
less cooling water than presently available systems.

The problems with MHD lie in  the  development  of  suitable
materials that can withstand temperatures in the 2200-2800°C
(UOOO-5000°F)  range.   This  includes electrodes, channels,
and auxiliary components.  There are also  problems  in  the
burning  of  commercial  fuels containing various impurities
(such as sulfur-containing coal) and problems resulting from
the fixation  of  nitrogen  and  the  lack  of  satisfactory
methods to remove nitrous oxides from the stack gases.

Although  the Soviet Union and Japan are actively engaged in
MHD research and development, including the construction  of
a   commercial   size  MHD  plant  in  Moscow,  experimental
generators in the United States have produced only  moderate
outputs  for  short  periods  of  time  or small outputs for
periods of up to hundreds of hours.  In spite of substantial
interest in and support of MHD research  by  the  Office  of
Coal  Research  of the U. S. Department of the Interior, and
the Edison Electric Institute, it does not seem likely  that
MHD  will  reach  commercial operations in the United States
within the next several years.

Electrogasdynamics

Electrogasdynamics   (EGD)  produces  power  by  passing   an
electrically  charged  gas  through  an electric field.  The
process converts the kinetic energy of  the  moving  gas  to
high voltage direct current electricity.

The  promise of EGD is similar to the promise of MHD.  Units
would be smaller, with a minimum of moving parts, would  not
be  limited  by  thermal  cycle  efficiencies  and would not
require cooling water.  The system could also be adapted  to
any  source  of  fuel  or energy including coal, gas, oil or
nuclear reactors.

Unfortunately,  the  problems  of  developing   commercially
practical  units  are  also similar to those associated with
MHD.  A pilot plant was constructed in the United States  in
1966, but tests on the pilot model uncovered major technical
problems  and  resulted in a termination of the project.  In
view of these difficulties and the relatively small  current
effort  toward  further  work  on  this  process,  it  seems
unlikely that EGD will have an impact on the national energy
picture within the next twenty years.

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Fuel Cells

Fuel cells are electrochemical devices, similar  to  storage
batteries,  in  which  the chemical energy of a fuel such as
hydrogen is converted continuously into low voltage electric
current.  Fuel cells  presently  under  development  produce
less  that  2  volts  per cell.  In order to create a usable
potential, many cells have to be arranged in series and many
of these series arrangements must be paralleled in order  to
produce a significant current.  Converters would be required
to  convert  the  direct  current produced by the cells into
alternating current.

The main attractiveness of the fuel cell lies in its modular
capability and the possibility of tailoring power output  to
the  immediate  needs.   Fuel  can  be  stored and used when
needed.  Losses in transporting fuel are also less that  the
corresponding  losses  incurred in transmitting electricity.
The efficiency of the direct  conversion  from  chemical  to
electric energy is high and the heat losses are minimal.

Main problem areas at the present time lie in developing low
cost materials of construction and low cost fuels.  The most
effective   electrodes   presently  available  are  platinum
electrodes, which can be used in military and space applica-
tions, but are not economically competitive  for  commercial
use.   Presently  used fuels include hydrogen, hydrazine and
methyl alcohol.  The use of relatively low cost  fuels  such
as  coal,  natural  gas or petroleum is not feasible at this
time.  Unfortunately, the manufacture of  the  usable  fuels
also  involves  the utilization of significant quantities of
electric and other energy, so that the overall benefits  are
que stionable.

A  strong  effort  is  being  made  in  the United States to
develop  the  fuel  cell  for  residential  and   commercial
service.   A  number  of prototype units have been installed
'and are operating successfully.  However the  fuel  cell  is
not expected to replace a significant portion of the central
plant power generation within the next ten years.

Geothermal Generation

Geothermal  generation  utilizes  natural steam or hot water
trapped in the earth1s crust to produce  electrical  energy.
At  the  present  time,  geothermal generation is limited to
areas of geothermal activity such as fumaroles, geysers  and
hot  springs,  if steam is obtained directly from the earth,
it can be used to drive a turbine.  Hot water must first  be
flashed  to  steam  or  used to evaporate some other type of
working fluid.
                            34

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Advantages of this type of power  generation  are  that  the
source  of energy is essentially free, although the costs of
drilling are not insignificant.  Disadvantages are that  the
steam  must  first be cleaned and that, at the current state
of the art, this scheme is practical  only  where  there  is
geothermal activity near the surface of the earth.  With the
advances  being  made  in deep drilling for locating oil, it
would seem possible to tap energy sources almost anywhere on
earth.  However, economic considerations appear to  lead  to
the  conclusion  that geothermal generation will be feasible
only under specially favorable geologic conditions.

Industry Regulation

At the Federal  level,  .numerous  agencies  have  regulatory
authority  or  direct  responsibility for certain aspects of
the industry.  These include the  Atomic  Energy  Commission
(AEC) ,   Department   of   Agriculture,  Department  of  the
Interior, Federal Power Commission, the  Department  of  the
Treasury,  Securities  and  Exchange  Commission,  Tennessee
Valley Authority, Environmental Protection Agency, U.S. Army
Corps of Engineers and the Department of Labor.

The Federal Power Commission (FPC) is authorized to  provide
certain  types of economic regulation over certain investor-
owned electric utilities and administrative supervision over
certain publicly-owned systems.  It licenses all non-Federal
hydroelectric projects, regulates all interstate  rates  and
services,  and requires systems to keep a specific system of
accounts and submit reports on their activities.  The annual
report FPC Form 67;  Steam  Electric  Plant  Air  and  Water
Quality  Control  Data,  with responses from 654 plants, and
the Summary Report for the year  ended  December  31,  1969,
formed  one  of  the  major sources of data for this report.
The 654 plants reporting represented steam  electric  plants
of  25  Mw  or  greater  capacity which were part of a power
supply system of 150 Mw or greater and plants of  25  Mw  or
greater capacity operating in one of the Air Quality Control
Regions.

The  Atomic  Energy  Commission (AEC) has the responsibility
for licensing construction and operation of  nuclear  plants
(stations).   A  utility  proposing to build a nuclear plant
must first apply  for  a  construction  permit.   With  this
application  the  utility  must  file  a  Preliminary Safety
Analysis  Report  and  an  Environmental  Impact  Statement.
After  the  major  design  details  have been completed, and
while construction is under way, the utility has to submit a
Final Safety Analysis Report which then  becomes  the  basis
for  an  operating  license.   In  conformance with a recent
                           35

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decision  by  the  United  States  Court  of  Appeals,   AEC
licensing   procedures  now  include  consideration  of  all
environmental factors, non-nuclear as well  as  nuclear,  as
required  by the National Environmental Policy Act (NEPA) of
1969.

At the state level, all states except  Minnesota,  Nebraska,
Texas  and  South  Dakota  have  regulatory commissions with
authority over investor owned utilities.  In less than  half
the  states the  commissions also have the power to regulate
publicly-owned utilities.  The degrees  of  authority  vary,
but   generally   include  territorial  rights,  quality  of
service, safety, and rate-setting.  The  rate-setting  power
generally   requires   a   utility  to  demonstrate  to  the
regulatory authority  that  a  proposed  rate  structure  is
necessary in order to permit the utility to earn a return on
its  equity investment, also known as a rate base.  The rate
base may be determined from historical cost or  fair  market
value  or  some  other valuation formula, but in most cases,
commissions in effect assure the utility of a minimum return
on capital invested in its system.

Construction Schedules

Construction schedules for nuclear plants and  fossil-fueled
plants  are  significantly  different in the total time span
required  from  the  concept  study  stage   to   commercial
operation.  For example, the condensed construction schedule
for   a   200  Mw  oil-fired  unit  shown  in  Figure  III-2
encompasses a span of about three years from  initiation  of
the  concept  study  to  commercial operation.  In contrast.
Figure III-3 shows excerpts from a typical LWR nuclear plant
project schedule.  The time span shown from  the  initiation
of  the  preliminary  design  until  commercial operation is
about 8-9 years.

Reliability, Reserve Generating Capacity,
and Scheduling of Outages

According to the Federal Power Commission and  the  National
Electrical  Reliability  Council  (References  292,  392 and
396) , in order to maintain the  uninterrupted  service  that
customers  expect  and  rely  upon,  all  power systems must
maintain or have access to more generating capacity than the
expected annual peak load.  This spare  capacity,  known  as
required  reserves,  changes  from  time  to time and varies
widely from system to system, depending on the system  size,
the  sizes  and types of generating units in the system, the
forced   outage   rates   for   these   units,   maintenance
requirements, and system load characteristics.
                          36

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                              Figure  III-2

             CONDENSED CONSTRUCTION SCHEDULE, 200 MW OIL-FIRED UNIT* (Reference No. 187)
Years
Months
Concept Study Begun
Grading and Excavation
Piling
Substructure
Structural Steel
Superstructure
Gallery Work
Steam Generator
Steam Turbine-Generator
Condensing Equipment '
Cooling Tower**
Equipment Erection
Flues, Ducts and Stack
Misc. Field Erection
Piping System
Thermal Insulation
Electrical
1972
JFMAMJJASONI
-

1973
JFMAMJJASOND

Initi
___ Commerci

	
	

.
1974
JFMAMJJASQND

Boil out — ^
al Steam 	

M




	



1975
JFMAMJ

»
fc






 * Note: Base-load type unit with provisions for cycling duty. Major items of
         equipment include one main transformer, one generator, one steam turbine,
         one steam condenser, two condensate pumps, five closed feedwater heaters,
         one deaerating heater, two boiler feedwater pumps, one steam generator,
         one combustion burner group, and two combustion air fans and compressors.
** Note: Cooling tower is mechanical draft.

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GO
00
                                       Figure III-3

                     TYPICAL LWR NUCLEAR PLANT PROJECT SCHEDULE (HIGHLIGHTS ONLY)*
           Task
                                     \Year
8
10
Site Selection and  Acquisition
Environmental Studies
Prepare NSSS and Fuel Specifications
Vendor Bid Preparation
Bid Evaluation and Negotiation
Contract Awards
Preliminary Design
Detailed Design
Site Clearance and Excavation
Foundations and Buildings
Containment Erection
NSSS Equipment Installation
Turbine-Generator Erection
NSSS and T-G Auxiliary Equipment
Fuel Loading
Testing
Commercial Operation
      * Note: Excerpts from Reference No. 186,

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Methods of Determining Reserve Requirements

The  planning techniques used by electric utility systems to
establish required reserve levels can be  divided  into  two
broad categories:
    1.  Non-probabilistic methods
    2.  Probabilistic methods

Generating   capacity   requirements   based   on   a   non-
probabilistic  method  have  generally  been  determined  by
establishing  minimum  reserve  requirements over the annual
peak load period based on:

    1.  A fixed percentage of peak load, or
    2.  A fixed multiple of the system's largest
        generating unit, as for example the largest unit
        plus an average-sized unit.

In the use  of  these  non-probabilistic  methods,  judgment
plays   a   predominant   role.   Their  only  advantage  is
simplicity,  since  reserve  requirements  can   easily   be
calculated  once  an annual peak load has been projected and
the capacity of the largest unit is known.  This  simplicity
of application, however, is offset by the inherent inability
of  such  methods  to measure, in a quantitative manner, the
system   reliability   associated    with    such '   reserve
determinations.   In  this approach, little consideration is
given to the daily, monthly, and seasonal load patterns,  or
to  the  characteristics of generating equipment peculiar to
the individual system, such as unit availabilities  and  the
mix of unit types and sizes.

Probabilistic   methods,   although   complex,   provide  an
analytical means for evaluating the relative risk associated
with supplying system load requirements  by  various  means.
This is generally accomplished by interrelating the load and
capacity models developed for the particular system and time
period  under  study.   The load model usually consists of a
series cf load levels representing the full range  of  daily
or  monthly  peak  loads  anticipated  throughout  the given
p'eriod.  The model  is  usually  developed  from  historical
records of daily peaks, with adjustments to reflect expected
changes  in  load  characteristics  of future loads.  It may
also inclu'de provision for the probability of  load  changes
because  of  deviations from normal conditions of weather or
expected economic activity.

The capacity models used  in  probabilistic  method  usually
involve   calculating  the  likelihood  of  availability  of
various levels  of  system  generating  capacity,  based  on
                          39

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assumed  forced  outage rates for the individual units.  The
study period is usually  divided  into  uniform  maintenance
intervals  so  that  units  that  would not be available for
service due to scheduled maintenance would be excluded  from
the  calculations  for that particular interval.  In effect,
this  results  in  a  number  of   capacity   models.    The
interrelation of such capacity models with load models forms
the basis for evaluating the risk of capacity not being able
to  satisfy  the load requirements.  Sample calculations and
more detailed explanations are given in some of the Regional
Advisory Committee reports published in Parts II and III  of
the 1970 National Power Survey.

To  illustrate  the  relationship  between  reliability  and
reserve generating  capacity  consider  the  two  curves  in
Figure   III-4 which are based on studies made by two groups
of  systems.   Assuming  an equivalent level of reliability,
e.g., one occasion in  ten  years  when,  on  a  probability
basis,  insufficent  generation  will  be available to cover
load, the New England systems require a reserve of about 21%
compared with 12% for the MARCA systems.  This reflects  the
differences in type, number, and size of generating units as
well  as  the  diversity  and  composition  of  load in each
instance - all factors,  which  affect  generation  reserves.
Furthermore,   the   percent  reserve  requirements  can  be
expected to change with time, reflecting varying conditions.

Reserves for Scheduled Outages

Generating units are taken out of service at fairly  regular
intervals  for inspection, overhaul, and repair as required.
This practice accounts for the relatively  high  reliability
of  generating  capacity.   When  conditions  are such on an
electric system that generating capacity  needed  to  supply
load  must be taken out of service, generating capacity from
reserves must be provided to take its place.  The amount  of
reserves needed at time of peak load depends on the duration
of maintenance outages and whether the work can be scheduled
during offpeak months.

There  are  variations  from  year  to year in the amount of
scheduled maintenance that a generating unit  requires,  and
some  types  of inspection and repair are needed only at two
or three year  intervals.   There  are  also  variations  in
intervals  between  scheduled  outages  and  in downtime for
maintenance because of such factors as age, size and type of
unit.  On  the  average,  baseload  boiler-turbine-generator
units  require  about one month of scheduled maintenance per
year.
                          40

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                                        ONE OCCASION
                                         IN 10 YEARS
                       10      15      20

                        PERCENT RESERVE
Figure 111-4
Regional  Reliability Versus
Percent Reserve
                41

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In general, the relatively large generating  units  will  be
operated  at  higher use factors and will  require more time
for maintenance than the smaller units.  For the purpose  of
the  Federal  Power  Commission analysis of 1980 reserve for
scheduled  outages,  the  large  size  thermal  units,   600
megawatt  or  over,  were  assumed  to  require 600 hours of
scheduled maintenance annually while units of  200  megawatt
to  599 megawatt size were assumed to require 500 hours, and
units under 200 megawatt, 400 hours.

In estimating the amount of reserve required  for  scheduled
maintenance,  it  is necessary to determine whether there is
enough time and spare capacity to  take  all  units  out  of
service for their scheduled overhaul during off-peak months.
In  actual  practice,  such  a  determination  would involve
extensive calculation if there were many units in the system
and the scheduling were tight.  Various  combinations  would
be  explored  to  determine the optimum schedule in terms of
utilizing the spare capacity available in  generating  units
of different sizes for each interval.3«* Reference 395 gives
an  example of a model for the optimization of outage costs.
At the same time the maintenance schedule should provide for
reasonable use of the crews  and  not  result  in  excessive
loading  on  parts  of  the  transmission system.  A further
factor is that the  generating  capacity  of  a  system  may
change  month  by  month  because of retirements, additions,
cooling water  limitations,  and  seasonal  changes  in  the
output capability of installed hydro-electric units.

Coordination for Reliability

Most  of  the  text  of  this  discussion  is  exerpted from
Reference 292, from the Federal Power Commission.

Nearly every major electric utility  system  in  the  United
States  is  connected with neighboring systems to form large
interconnected networks.   Financial  benefits  are  thereby
often   realized   from   staggered  construction  of  large
generating  units,  short-term  capacity  transactions,  and
interchanges  of  economy  energy.   Reduction  of installed
reserve  capacity  is  made  possible  by  mutual  emergency
assistance    arrangements    and   associated   coordinated
transmission planning.  Bulk  power  supply  reliability  is
enhanced  by  interconnection  agreements  covering spinning
reserves, reactive kilovolt-ampere  requirements,  emergency
service,   coordination   of   day-to-day   operations,  and
coordination of maintenance.  The  satisfactory  performance
of  a  power supply network requires close cooperation among
component systems for accurate control of frequency, sharing
                        42

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of load regulating responsibilities and maintenance of power
system stability.

There are thousands of arrangements among systems  from  all
segments  of  the industry providing for various degrees and
methods  of  electrical  coordination.    These   variations
reflect  differences  in  load  density,  characteristics of
generating sources, geography, and climate.  They are also a
product  of  managerial  views  with  respect  to  planning,
marketing,   competition,  and  retention  of  prerogatives.
Because  of  these  differences,  no  single  definition  of
coordination  has  been  established by the electric utility
industry.  As used  in  this  discussion  "coordination"  is
joint planning and operation of bulk power facilities by two
or  more  electric  systems  for  improved  reliability  and
increased efficiency which would not be attainable  if  each
system  acted  independently.   "Full coordination" involves
coordination of all systems within an area,  to  the  extent
technologically  and  economically  feasible  to  permit the
serving of their combined loads with a minimum of  resources
and  to exploit opportunities for coordination with adjacent
areas.

Managements of various electric  systems  have  developed  a
wide   variety   of   formal   and   informal   coordinating
organizations or power pools.  Some merely  provide  members
with  a  mechanism  for  the exchange of information; others
deal primarily  with  day-to-day  interconnected  operations
under  normal and abnormal system conditions; many engage in
coordinated planning and operation for increased  economies;
and still others are dedicated to improving reliability over
broad  geographic  areas encompassing otherwise unaffiliated
electric systems.  All of these organizations contribute  in
varying  degrees  to the reliability and economy of electric
power supply.

The term "formal power pool" as used here means two or  more
electric   systems  which  coordinate  the  planning  and/or
operation of their bulk power facilities for the purpose  of
achieving greater economy and reliability in accordance with
a  contractual  agreement  that  establishes  each  member1s
responsibilities.  Individual members usually  are  able  to
obtain  the economies and other advantages available to much
larger systems  while  retaining  their  separate  corporate
identities.

Table  A-2-1  of  Appendix 2 lists the individual members of
each formal power pool in the contiguous United States.  The
areas served by formal power pools cover most of the  United
States as shown in Figure A-2-1 of Appendix 2.
                          43

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A  power  pool  must  have sufficient generating capacity to
meet the combined pool load plus reserve to cover  equipment
outages,  frequency,  regulation,  load  swings,  errors  in
forecasting loads, and slippage in planning and construction
schedules.  The various pools make  specific  provision  for
sharing  among the pool participants the burden of providing
this reserve margin.  There are, in general,  two  different
methods  of  accomplishing  this objective.  Under one, each
member is required to maintain a specified minimum  capacity
reserve,  usually stated in percent of peak load.  Under the
other, existing installed generating capacity is  shared  on
an  equalized  reserve  basis.   That  is,  rather than each
member being responsible for maintaining some minimum amount
of reserve, the reserve  capacity  of  the  pool  is  shared
proportionally among the members.  Reserve responsibility is
satisfied  by  capacity  transactions  so  that members with
excess capacity resources are compensated by members  having
capacity deficiencies.

There are at least 13 informal organizations of utilities in
the   contiguous  United  States  which  are  structured  to
emphasize some limited aspects of inter-system coordination.
These coordinating groups are informal in the sense that  no
member  is contractually obligated to undertake any specific
course of action or to provide any kind of service to  other
members.   The groups are usually concerned primarily either
with planning or operation,  although  some  are  active  in
both.   The  geographic  areas  covered  by these groups are
shown in  Figure  A-2-2  of  Appendix  2.   Table  A-2-2  of
Appendix 2 lists each group, its acronym, and the individual
members.   Twenty-four individual systems, as shown in Table
A-2-3 of Appendix'2, are members of  two  or  more  informal
coordinating groups.

The  National Electric Reliability Council  (NERC) was formed
in  1968  for  the  purpose  of   further   augmenting   the
reliability  and  adequacy  of  bulk  power  supply  by  the
electric systems of North  America.   It  consists  of  nine
regional  reliability  councils  whose  membership comprises
essentially all of the power systems in  the  United  States
and  the  Canadian  systems  in  the  provinces  of Ontario,
British Columbia, Manitoba, and New Brunswick.

Each council has established  a  mechanism  to  provide  for
direct  or  indirect  participation  by the smaller electric
utilities within its boundaries.  The approximate geographic
boundaries of the councils are  shown  on  Figure  A-2-3  of
Appendix  2,  and the individual members of each council are
shown in Table A-2-4 of Appendix 2.
                         44

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None of the  reliability  councils  has  authority  to  make
decisions involving the planning or installation of new bulk
power facilities, but most have a formal review and approval
role.   Seven reliability councils have adopted criteria for
testing the design and operation of  existing  and  proposed
bulk  power  facilities  and  the other two have established
committees to formulate  such  criteria.   Several  councils
have  adopted procedures for reporting by members of uniform
compatible data on load  estimates,  scheduled  maintenance,
power  exchanges, and installed reserve margins.  A few have
developed  guides  and   regionally   coordinated   programs
covering daily operating reserve margins, emergencies on the
interconnected   system,   uniform   rating   of  generating
equipment,  and  principles  of  relaying.   Some   regional
councils   have   established  environmental  committees  to
encourage  more  effective  consideration  of  environmental
matters  in the siting, construction, and operation of major
facilities.

The  Federal  Power  Commission's  Statement  of  Policy  on
Reliability and Adequacy of Electric Service, Order No. 383-
2  (Docket No. R-362), issued April 10, 1970, is intended to
implement fully the voluntary aspects of Section  202(a)  of
the Federal Power Act, and to encourage utilities throughout
the   Nation  to  continue  to  strengthen  the  reliability
councils  and  develop  more  effective  bulk  power  supply
programs.   The  Commission Order requested participation by
the  staffs  of  the  Commission   and   appropriate   State
commissions  as  non-voting  participants  in  the principal
meetings of NERC and the regional  councils,  and  requested
regional  councils  to  report  the  projection of loads and
coordinated bulk power supply programs on a ten-year  basis.
It  also  requested  reports  on the status of consultations
with affected  groups  and  appropriate  local.  State,  and
Federal  authorities  regarding  the environmental impact of
proposed major facilities,  and  information  on  load  flow
studies, network stability analyses, principal communication
and  control  systems,  and  coordinated  regional  programs
pertaining  to   provisions   for   emergencies,   scheduled
maintenance  outages  of major facilities, and other matters
which affect the overall reliability of  the  interconnected
network.   Initial  reports  were  filed  as of September 1,
1970.  Future reports to be filed on April 1  of  each  year
provide  opportunity  for updating the power supply programs
in the ten-year  framework  to  reflect  revisions  in  load
estimates,   new   developments   and   resources,  and  the
resolution of environmental issues.

In April 1962,  representatives  of  interconnected  systems
throughout  the  United  States  and  eastern  Canada met at
                           45

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Omaha,  Nebraska,   and   laid   the   groundwork   for   an
international  organization to coordinate the operation of a
looming coast-to-coast interconnected network.  This led  to
formation    of    the    North   American   Power   Systems
Interconnection Committee  (NAPSIC)   which  held  its  first
meeting   in   January,   1963.    NAPSIC   is  a  voluntary
organization  of  operating   personnel   representing   ten
interconnected   Operating   Areas.     The   scope   of  the
organization has  expanded  so  that  by  1971  it  included
consideration of the following:

     1.  Operating reliability criteria,
     2.  Frequency regulation,
     3.  Time control,
     t.  Tie-line frequency bias,
     5.  Operating reserves,
     6.  Time error correction procedures,
     7.  Emergency operating procedures
         (a)  Load shedding and restoration
         (b)  Tie separation and restoration
         (c)  Generating unit security,
     8.  Scheduled maintenance outages of major facilities
     9.  Interchange scheduling procedures,
    10.  Procedures, for handling inadvertent interchange,
    11.  Any other operating matters that required
         coordination to effect reliable inter-
         connected operation.

NAPSIC's  contribution  to  reliable  system  performance is
enhanced  by  its  close  liaison  with  planning  entities,
regional  reliability  councils,  and  the National Electric
Reliability Council.  Much of the reliability  council  work
overlaps  activities  which are the concern of the Operating
Areas within NAPSIC.  Close working relationships which have
been  established  between  these  different  organizational
units   provide   the   opportunity   for   very   effective
coordination between planning and operating functions.

Coordinating Techniques

Over the years electric  utilities  have  developed  a  wide
variety  of  coordinating  techniques  to  achieve increased
reliability and  improved  economies.   Some  of  the  major
coordinating techniques are described below.


Staggered   construction   is  a  technique  which  involves
construction of excess capacity by one utility for  the  use
of  one  or  more  other  utilities  with the supplier-buyer
arrangement being reversed or modified with each  succedding
                           46

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unit.   Several variations of this practice are widely used.
Sometimes  adjacent  systems  informally  coordinate   their
capacity  additions  over  a period of several years so that
the total installed capacity reserve approximates the amount
required by the entire geographic  area.   Another  form  of
staggered   construction   which   has   gained   widespread
acceptance in recent years is the unit-sale  concept.   This
entails arrangements whereby a system installs a larger unit
than  it  otherwise  normally  would,  and sells a specified
amount of excess capacity from that  unit  to  one  or  more
neighboring systems.  The purchaser's entitlement is limited
to  the  availablity of capacity from the specific unit.  In
the event of an outage  of  such  unit,  the  buyer  is  not
entitled  to  any  portion  of the supplier's other capacity
resources.

Seasonal capacity exchanges can usually  be  made  when  the
annual  peak loads of two utilities, areas, or regions occur
in different  seasons  of  the  year.   However,  individual
systems  within  the  same  power  pool  having  annual peak
demands which occur in  different  months  do  not  normally
participate  in  seasonal  capacity  exchanges because, in a
pool, savings from  intrapool  diversity  are  automatically
achieved   by   the   decreased   total   installed  reserve
requirements resulting from the pool operation.

Small Systems

For  the  purpose  of  providing  a  statistical  frame   of
reference,  small  electric systems were defined in the 1964
National Power  Survey  as  those  having  annual  peak-hour
demands of less than 25 megawatts.  By this definition there
were 3,190 small systems in 1962, of which 899 generated all
or  part  of  their  requirements  and 2,291 purchased their
entire requirements.  By 1968  the  total  number  of  small
systems  decreased to 2,812, a reduction of 348, principally
as the result of acquisitions and mergers.  More than 800 of
the remaining small systems owned generating facilities, and
243  were  electrically  isolated  from  major  transmission
networks.

The total cost of generation at the bus bar for the sizes of
plants usually installed by small systems is relatively high
because  such  plants  cost more per kilowatt to build, burn
more fuel per kilowatt-hour, and cost more per kilowatt-hour
to operate.  The ability to take full  advantage  of  modern
generation  and  transmission technology is often limited to
the  larger  systems.   Only  31  systems  with   generating
capacity  of  less  than 500 megawatts are members of formal
power pools.
                           47

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Since the cost gap  between  small  scale  and  large  scale
generation  and  transmission has been progressively widened
by technological improvement, most of the  smaller  electric
systems   which   generate   the   bulk  of  their  electric
requirements  are   at   a   relatively   greater   economic
disadvantage  than they were during the 1950's and the early
IseO's.   Benefits  from  coordinated  planning  are   being
realized  by  some  of  these  smaller  system through joint
ownership,  or  entitlements  in   large,   more   efficient
generating  units  sized  to  meet  area  needs, and through
associate or  affiliate  membership  in  regional  councils.
Systems  which  serve their growing needs by power purchases
receive reliability and economic benefits when  their  power
suppliers    participate    in    area-wide   and   regional
coordination.

Many small systems buy all of their  power  requirements  at
wholesale,  although  they have the option to plan, install,
and operate bulk power facilities.  A heavy concentration of
these distribution systems within a specific geographic area
increases the  chances  of  economic  feasibility  for  them
jointly  to  plan and construct their own bulk power system,
but such endeavors may result in  duplication  of  faciities
unless suitable wheeling arrangements can be worked out with
neighboring, and generally competing, systems.

Small   systems   having  generating  facilities,  but  with
sufficient   capacity   to   meet   their   total   electric
requirements, include:  (1) those having only a small amount
of  generation  (often,  hydro)  which  is supplemented with
purchases from a neighboring supplier (2) systems which plan
gradually to phase themselves"out of the generating business
but still have one or more units in  serviceable  condition;
and  (3)  systems  that  use small units for peak shaving to
reduce average purchased  power  costs.   There  is  a  wide
variety  of  bilateral arrangements covering such situations
This type of system will  continue  to  be  a  part  of  the
overall   supply,   primarily   because   it   provides   an
intermediate step in moving to or  from  full  within-system
generation.

Some  small systems have sufficient generation to meet their
own requirements and operate in complete electric isolation,
or with interconnection facilities  normally  open.   Others
are  connected  to  and operate in parallel with major power
networks, under a wide variety  of  agreements.   In  recent
years,  some small systems have been able to negotiate lower
reserve   requirements   through   coordination   of   their
operations  with  neighboring systems, and a few have gained
access to large scale generation.
                          48

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At the beginning of  1968,  243  systems  were  electrically
isolated  from  power supply networks.  Approximately 82 1/2
percent of the total generating  capacity  of  the  isolated
systems  was  located  in  eight  states (Florida, Illinois,
Kansas,  Louisiana,  Massachusetts,  Mississippi,  Ohio  and
Texas) .

Isolated  systems typically experience relatively high power
supply costs and inferior bulk power reliability.  About  75
percent  of  the  isolated  systems  in 1966 carried reserve
capacity greater than 50 percent of their annual system peak
demands.  On such systems the forced outage of a  generating
unit  may  represent loss of such a large portion of on-line
capacity that partial or  total  power  failure  may  result
before  other  units  can respond to meet the increased load
placed upon them.  Also, an isolated system is vulnerable to
extended service interruption if fire, natural disaster,  or
other   catastrophe  destroys  one  or  more  of  its  major
generating plants.
                           49

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                         SECTION IV

                   INDUSTRY CATEGORIZATION
 The  purpose of  this  section is to  establish a framework  for
 the   orderly  development of effluent limitations guidelines
 and    standards   in   consideration    of    waste    water
 characteristics,  pollutant parameters, control and treatment
 technology,   cost,   energy,  non-water  quality aspects, and
 other factors as   presented  in  subsequent  sections.   The
 rationale     supporting     the     recommended    industry
 subcategorization and  effluent  limitations  guidelines  and
 standards  is  presented  in  Sections IX, X, and XI of this
 document.

 Steam electric  powerplants are characterized by many diverse
 aspects,   and  at the same  time by  many   similarities.
 Categorization  of  the industry  into discrete segments for
 the  purpose of  establishing effluent limitations  guidelines
 requires   consideration of the various factors causing both
 this  diversity  and  similarity.   Specific  factors  which
 require    detailed  analysis  in   order  to  categorize  the
 industry   include the processes   employed,  raw  materials
 utilized,  the  number and  size   of generating facilities,
 their age, site characteristics and mode of operation^

 Process Considerations

 There are five   major unit  processes  involved  in   the
 generation of  electric power - the storage and handling of.
 fuel related  materials both  before and  after  usage,  the
 production of  high-pressure  steam,  the  expansion of the
 steam in  a  turbine   which  drives  the   generator,   the
 condensation  of the  steam leaving  the turbine and its return
 to   the  boiler,   and  the generation of electric energy from
 the   rotating  mechanical  energy.   Figure  IV-1  shows    a
 schematic   flow   diagram   of  a typical  steam  electric
 powerplant.   Power cycle diagrams  for  typical  fossil  fuel
 units and  nuclear units are shown  in Figures IV-2, and IV-3,
 respectively.

 Fuel Storage  and  Handling

 All   fuels must be delivered to the plant site, stored until
•usage, and the  spent fuel materials stored on  the  premises
 or    removed.    Fossil-fueled  plants  require  off-loading
 facilities and  fuel  storage in quantities based on the  size
 of   the  plant  and  the  limited   reliability  of delivery.
 Fossil-fuels  are  transported to the furnace where combustion
                            51

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cn
tv>
 VENT

X
       BOILER
       SLOWDOWN

       DRUM
                      FIGURE   IV-I


             SCHEMATIC  FLOW   DIAGRAM
                                                       BOILER FEED

                                                           PUMP
CONDENSATE

   PUMP
          TYPICAL STEAM ELECTRIC  GENERATING PLANT

-------
                                                                   Table II-l

                                SUMMARY OF EFFLUENT LIMITATIONS GUIDELINES AND STANDARDS FOR POLLUTANTS OTHER THAN HEAT
SOURCE
Nonrecirculating cooling water

Cooling tower blowdown







Ash transport

Bottom ash transport

Fly ash transport

Low-volume wastes
Boiler blowdown



Metal equipment cleaning wastes



Other sf except sanitary wastes
and radwastes
Rainfall runoff from materials stor-
age piles and construction activities
Rainfall runoff from other sources ***
Sanitary wastes and radwastes
All sources


POLLUTANT PARAMETER
Free available chlorine
Total residual chlorine
Free available chlorine
Total residual chlorine
Chromium, total
Zinc, total
Total phosphorus ( as P )
Corrosion inhibiting materials
other than Cr, Zn, and P
All corrosion inhibiting materials
Total suspended solids
Oil and grease
Total suspended solids
Oil and grease
Total suspended solids
Oil and grease

Total suspended solids
Oil and grease
Copper, total
Iron, total
Total suspended solids
Oil and grease
Copper, total
iron, total
Oil and grease

Total suspended solids
All pollutant parameters
All pollutant parameters
Polychlorinated biphenyls
pH value ****

EF
BPCTCA (1977)

--"
"^. 	

"I
>- No limitation
\


J
30 (100 max)
15 ( 20 max)
-
-
-
-








^








LUEOT LIMITATIONS*
BATEA (1983)
0.2 (0.5 max) **
**
0.2 (0.5 max) **
**




0.2 (0.2 max)
1.0 (1.0 max)
5.0 (5.0 max)
Case-by-case

-
-
-
2.4 (8.0 max)
1.2 (1.6 max)
30 (100 max)
15 ( 20 max)

30 (100 max)
15 ( 20 max)
1.0 '(1.0 max)
1.0 (1.0 max)
30 (100 max)
15 ( 20 max)
1.0 (1.0 max)
1.0 (1.0 max)
30 ( 100 max )
15 ( 20 max)

Not to exceed 50mg/l
No limitation
No limitation
No discharge
Within the range 6.0-9.0
_ at all times

















New Sources




_
_
_
_

No discharge
-
-
1.5 (5.0 max)
0.75(1.0 max)
No discharge
No discharge

















   * Note:  Numbers are concentrations, mg/1, except for pH values. Effluent limitations, except for pH and rainfall runoff,  are quantities of pollutants
           to be determined by multiplying the concentration indicated times the flow of water from the corresponding source.  Effluent limitations are
           averages of daily values for 30 consecutive days ( maximum values for any one day are determined from the numbers in parentheses), except for
           pH and rainfall runoff. In the event that waste streams from various sources are combined for treatment or discharge, the quantity of each
           pollutant attributable to each waste water source shall not exceed the limitation for that source.  No limitations are prescribed for
           sources/pollutants not specified in this table.
  ** Note:  Neither free available chlorine nor total residual chlorine may be discharged from any unit for more than two hours ( aggregate )  in any one
           day and not more than one unit in any plant may discharge free available chlorine or total residual chlorine at any one time.  Exceptions to be
           made, on a case—by—case basis, if discharger demonstrates that limitations must be exceeded in order for the cooling system to operate
           efficiently.
 *** Note:  ...and from facilities designed, constructed, and operated to treat the volume of material storage runoff and runoff from construction activit-
           ies that is associated with a 10 year, 24 hour rainfall event.
**** Note:  From all sources except nonrecirculating cooling water, rainfall runoff from sources other than materials storage piles and construction activ-
           ities ***, sanitary wastes and radwastes.

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CT1
CO
                                        Stack Loss    Air In
                                                                                                                                        Net Power Loss
                                                                                                                                                    Net Power
                                                                                                                                                      Net
                                                                                                                                                   Generator
                                                                                                                                                  & Mechanical
                                                                                                                                                     Loss
fit—
                                                                    High Pressure Bleed Heaters
                              \
                                                                                                             Low Pressure Bleed Heaters

                                                                                                         Boiler Feed Pump
             Figure  IV—2    Power cycle diagram,  fossil fuel — single reheat, 8 stage regenerative feed heating — 3515 psia, 1000F/1000F steam.
                                                                                                                                                             278

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en
                                                                                                                              Auxiliary
                                                                                                                                Loss
Figure
                                                                                                    Steam
                                                                                                  Generator
                                                                                                  Feed Pump
                                                                                                   Turbine
                                                                                 Low Pressure Bleed Healers
                                                                                 & Internal Moisture Separator Receivers
                               Power cycle diagram, nuclear fuel — reheat by bleed and  high pressure steam, moisture separation, and 6-stage regenera-
                        te feed heating — 900 psia, 566F/503F steam.   278

-------
takes place.  The combustion  of  fossil  fuels  results  in
gaseous   products   of   combustion  and  non-gaseous  non-
combustible residues called ash.  A portion of  the  ash  is
carried  along with the hot gases.  This portion is referred
to as fly ash.  The remainder of  the  ash  settles  to  the
bottom  of  the furnace in the combustion zone and is called
bottom ash.  The amount and characteristics of each type  of
ash  is  dependent  on  the  fuel  and  the  type  of boiler
employed.  Coal produces a relatively large amount of bottom
ash and  fly  ash.   Oil  produces  little  bottom  ash  but
substantial fly ash.  Gas produces little ash of any type.

Coal-fired steam generators can be categorized as wet or dry
bottom according to ash characteristics.  Gas-fired and oil-
fired  steam  generators are generally run with dry bottoms.
In one type of wet bottom steam generator the coal is burned
in such a manner as to form a molten slag which is collected
in the bottom and is tapped off similar to the tapping of  a
blast furnace.  In dry bottom steam generators, where ash is
removed  hydraulically,  it  is  customary  to  pump the ash
slurry to a pond or settling tank, where the water  and  ash
are separated.

Many  modern  powerplants  remove  fly  ash from the gaseous
products   of   combustion   by   means   of   electrostatic
precipitators, although scrubbers may be required  on plants
burning  fossil  fuels containing more than a minimal amount
of  sulfur.   The  removal  of  fly  ash  collected  in   an
electrostatic precipitator depends on the method of ultimate
disposal.   if  the fly ash is to be used in the manufacture
of cement or bricks or otherwise used  commercially,  it  is
generally  collected  dry  and handled with an air conveyor.
If it is to be disposed of in an ash pond or settling basin,
it is sluiced out hydraulically.

Many of the operations involving fossil-fuels are  potential
sources  of  water  pollutants.  The storage and handling of
nuclear fuels in comparison is not a  continuous  operation,
requires  little  space,  is  highly  sophisticated from the
standpoint  of  engineering  precision  and   attention   to
details,  and  is not considered to be a potential source of
nonradiation water pollutants.

Steam Production

The production of high-pressure steam  from  water  involves
the combustion of fuel with air and the transfer of the heat
of  combustion from the hot gases produced by the combustion
to the water and steam  by  radiation  and  convection.   In
order  to  obtain the highest thermal efficiency, as much of
                          55

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the heat of combustion as possible must be transferred  from
the  gases  to  the  steam  and  the gases discharged at the
lowest possible temperature.  This requires the transfer  to
be  accomplished  in  a  series  of steps, each designed for
optimum efficiency of the overall process.  Not every boiler
provides each of the steps outlined  in  this  section,  but
most  of  the  boilers  supplying  steam to larger and newer
generating units (over 200 Mw and built in the  last  twenty
years)   provide  these steps as a minimum.  A typical boiler
for a coal-fired furnace is shown in Figure IV-U.

Feedwater is introduced into the boiler by the  boiler  feed
pump  and  first  enters  a  series  of  tubes (regenerative
feedwater heater) near the point where the gases  exit  from
the  boiler.   There it is heated to near the boiling point.
The water then flows to one or more  drums  connected  by  a
number  of  tubes.   The tubes are arranged in vertical rows
along the walls of the combustion zone of  the  boiler.   In
this  zone, the water in the tubes is vaporized to saturated
steam primarily by the  radiant  heat  of  combustion.   The
saturated   steam   is   then   further   heated  to  higher
temperatures primarily by convection of the hot gases in the
superheater section of the boiler.   In  some  boilers,  the
steam is reheated after passage through the initial sections
of  the turbine.  Finally, the flue gases are passed through
a heat exchanger (air heater)  in order to transfer heat at a
low temperature to the air being blown into the boiler.

As far as steam production is  concerned,  the  efficiencies
possible  from  the conversion of the chemical energy of the
fuel  to  electric  energy  depend  on  the  maximum   steam
temperatures   and  pressures  and  on  the  extent  of  the
utilization of regeneration feedwater  heaters,  reheat  and
air  heating.  For a simple cycle using saturated steam with
a maximum pressure of 6.3 MN/sq m (900 psi) expanded in  the
turbine  to  atmospheric pressure and using exhaust steam to
heat the feedwater, the  total  cycle  efficiency  would  be
about  20%.   If the saturated steam is superheated to 530°C
(1,000°F), the efficiency is increased by an increment of  5
to  6%.   The  addition of a high-vacuum  (863 kg/sq m  (2-1/2
in. of Hg abs)) condenser  and  the  addition  of  feedwater
heating  will increase possible efficiencies by an increment
of 12 -  13%  to  about  38%.   By  increasing  the  maximum
pressure   still   further  and  reheating  the  steam,  the
efficiency can be increased to about U5%.  These are turbine
cycle efficiencies and do not reflect various losses in  the
boiler  and  auxiliary  power requirements.  Indications are
that these efficiencies represent the limit obtainable  from
the  processes  presently in use.  Higher efficiencies which
require  higher  steam  pressures  and  temperatures   would
                            56

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                                                                                ZJ
                                                                                  Coal
                                                                                 Tripper
                                                                      -=¥R!J
                                                                      •••^IM—,
                                                                          •i"	.••  _ .
                                                                           Cyclone "  ;!•
                                                                      "223J~furnac.es   ii
 Gas
Outlet
Universal-Pressure boiler with opposed Cyclone Furnaces and bin system for coal preparation and feeding.

              Figure  IV-4  Typical Boiler for  a  Coal-Fired Furnace
                               57

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present  material  problems  that  do  not  seem  to be near
solution.  The alternate of lower terminal  temperatures  is
not  possible  since  the waste heat must be rejected to the
environment  under  ambient  conditions,  unless  economical
techniques  could  be  developed to reject waste heat to the
low temperature of outer space.

In the effort to improve the efficiency of the steam  cycle,
designers  have  attempted  to resort to higher temperatures
and  pressures.    Maximum   turbine   operating   pressures
increased  from about 1,000 psi in the early 1930's to 5,000
psi  in  the  early  1960's.   Since  then,  turbine  design
pressures  for  new units have receded slightly to a maximum
of 3500  psi.   Similarly,  maximum  operating  temperatures
increased  from  800°F to 1200°F for a brief period and then
receded to a maximum of 1050°F, as designers looked to  more
sophisticated  reheat cycles and turbine designs to optimize
plant performance.

Nuclear generators presently  in  operation  fall  into  two
classes,  pressurized water reactors (PWR)  and boiling water
reactors (BWR).  In a PWR, water under a pressure  of  about
1U  MN/sq m  (2,000 psig) is heated as it circulates past the
nuclear fuel rods in a closed loop.   This  hot  water  then
exchanges  heat  with  a  secondary  water  system  which is
allowed to vaporize to steam.  In the BWR, water  heated  in
the  reactor core under a pressure of about 7 MN/sq m (1,000
psig)  is allowed to vaporize to steam directly.  Neither  of
these  processes  produce  steam with significant amounts of
superheat and this limits their thermal  cycle  efficiencies
to about 30%.

The  size  or  rating of boilers is in terms of thousands of
pounds of steam supplied per hour.  According to the FPC the
increase in boiler capacity was rather slow until 1955, when
the maximum capacity of boilers installed began to rise from
a level of about 1,500  thousand  pounds  per  hour  to  the
present  level  of  about  10,000  thousand pounds per hour.
Prior to 1950, individual boilers were kept small, in  large
part because boiler outages were rather numerous, so that it
was  common  design practice to provide multiple boilers and
steam header systems to supply  a  turbine-generator.   Some
plants  report  to  the  FPC  that  the  steam  headers  are
connected to multiple turbine-generators.  Advances in metal
technology since 1950, with associated lower costs of larger
units, have made it economical  and  reliable  to  have  one
boiler per turbine-generator.
                           58

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Steam Expansion

The  conversion  of  the  pressure  energy of the steam into
mechanical energy occurs  in  the  steam  turbine.   In  the
turbine  the  steam  flows  through a succession of passages
made  up  of  blades  mounted  on  alternately  moving   and
stationary  discs.   Each set of moving and stationary discs
is called a stage.   The  moving  discs  are  mounted  on  a
rotating  shaft  while  the stationary discs are attached to
the turbine casing.  As the steam passes from disc to  disc,
it  gives  up  its  energy to the rotating blades and in the
process loses pressure and  increases  in  volume.   If  the
steam  enters  the turbine in a saturated condition, a small
portion of the steam will condense as it passes through  the
turbine.  One  reason for superheating or reheating steam is
to reduce this  condensation  and  the  mechanical  problems
associated with it.

There  are.  many  different  types  of  turbines and turbine
arrangements in use in steam electric  powerplants.   Almost
all  turbines in use in central generating plants are of the
condensing type, discharging the steam from the  last  stage
at  below  atmospheric  pressure.   The  efficiency  of  the
turbine  is  highly  sensitive  to  the   exhaust   pressure
(backpressure).   A turbine designed optimally for one level
of backpressure will not operate as efficiently at the other
levels of backpressure.   Some  turbines  designed  for  863
kg/sq m (2-1/2 in. of Hg abs) backpressure cannot operate at
1,730  kg/sq m  (5 in. of Hg abs) because of high temperature
in the last stages.  In general, turbines designed for once-
through cooling systems will generally be operated at  lower
backpressures   than   those  designed  for  closed  cooling
systems.  Moreover,  if  a  turbine  designed  for  the  low
backpressures  corresponding  to once-through cooling system
is  operated  instead  with  a  closed  cooling  system,  an
incremental  decrease  in  turbine  efficiency  will  result
during times when the back pressure is higher than it  would
have been for once-through cooling.

In  most  turbine arrangements a portion of the steam leaves
the casing before the final stage.  This type of turbine  is
called  an  extraction turbine.  The extracted steam is used
for feedwater heating purposes.  In some turbines, a portion
of the steam is  extracted,  reheated  in  the  boiler,  and
returned  to the turbine or to another turbine as a means of
improving overall  efficiency.   Many  different  mechanical
arrangements  of  high pressure and low pressure turbines on
one or more shafts are possible, and have been utilized.

While there are no major effluents associated with the steam
expansion phase other than those resulting from housekeeping
operations, the significance of the steam expansion lies  in
                            59

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its  effect on plant efficiency and therefore on the thermal
discharge.  In many plants, turbine design  will  be  a  key
factor determining the extent of the feasibility of convert-
ing a once-through cooling system to a closed system.

Steam Condensation

Steam electric powerplants use a condenser to maintain a low
turbine exhaust pressure by condensing the steam leaving the
turbine at a temperature corresponding to vacuum conditions,
thus  providing  a  high cycle efficiency and recovering the
condensate for return  to  the  cycle.   Alternatively,  the
spent  steam  could  be exhausted directly to the atmosphere
thus avoiding the requirement for  condensers  or  condenser
cooling   water,  but  with  poor  cycle  efficiency  and  a
requirement for  large  quantities  of  high  purity  water.
There  are two basic types of condensers, surface and direct
contact.  Nearly all powerplants use surface  condensers  of
the  shell  and  tube  heat  exchanger  type.  The condenser
consists of a shell with a chamber at each end, connected by
banks of tubes.  If all  of  the  water  flows  through  the
condenser tubes in one direction, it is called a single-pass
condenser.   If  the  water  passes  through one half of the
tubes in one direction and the other half  in  the  opposite
direction,  it is called a two-pass condenser.  Steam passed
into the shell condenses on the outer surface of the  cooled
tubes.

A  single-pass  condenser  tends  to  require a larger water
supply than a two-pass condenser and will  generally  result
in  a  lower temperature rise in the cooling water.  In most
instances it will also produce a lower turbine backpressure.
A two-pass condenser is utilized  where  the  cooling  water
supply  is limited or in a closed system where it is desired
to reduce the size of the cooling device,  and  improve  its
efficiency by raising the temperatures of operation.

Many  condensers at the more-recently built powerplants have
divided water boxes so that half the condenser can be  taken
out  of  service for cleaning while the unit is kept running
under reduced loads.  Since cleanliness of the condenser  is
essential  to  maintaining maximum heat transfer efficiency,
it is common practice to add some type  of  biocide  to  the
cooling  water  to  control the growth of algae or slimes in
the condenser.  In spite of these biocides most  powerplants
clean condensers mechanically as part of regularly scheduled
maintenance  procedures.   Some plants employ continuous on-
line mechanical cleaning systems.
                            60

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Operation of the  condenser  requires  large  quantities  of
cooling  water.  Wherever adequate supplies of cooling water
are available, it has been common practice to  take  cooling
water  from a natural source, pump it through the condenser,
and discharge it to the same body of water from which it was
obtained.  This is known as a "once-through" system.  One of
the  major  considerations  in  siting  powerplants  is  the
availability  of  an  adequate  source of high-quality once-
through cooling water.  If  sufficient  water  for  a  once-
through  system  is  not  available and other considerations
prevail in determining the location of  the  plant,  cooling
water  must  be recirculated within the plant.  In this case
some form of cooling device,  an  artificial  pond  with  or
without  sprays, or a cooling tower must be provided to keep
the  temperature  from  rising  above  the   maximum   level
permissible or desirable for turbine operation.  Figure IV-5
shows  a  schematic  flow diagram of a typical recirculating
(closed) system utilizing cooling towers.   For  reasons  of
economy   closed   systems   typically   operate  at  higher
temperature differentials across the  condenser  than  once-
through  systems,  balancing the somewhat reduced efficiency
of the turbine against the lower quantity of  cooling  water
required,  and  therefore the smaller size and lower cost of
the cooling  device.   However,  since  nearly  all  cooling
devices  currently  in  use obtain their cooling effect from
evaporation, the dissolved solids  concentration  of  closed
cooling  systems  tends to increase, eventually reaching, if
uncontrolled, a point where scaling of the  condenser  would
interfere with heat transfer.  A portion of the concentrated
circulating  water  must therefore be discharged continually
as blowdown to remove  dissolved  solids,  and  purer  fresh
water  must  be  provided  to  make  up  for  losses  due to
evaporation, blowdown, liquid carryover  (drift), and leaks.

Flow rates of cooling water vary with the type of plant, its
heat rate and the temperature rise across the condenser.   A
fossil  plant  with  a heat rate of 10,000 kJ/kwh  (9,500 Btu
per kwh) and  a  6.7°c   (12°F)  rise  across  the  condenser
(values   typical   of    plants   in   the  industry  using
once-through cooling systems) will require about 0.5 x  10-*
cu  m/sec   (0.8  gpn)  of  cooling  water  for  every  kw of
generating capacity.  A nuclear plant with a  heat  rate  of
11,100  kJ/kwh   (10,500  Btu per kwh) and a 11°C (20«F) rise
across  the  condenser,  (typical  of  plants  using  closed
cooling  systems)  will  require  about 0.46 x 10-* cu m/sec
(0.73 gpm).  Because of differences in thermal efficiencies,
nuclear plants under identical conditions require about  SOX
more cooling capacity than comparible fossil plants.
                         61

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                EVAPORATION
                    LOSS
 FRESH
 WATER
MAKE-UP
   AUXILARY
   COOLERS
      &
  CONDENSERS
      SPRAY &
   WINDAGE LOSS
                           COOLING
                            TOWER
   CHLORINE &
   TREATING
   CHEMICALS
     $\
V
                                        SURFACE
                                       CONDENSERS
                        PUMP BEARING COOLING
                                                     SLOWDOWN
                          PUMP GLAND COOLING
              FIGURE IV-5 SCHEMATIC COOLING WATER CIRCUIT
                                62

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While  both  once-through  and  closed  cooling  systems are
currently in use in the industry, the use of closed  systems
has  generally  been  dictated  by  lack of sufficient water
supplies to operate a once-through system and not  generally
by  considerations  of  the  thermal  effects of the cooling
water  discharge.   A  few  plants  have  installed  cooling
devices  on  their effluents to meet receiving water quality
standards and a few others have installed or are planning to
install cooling devices or to convert to closed  systems  in
order to meet receiving water temperature requirements.

Generating of Electricity

The  actual generation of electric energy is accomplished in
a generator, usually directly connected to the turbine.  The
generator .consists of a  rotating  element  called  a  rotor
revolving  in  a  stationary  frame  called  a  stator.  The
process converts mechanical energy into electric  energy  at
almost 100% of theoretical efficiency and therefore produces
little  waste heat.

Raw Materials

General  aspects  of  the  four  basic  fuels  in use in the
industry have been discussed in the  previous  section.   In
this  section  some  of  the  characteristics of each of the
fuels will be discussed as they affect the process  and  the
wastewater effluents produced.

Coal

Coals  are  ranked  according  to their geological age which
determines their fuel value and other characteristics.   The
oldest coals are the anthracites, which contain in excess of
92%  fixed carbon.  Most anthracite lies in a limited region
of eastern Pennsylvania and is not a  major  factor  in  the
nationwide generation of electric energy.  Most of the power
is produced from bituminous coal (the next lower rank) which
contains  between 50 and 92% fixed carbon and varies in fuel
value between 19,300 and 32,600 J/g (8,300  and  14,000  Btu
per  Ib).   A  substantial  amount of power is also produced
from lignite containing less than 50% carbon and  having  an
average heating value of 15,600 J/g (6,700 Btu per Ib).

Three  major  characteristics of coal that affect its use in
powerplants are  the  percentages  of  volatile  combustible
matter,  sulfur  and  ash.   The  sulfur  content of coal is
particularly  critical  since  air   pollution   limitations
restrict the emission of sulfur dioxide.  The sulfur content
of  U.  S.  coals  varies from 0.2 to 7.0 percent by weight.
                          63

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Most of the low sulfur coal deposits are located west of the
Mississippi River.  In the East, a large portion of the  low
sulfur  coal  has been dedicated to metallurgical and export
uses.

The ash content of coal varies from 5 to 20% by weight.  Ash
can create problems of air pollution, slagging, abrasion and
generally reduced efficiency.  One problem  of  substituting
low  sulfur  coal  for  coal with a higher sulfur content is
that low  sulfur  coals  tend  to  have  higher  ash  fusion
temperatures,  which may cause problems in boiler operation.
The fly ash produced by low sulfur coal tends to have higher
electrical  resistivity  which  reduces  the  efficiency  of
electrostatic precipitators.

Several  other  aspects of coal as a fuel for steam electric
powerplants should be noted.  The  first  is  the  increased
popularity  of  mine-mouth  plants, that is plants built for
the purpose of using coal from a specific mine  and  located
in the immediate vicinity of that mine.  Much of the current
construction  of  coal-fired  units  consists  of mine-mouth
plants.  These plants in effect trade off the cost of trans-
porting coal against the cost of transmitting the electrical
energy generated.  Their major advantages are that  in  most
cases that they are not located in or near urban centers and
therefore  do  not arouse public opposition or have the same
type of environmental impact as plants located within  those
centers.   Most mine-mouth plants are base-load operated and
many use cooling towers because of the absence  of  adequate
cooling  water  supplies.   They compete favorably on a unit
cost basis with nuclear plants and in many instances can  be
constructed with a substantially shorter lead time.

A  second  aspect  consists  of  the potential impact on the
industry of the successful development of a commercial-scale
coal  gasification  process.   A  number  of  processes  are
currently   under   development.    The  potential  of  coal
gasification lies in  its  ability  to  produce  a  storable
product that can be transported economically by pipeline and
can  be  burned  without  ash  or  sulfur  problems.  At the
present, the  estimated  cost  of  synthetic  gas  is  still
substantially  higher  than the cost of alternate fuels, but
upward pressures on natural gas and residual oil prices  may
make coal gasification economically attractive.

Natural Gas

The  use of natural gas as a fuel for generating electricity
is a fairly recent development, dating back to  about  1930.
In  1970  0.1  trillion cu m  (3.9 trillion cu ft) of natural
                           64

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gas were burned to generate electricity, placing natural gas
second among the fossil fuels and accounting for almost  30%
of the energy generated from fossil fuels.

The   original   attractions   of   natural   gas  were  its
availability and its economics.  For a long time natural gas
was considered almost a by-product.  At the same  time,  its
use  in  utility  powerpiants  resulted  in simpler and less
costly  fuel  handling,  burning  facilities  and  a  marked
reduction  in  ash  handling  and  air  pollution  problems.
However,  the  availability  of  natural  gas  has  declined
sharply  in the last few years, and utilities are finding it
increasingly difficult to conclude long-term agreements  for
natural  gas  supplied  for  central generating plants.  The
future availability of natural /gas  is  uncertain.   Present
reserves  of natural gas amount to an estimated twelve times
our current annual production, and the annual  discovery  of
new sources is less than the current rate of consumption.

Estimates  by  the  FPC  project  a  fairly  stable level of
natural gas consumption by  the  electric  utility  industry
over  the  next  twenty  years.   However,  in  view  of the
projected growth of the industry as a whole,  the  share  of
the  total  electricity generated is expected to decrease to
6% by  1990.   This  trend  could  be  affected  by  several
technological  developments.  One of these is the successful
commercial application of coal gasification.  Another is  an
AEC  program  to  increase  the  yield  of  natural gas from
underground  formations  by  the  underground  explosion  of
nuclear  devices.   In  the  meantime,  some existing plants
using natural gas as a fuel were being converted to  oil  in
spite  of  the  advantages of natural gas in the ash and air
pollution areas.

Fuel Oil

Fuel oil is presently the third most significant  source  of
fossil  fuel  for generating electricity, accounting for 15X
of the total  generation  in  1970.   However,  in  the  New
England-  Middle  Atlantic  area it accounted for 82* of the
thermal generation, primarily as a result of the  conversion
of coal-burning plants to residual fuel oil in order to meet
air pollution standards.

Three  types  of  fuel  oil are used in utility powerplants:
crude oil, distillate oil, and residual oil.  A key  problem
with  the  use  of fuel oil, as with the use of coal, is the
sulfur content.  At the present  time,  powerplants  in  the
Northeast  are burning oil containing less than 1% sulfur by
weight.  Domestic supplies of low sulfur  crudes  are  quite
                            65

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limited  and will not be improved significantly when Alaskan
oil is available in the  contiguous  United  States.   As  a
result,  utilities  have  been  highly  dependent on foreign
sources of supply.  Major foreign sources include Venezuela,
and the Middle East.  Venezuelan sources must be,  and  are,
desulfurized  at the source, while Middle Eastern crudes are
low in sulfur in their original state.

With the future availability of petroleum  products  of  all
types in question, it appears doubtful that the recent trend
toward increased burning of oil in powerplants will continue
in  the  future.   FPC projections (1970) indicated a slight
increase in the percentage share of oil  compared  to  total
use  of  fossil  fuels  over  the  next  five  years, with a
leveling off thereafter.  The price of fuel oil,  which  had
remained   fairly  constant  during  the  early  1960's  has
increased  in  recent  years,  and  will  possibly  increase
further in the future.

A  possible technological development which might affect the
supply of fuel oil is the extraction of oil from oil shales.
Certain areas of Colorado, Utah and  Wyoming  contain  large
reserves  of oil shale, with unfavorable economics being the
major  obstruction  to  the  development  of  an  oil  shale
industry.   If crude oil prices continue to escalate and oil
supplies continue to dwindle, the development of this source
may become economically viable.

Fuel oil use in powerplants minimizes bottom  ash  problems,
although  fly ash can continue to be troublesome.  Some fuel
oils also contain vanadium and  may  contain  other  unusual
components  which  may  or  may  not wind up in a powerplant
effluent.

Refuse

Emphasis on recycling waste products has increased  interest
in  use  of  another fuel - solid waste.  Refuse and garbage
are not confined to kitchen wastes, but include a mixture of
all household wastes with commercial and industrial  wastes.
Large-scale  inorganic  industrial  wastes are generally not
included.  The average American  domestic  refuse  has  many
combustibles  which raise its heating value to approximately
HQ% of  that  of  coal.   Incineration  coupled  with  steam
generation  has  been practiced for a considerable period in
Europe, where  household  garbage  as  collected  is  mixed,
especially  during  the  winter  months,  with  the ashes of
household coal furnaces.  Garbage is generally shredded  and
most   non-combustibles   are   removed   by   magnetic  and
centrifugal  separators  before  firing  to   the   furnace.
                           66

-------
However,  furnaces must still be designed for non-combustible
loadings.    Garbage  is  essentially  sulfur-free  but  can
generate  moderate quantities of hydrogen chloride  from  the
combustion  of  polyvinyl  chloride  and  other  chlorinated
polymers.   Because  of  the  presence  of  these  materials,
studies   of the removal of acid gases from the furnace stack
gases, and  the disposal  of  the  effluents  resulting  from
these operations should continue.

At  the   present  time there is one powerplant in the United
States that burns refuse as part of its fuel.  The plant has
the capability of using as much as 20% refuse with at  least
80% coal, although  operation to date has been limited to 10%
refuse and  90% coal.

Information on U. S. Generating Facilities  (Size and Age)

An  inventory of operating steam electric powerplants in the
United States is presented in Appendix  1  of  this  report.
The  list  has  been  divided into ten sections to conform to
the ten EPA regions of the country.  The inventory shows the
operating utilities by states, plants,  and  their  specific
geographic  location.  It also shows the total plant capacity
in  megawatts,  with  an  indication of whether the plant is
nuclear or  fossil-fueled, and a designation of  plants  that
are  under  construction.  Gas combustion turbine facilities
operating within fossil-fueled generating plants  have  been
indicated on a separate line.

The  inventory  shows a total of 1,037 operating generating
plants in the United  States as of January !=•/ 1972,  consist-
ing  of   1011  fossil-fired plants and 26 nuclear plants. -A
total of  59 plants  were under construction as  of  the  date
indicated.   Of this  total, 42 are nuclear plants and 17 are
.fossil-fueled plants.  Table IV-1 provides a summary of  the
industry  inventory  by EPA region and individual states.

Figures   IV-6  through  IV-8  provide a cumulative frequency
distribution plot of  plant size within  the  steam  electric
powerplant  industry.   It can be seen from Figure IV-6 that
approximately 50 percent of the plants in the  industry  are
100  Mw   or larger,  and  that 25 percent of all plants are
larger than 400  Mw.   Figure  IV-7  shows  that  the  size
distribution  of fossil-fueled plants roughly corresponds to
the industry profile.  However, Figure IV-8 illustrates  the
large  size of  nuclear  plants, showing that 50 percent of
these plants are larger than 800 Mw, and that 25 percent are
larger than 1,500 Mw.
                               67

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                     TABLE IV-1
              INDUSTRY INVENTORY SUMMARY
OPERATING PLANTS
STATE
EPA Region 1
Connecticut
New Hampshire
Rhode Island
Vermont
Maine
Massachusetts
EPA Region 2
New Jersey
New York
Puerto Rico
Virgin Islands
EPA Region 3
Delaware
Maryland
Pennsylvania
Virginia
West Virginia
District of Columbia
EPA Region 4
Alabama
Florida
Georgia
Kentucky
Mississippi
North Carolina
South Carolina
Tennessee
EPA Region 5
Illinois
Indiana
Michigan
Minnesota
Ohio
Wisconsin
EPA Region 6
Arkansas
Louisiana
New Mexico
Texas
Oklahoma
EPA Region 7
Iowa
Kansas
Missouri
Nebraska
EPA Region 8
Colorado
Montana
North Dakota
South Dakota
Utah
Wyoming
EPA Region 9
Arizona
California
Hawaii
Nevada
EPA Region 10
Alaska
Idaho
Oregon
Washington
TOTAL

16
5
5
4
6
29

18
39
4
2

5
14
48
15
12
2

10
43
13
19
9
12
16
7

45
29
40
48
54
33

10
27
16
91
19

37
32
31
15

23
8
9
9
6
8

12
39
7
6

14
1
6
9
FOSSIL

13
5
5
3
6
28

17
36
4
2

5
14
45
15
12
2

10
43
13
19
9
12
15
7

43
29
38
45
54
31

10
27
16
91
19

37
32
31
15

23
8
9
8
6
8

12
37
7
6

13
1
6
9
NUCLEAR

3
0
0
1
0
1

1
3
0
0

0
0
3
0
0
0

0
0
0
0
0
0
1
0

2
0
2
3
0
2

0
0
0
0
0

0
0
0
0

0
0
0
1
0
0

0
2
0
0

1
0
0
0
FOSSIL
0
0
0
0
0
0
0
1
0
0
0
0
0
0
1
0
0
0
3
2
0
1
1
1
1
1
2
0
0
0
0
1
0
1
0
0
0
0
0
0
0
0
0
0
0
1
0 •
0
0
0
0
0
0
NUCLEAR
0
0
0
0
1
1
1
2
0
0
0
1
2
2
0
0
3
4
1
0
0
2
1
1
3
0
4
1
3
1
1
1
0
0
0
1
0
0
2
1
0
0
0
0
0
0
2
0
0
0
0
0
0
TOTAL
1037    1011

   68
                                     26
                                                17
                                                        42

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o
o.
o
o
             CUMULRTIVE  FREQUENCY  DISTRIBUTION OF

                 ENTIRE  POWER PLflNT  INVENTORY

                       FOR RLL EPR  REGIONS
o
o
o
rj_
o
o
o
CO-
         12.50    25.00    37.50   50.00    62.50    75.00    87.50    100.OC

    PERCENT OF  PLRNTS EQURL TO  OR  LRRGER THRN  STRTED SIZE
                             FIGURE  IV-6


                               69

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o
O-
O
o

o
CD-
CO
o
o

o
CM-
PI
O
O
CUMULATIVE  FREQUENCY  DISTRIBUTION OF

     FOSSIL-STEflM POWER  PLflNTS

          FOR flLL EPfl  REGIONS
   0     12.50    25.00    37.50   50.00    62.50    75.00   87.50    100.OQ
    PERCENT OF PLflNTS EQUflL TO  OR  LflRGER THflN  STflTEO SIZE
                              FIGURE IV- 7
                               70

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  O
  O

00
.—zr.
~ c\j
5°
 ro'

uLj
rvj
•-S.
 o
 C\J.
 o.
 CD
 O
 o
 o.
 Of
 o
 o
               CUMULflTIVE  FREQUENCY  DISTRIBUTION OF

                    NUCLERR-STERM  POWER PLRNTS

                         FOR RLL  EPR  REGIONS
0    12.50    25.00    37.50    50.00    62.50    75.00    87.50
 PERCENT OF  PLRNTS EQURL  TO OR LRRGER THRN  STRTED SIZE
                                                                 100. OC
                             FIGURE IV- 8


                               71

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The Federal Power Commission Form 67, "Steam-Electric  Plant
Air  and  Water  Quality  Control  Data  for  the Year Ended
December  31,  1969"   provides   data   on   the   capacity
utilization, age, etc., of generating units.  This form must
be filed annually by plants with a generating capacity of 25
Mw or greater, provided the plant is part of a system with a
total capacity of 150 Mw or more.

Size of Units

According   to  the  Federal  Power  Commission  (FPC)  1970
National Power Survey, in 1930, the  largest  steam-electric
unit  in  the United States was about 200 megawatts, and the
average size of all units was 20 megawatts.  Over 95 percent
of all units in operation at that time had capacities of  50
megawatts  or less.  By 1955, when the swing to larger units
began to be significant, the largest unit size had increased
to about 300 megawatts, and the average size  had  increased
to  35  megawatts,  (see  Figure  IV-9).  There were then 31
units of 200 megawatts or larger.  By 1968, the largest unit
in operation was 1,000 megawatts; there were 65 units in the
400 to 1,000 megawatt range; and the average  size  for  all
operating units had increased to 66 megawatts.  In 1970, the
largest   unit   in   service  was  1,150  megawatts;  three
1,300-megawatt units  were  under  construction;  and  three
additional  1,300-megawatt units were on order.  The average
size  of  all  units  under  construction  was   about   U50
megawatts.   As the smaller and older units are retired, the
average size of units is expected to increase to  about  160
megawatts by 1980 and 370 megawatts by 1990.

The  distribution  of U.S. generating capacity by size, as a
percentage  of  the   generating   capacity   installed   in
particular years, is given in Table IV-2.

Age of Facilities

In the steam electric powerplant industry, age of generating
facilities  must  be  discussed on the basis of units rather
than on a plant basis.  Generally, the  units  comprising  a
generating plant have been installed at different times over
a  period  of  years,  so that the age of equipment within a
given plant is likely to be  distributed  over  a  range  of
years.   In  addition,  age  may  play  a  peculiar  role in
assigning a unit to a particular type of operation  as  out-
lined below.

In  general,  the thermal efficiency of newly designed power
generation plants has increased as operating experience  and
design  technology  have progressed.  Early plants generated
                             72

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           Figure IV-  9
LARGEST FOSSIL-FUELED STEAM-ELECTRIC
    TURBINE-GENERATORS IN SERVICE
               1900 - 1990
   2500 r
   2000
   1500
   1000
    500
                       292
      1900
1930
  YEAR
1960
1990
                  73

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                 Table IV-2
DISTRIBUTION OF  INSTALLED GENERATING CAPACITY IN THE U.S. BY SIZE
   FOR VARIOUS YEARS WHEN EQUIPMENT WAS FIRST PLACED IN SERVICE
Generating
megawe
0 -
25 -
100 -
300 -
500 -
Capacity,
itts
24
99
299
499

Year
1945
18
58
24
0
0
in Which
Equipment
1955 1960
8
26
66
0
0
4
13
56
27
0
1965
0
12
55
25
8
was First
1970
1
4
32
32
31
Placed
1972
0
1
13
13
73
in Service
1974
0
3
3
10
84
1970-1974
0
1
13
15
71

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saturated  steam  at  low  pressures  and   consumed   large
quantities  of  fuel to produce a unit of electrical energy.
One electrical kilowatt hour of energy is equivalent to  860
k  cal  (3,413  Btu)  of  heat  energy.  Steam pressures and
temperatures increased from about 1.17 MN/sq m (170 psig)  at
the turn of the century to 1.72 - 1.90 MN/sq m  (250  -  275
psig)   and  293°C (560°F) by World War I, and to 3.10 - 4.48
MN/sq m (450-640 psig) and 370-400<»C  (700-750°F)   by  1924.
«»•   In  1924  and  1925  there was a surge to 8.27 MN/sq m
(1,200 psig) and 370°C (700°F) and it has steadily increased
since then, until by 1953 pressures had reached the critical
pressure  of  steam   (22.11  MN/sq  m    (3,206   psia)   and
temperatures  of  540-565°C   (1,000-1,05p°F).*»•   Above the
critical  pressure  the  liquid   and   vapor   phases   are
indistinguishable  and  there  is  no  need for a steam drum
(separator).    The   economic    justification    of    the
supercritical cycle has resulted in a limited number of this
type of unit to date.

These  changes have had the effect of reducing the amount of
fuel required to generate  a  kilowatt  hour,  as  shown  in
Figure  IV-10,  taken  from  Reference  No. 292.  In 1900 it
required 2.72 kg (6 pounds) of coal,  (41,700 k  cal   (75,000
Btu)   to   generate   one   kwh.   Today  a  supercritical,
double-reheat unit of Plant  no.  3927  has  established  an
annual  heat  rate  of  2197  k cal/kwh  (8,717 Btu/kwh). "°
This amounts to 0.318 kg (seven-tenths of a pound)  of  coal
per  kwh.   The  heat  economies  of  the  newer  facilities
generally make  it  desirable  to  keep  them  in  full-time
base-load operation.  The older units with their higher fuel
consumption  are therefore generally relegated to cycling or
peaking service.  In spite of this general trend, there  are
indications  that heat rates have been increasing since 1972
as a result of pressures to reduce capital cost in  relation
to  fuel  prices,  and  increasing  use  of  air  and  water
pollution control equipment which tend to reduce  generating
efficiency.

A  computer plot of heat rate in Btu/kwh vs unit capacity in
megawatts  (x 10) is shown in Figure IV-11.  The  plot  is  a
print-out . of  data  obtained  from FPC Form 67 for the year
1969.  In the plot, data obtained from newer  plants   (under
10  years old) are represented by squares, those 10-20 years
old  by  triangles,  and  those  over  20  years   by   X's.
Similarly,   Figure   IV-12   is  a  printout  of  the  same
information replotted with Btu/kwh as the ordinate and  unit
age  as  the  abscissa.   The data from both plots represent
over 1,000 operating units, and are not conclusive,  but  do
show  general  trends.   The  newer  plants, of larger size,
generally are more efficient.  Thus the data illustrates the

-------
   30,000 p
   25,000 -
   20,000 -
1

-------
                                     LEGEND
                             m UNITS UNDER 10 TERRS OLD
                             * 10 TO 20 TERRS OLD
                             X OVER 20 TEflRS OLD
"tToo
      20.00   10.00   60.00   80.00
            UN'IT CflPflCITT  (MW)
100.00   120.00   140.00   160.00
      *10'
      HEflT  RRTE  VS  UNIT  CflPRCITT
                      Figure IV-1

                          77

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 o
 o
                                     LEGEND

                             D UNITS UNDER 100 MW

                             A 100 TO 300 MW

                             X OVER 300 MW
 o
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 o
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 X

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a a
                                                      a
                                                      a
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        5.00
             10.00   15.00   20.00   25.00   30.00   35.00   40.00

               UNIT flGE IN TERRS
       HERT  RflTE   VS0  UNIT  RGE
                         Figure IV-12



                            78

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improvement in  efficiency  achieved  as  the  industry  has
progressed to newer and larger generating facilities.

Mode of Operation (Utilization^

The need for considering a subcategorization of the industry
based  on  utilization  arises  because  of  the  costs  and
economics associated with the installation  of  supplemental
cooling  facilities.   The  unit  cost increment (mills/kwh)
required to amortize the capital costs of the cooling system
is dependent on the remaining kwh's  that  individual  units
will  generate.   The  remaining generation is a function of
both the manner in which the individual unit is utilized and
the number of years that the  unit  will  operate  prior  to
retirement.   These  two  factors  are not fully independent
variables.  In general, utilities  will  employ  their  most
efficient,  usually newest equipment most intensively.  This
equipment will also generally  have  the  longest  remaining
useful  life.   The  cost of installing supplemental cooling
water equipment for these units relative  to  the  remaining
generation  will  therefore  be  relatively low.  Therefore,
these more modern, highly-utilized units, which  also  would
reject  relatively  large  amounts  of  the  waste heat, are
better able to  carry  the  costs  associated  with  thermal
effluent control.

Less  efficient, usually older equipment will be utilized to
a lesser degree to meet daily and seasonal peak loads.  This
lower annual utilization is compounded by the fact that this
equipment has relatively fewer remaining  years  of  service
prior  to  retirement.   Therefore,  the  cost of amortizing
supplemental cooling  equipment  for  these  units  will  be
substantially   higher  than  for  the  newer,  more  highly
utilized units.  Because of  their  low  utilization,  these
units  will  reject  considerably  less  heat  per  unit  of
capacity than the newer equipment.   Also,  because  of  the
higher costs associated with this equipment, utilities might
consider  early  retirement of much of this equipment rather
than the installion of costly  treatment  equipment.   Since
these  units  provide  an  important  function as peaking or
standby capacity, retirement prior to  the  installation  of
replacement capacity would have associated penalties.

According  to  the  FPC National Power Survey (1970), all of
the    high-pressure,    high-temperature,     fossil-fueled
steam-electric  generating  units, 500 megawatts and larger,
have been designed as "base load" units and built  for  con-
tinuous  operation  at or near full load.  Daily or frequent
"stops" and "starts" are not consistent  with  their  design
and   construction  and  so-called  "cycling"  or  part-time
                          79

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variable generation  was  not  originally  comtemplated  for
these  units.   However,  by  the  time  units  having lower
incremental production costs become available for base  load
operation, it is believed that the earlier "base load" units
can  be  adapted  and  used as "intermediate" peaking units.
The units placed in service during the 1960•s still have  15
or  more  years  of  base  load  service  ahead of them, but
eventually the installation of  more  economical  base  load
equipment  may  make  it  desirable  to  convert  to peaking
service those units which are suitable for such conversion.

New steam-electric peaking units, sometimes referred  to  as
mid-range  peaking  units,  are designed for minimum capital
cost and to operate at low capacity factor.  They  are  oil-
or  gas-fired,  with a minimum of duplicate auxiliaries, and
operate  at  relatively  low  pressures,  temperatures,  and
efficiencies.   They are capable of quick startups and stops
and variable loading, without jeopardizing the integrity  of
the  facilities.   Such  units  are  economical  because low
capital costs  and  low  annual  fixed  charges  offset  low
efficiency and operation at low capacity factors.  The units
can,  however,  be operated for extended periods, if needed,
to meet emergency situations.

The  first  of  such  fossil-fueled   steam-electric   units
designed  for  peaking  service,  a 100-megawatt, 1,450 psi,
1000°F, non-reheat, gas-fired unit, was installed  in  1960,
Two  earlier  low  capital cost fossil-fueled steam-electric
plants—a 69-megawatt, single-unit plant (1952), and a  313-
megawatt,  two-unit  plant (1954)—were generally classified
as  hydro  standby;   they   were   not   straight   peaking
installations.   The  313-megawatt  plant was later modified
for base load operation.

With  increasing  loads  and  the  accompanying   need   for
additional  peaking  capacity,  at least 27 peaking units of
this general type were on order or under construction at the
end of 1970.  All are either oil- or gas-fired, because  the
added  costs of coal and ash handling facilities for peaking
units are not justified by the small fuel cost  saving  that
might  be realized by using coal.  Eight of the 27 units are
in  the  250  to  350-megawatt   class,   fifteen   in   the
400-megawatt  class,  and  four  in  the 600-megawatt class.
Most of the units are designed for steam conditions of 1,800
psi and 950°/950°F.

The use of the nuclear power plant in conjunction with other
forms of generation in order to provide energy to  meet  the
daily  requirements  of  a power system will probably not be
vastly different from the use of a  fossil-fueled  plant  of
                           80

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the  same  capacity.   There  are some differences, however,
that may affect the operation of the nuclear plant, such  as
relative operating costs, refueling time and inspections.

Because an economic loading schedule for a power system will
tend to favor operation of units with the lowest incremental
production  cost,  the  capacity  factor of a nuclear fueled
plant is expected to be relatively high when it is added  to
a  system consisting of fossil-fueled plants.  However, when
newer, more  efficient  nuclear  plants  are  added  to  the
system,  which can operate with even lower production costs,
the first nuclear  plants  will  begin  to  have  decreasing
capacity factors.  Most of the plants that have been ordered
during  the  past  three  years  will  probably  have annual
capacity factors of 80 percent or better for a period of ten
to fifteen years, depending on  the  operating  requirements
and makeup of the system.

The   limited   operating   experience   to  date  with  the
comparatively small nuclear plants indicates that  they  are
able  to  handle  load  swings  without  difficulty.   It is
expected that the larger units now  on  order  will  perform
similarly, but it may develop that they will not be amenable
to   load   regulation.    In   that  event,  fossil  units,
pumped-storage units, conventional  hydro  units,  or  other
types  of peaking units will be installed to carry peak load
with  nuclear  units  being  maintained  at  base  load  for
substantially  all  of their useful lives.  If nuclear units
are to be utilized with very low  annual  capacity  factors,
substantial research and engineering effort must go into the
determination  of  core  designs  to economically accomplish
this type of operation.

Base-load units are responsible for the bulk of the  thermal
discharges,  will  continue  to operate for many more years,
and  are  able  to  support  the  required  technology  with
relatively  small  increases  in  the bus-bar cost of power.
The balance of the steam-electric power generation inventory
is made up of older  equipment,  which  reject  considerably
less  heat  and for which the cost of installing control and
treatment technology would be considerably  higher  relative
to   the   effluent  reduction  benefits  obtained.   It  is
understood that considerable abatement will  take  place  in
time  in  this  older portion of the inventory due to normal
attrition.

Traditionally,  the  power   industry   has   employed   two
categories   for   generating  equipment.   Units  that  are
continuously  connected  to  load,  with  the  exception  of
scheduled  and  unscheduled  maintenance  periods, have been
                            81

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termed base-loaded units.  Units which are operated to  meet
seasonal  peak  loads have been termed peaking units.  Daily
load swings have usually been met by modulation of the base-
loaded  units.    More   recently,   the   increased   cycle
sophistication  built  into  the newer base-loaded equipment
has made them less efficient in  accommodating  large  daily
load  swings.   Therefore,  a  third type of capacity called
cyclic or intermediate generation unit has come into general
acceptance within the industry.  This third type of unit  is
usually  a  downgraded base-loaded unit which can be adapted
to the intermittent operation with fairly rapid load swings.

The progression of individual units of capacity through  the
three  types  of  duty  assignments  generally  follows  the
sequence given below:

    1.  New steam electric capacity  has  historically  been
added  as  base-load  units.   All  but a few existing steam
electric generating  units  were  at  one  time  base-loaded
units.   Beginning  in  the  middle  1960's some new peaking
units, both steam electric and gas turbine types  have  been
constructed.   More  recently  (late  1960's  early  1970»s)
several units of the combined  (gas  turbine/steam  turbine)
cycle  design  have been designed specifically for cyclic or
intermittent duty.  The aggregate existing capacity of units
or.  inally  built  for  peaking   or   cyclic   service   is
considerably  less  than  151  of  the  total  steam electric
inventory.

    2.  Cycling  capacity  and  peaking  capacity  has  been
obtained by downgrading the older less efficient base-loaded
equipment  as  more  efficient replacement capacity has been
built.  The manner in which a  unit  is  downgraded  depends
upon   the   needs   of   the  individual  utility  and  the
requirements of its system load curve.  Toward  the  end  of
its  usefx\ life, the unit may be held in standby duty to be
used only in the event of an outage to the other units.

    3.  Units have been retired from  the  bottom  level  of
utilization.    Therefore,  retirements  of  steam  electric
capacity  have  generally  been  made   from   the   peaking
inventory.   While  the  annual retirement of steam electric
powerplant capacity have been significantly less than 1%  of
the  total  capacity,  this amount constitutes a significant
portion of the present peaking inventory.

The typical utility makes duty assignments by comparing  the
capability  of  its  available  generating units against the
requirements of its system  load  curve.   Efficient  system
operation  dictates  that  the  most  efficient equipment be
                            82

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operated continuously.  These are the base-loaded units.   In
descending order, the less efficient equipment  is  assigned
lower utilization duty to meet daily and seasonal variations
in the load curve.  The process of matching capacity to load
is  different  for each utility.  The system load curve will
be different for each utility as will the capability of  its
individual generating units.

Large  systems  will have sufficient diversity of load which
will dampen extreme peaks and valleys in the  characteristic
load curve.  They will also have multiple units serving each
of  the load segments and considerable flexibility in making
duty assignments.  Individual  large  industrial  loads  may
dominate  the  system  load  curve for smaller utilities and
highs and lows  of  load  may  be  more  exaggerated.   Duty
assignments  for smaller systems will be more constrained by
the lack of multiple units and single  units  may  be  found
which service all three load segments.  Duty assignments are
also  influenced  by the needs of the regional power grid in
which  most  utilities  participate  through  a  series   of
agreements governing interconnections.

The  diversity  in  both  load  and  available capacity com-
plicates the process of establishing concrete limits between
the three types  of  generating  equipment.   The  following
bases  of  establishing definitions of base-load, cyclic and
peaking units have been considered.

    1.  Qualitative  descriptions  of  the  three  types  of
operation.

    2.  Annual hours of operation.

    3.   Plant  index  numbers such as load factor, capacity
factor, utilization factor, etc.

The relative merits of definitions based  on  these  systems
are   discussed  below.   The  ideal  definition  should  be
relatively easy to employ, allow effective separation of the
three types of generation, and be understood and accepted.

Definitions Based on Qualitative Description  of  the  Three
Types of Generation

This  would  rely  on  a  description  of the three types of
generation  as   the   basis   of   separation.    Suggested
definitions of the three types of generation are as follows:
                           83

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A base-loaded unit is one which is continuously connected to
load   except   for  periods  of  scheduled  or  unscheduled
maintenance.

A cycling unit is one which services daily  load  variations
above  the  base-load.   This  type  of  unit  is  typically
connected to load some 250  days  per  year  for  a  typical
period  of  about  12 hours.  When not connected to load the
boiler is kept warm to allow rapid return to the system.

A peaking unit is one which is operated to meet  peak  loads
only.   During periods when the unit is not generating power
it is held in standby or is shut down.


Annual Hours of Operation

It is clear that a basic difference between the three  types
of generation is the amount of time that the different units
operate.

Reference 292, Part II suggests that steam peaking units are
designed   to  operate  less  than  2,000  hours  per  year.
Reference 256 indicates  that  base-load  units  operate  in
excess of 6,000 hours per year.  Units which operate between
these  two  limits  would  be defined as cycling units.  The
hours of operation referred to in this system are hours that
the unit is connected to load.  Hours  of  boiler  operation
are  not  satisfactory.  There is considerable difference in
hours of boiler operation and hours connected  to  load  for
cycling  and  peaking  units.   Hours of condenser operation
could be used as a substitute  since  it  is  equivalent  to
hours  connected to load.  See Table IV-3 for the heat rate,
service life, and capacity factors characteristic  of  units
within the above groupings based on hours of operation.

Historical records of annual hours of operation are required
to  employ  this sytem.  There will be instances where base-
loaded units will have been operated less than  6,000  hours
per  year  because of extended maintenance requirements.  On
the other hand there will be cases  of  stretching  out  the
operating  schedules of peaking and cycling units because of
capacity shortage in particular systems.  This  system  does
have  the  advantage of a basic simplicity in discriminating
between the different categories of generation.

Performance Indices

This would require relating the utilization  of  a  unit  to
indices  of  its  performance.  Several of these indices are
described below.
                           84

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                                      Table IV-3



                          CHARACTERISTICS OF UNITS BASED ON ANNUAL

                                HOURS OF OPERATION
oo
en
Annual Hours of
Operation
0 - 2000
2000 - 6000
6000 - 8760
Heat
Min.
8727
8735
8706
Rate,
Mean
15793
12493
10636
Btu/kwhr
Max.
27315
27748
26741
Remaining Service? yr
Min. Mean Max.
1
1
1
11 26
15 26
19 32
Capacity Factor
Min. Mean Max.
.01 .07 .17
.03 .35 .71
.15 .67 1.12
               Note:  Based on a total service life of 36 years.

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Load Factor

Load factor is the ratio of the  average  demand  for  power
(kilowatts)  over  a designated period to the maximum demand
for power occurring in that period.  The average  demand  is
the  total  (kilowatt-hours)  for  the period divided by the
total time span (hours).  For example, in the twelve  months
ended  December  31, 1971, the electric energy generated and
purchased less sales to other electric utilities amounted to
35,720,253,101 kilowatt-hours.   The  one-hour  net  maximum
demand  was  7,719,000  kw.   The average hourly demand was,
consequently, 35,720,253,101 / 8760  =  4,078,000  kw.   The
annual   system  load  factor  is,  therefore,  4,078,000  /
7,719,000 = 0.528 or 52.8*.  The load factor may be regarded
as providing some measure of the variation of demand  during
a  given  period.    Thus,  if the load factor is 100* over a
period of 21 hours, the demand has been maintained  constant
for the duration of the period.

Operating Load Factor

If  the  maximum  demand  varies  from  day to day, then the
operating load factor is the ratio of the average demand  to
the  average  value  of  the maximum demands for the period.
For example, the daily maximum demands for a ten-day  period
and the corresponding kilowatt-hours are as follows:

                       Maximum Demand        Kilowatt Hours
     Day               	kw	        	Per day

      1                   1,000                 19,200
      2                     950                 13,700
      3                     800                 14,400
      4                     980                  9,700
      5                     700                 10,900
      6                     850                 18,000
      7                     500                  7,000
      8                     750                 10,000
      9                     820                  9,100
     10                     900                 12.000

             Totals       8,250                124,000

    Maximum Demand                             1,000 kw
    Average Maximum Demand = 8,250 / 10 =        825 kw
    Average Demand = 124,000 / (10 x 24) =       517 kw

    Load Factor =  (517 / 1000) x 100 =            51.7%
    Operating Load Factor = (517 / 825)  x 100 =   62.6%
                               86

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Thus the operating load factor takes into account the varia-
tion of the daily maximum demand.

Capacity Factor

Capacity  factor  defines the relation between energy output
over  a  given  time  span  and  the  capacity  for   energy
production  over  the  same time span, and normally provides
measure of  the  utilization  of  the  generating  equipment
relative  to investment.  This factor is also a ratio of the
average load to the total rating of the installed generating
equipment for a given period.  For example,  in  the  twelve
months   ended   December   31,  1970,  one  unit  generated
4,465,175,600  kilowatt-hours  (exclusive  of  gas   turbine
generation).   The maximum unit capacity (winter rating) was
878,000 kw.  The average hourly  load  was  4,465,175,600  /
8760 = 509,723 kw.  The annual capacity factor is therefore,
509,723 / 878,000 = 0.5806 or 58.1%.

Operating Capacity Factor

Although  a  plant may have installed equipment of a certain
amount of generating capacity, only part of this may  be  in
actual  operation  for  the  given  period.   Suppose  for a
certain generating  plant  the  capacity  of  the  installed
equipment  is  770,000 kw and for some particular month only
600,000 kw of boiler capacity is actually  operating.   This
means  that  the  maximum  demand that can be imposed on the
plant is limited to  600,000  kw.   The  operating  capacity
factor  for  the  month  would  then  be in the ratio of the
average demand for power to 600,000 kw, the maximum capacity
utilized.  This factor therefore,  determines  the  relation
between  average  output and the peak demand for power which
the plant is prepared to meet.

Use Factor

This  term  is  generally  used  in  connection   with   the
performance  of  turbo-generators.   It  is the ratio of the
actual energy output of a machine during a certain period to
the energy generation which could have been obtained  during
the  actual  operating hours in that period by operating the
machine at rated capacity.  A turbo-generator operating  for
7,000 hours generated 350,000,000 kilowatt-hours.  The rated
capacity  of  the  unit  is  100,000 kw.  The use factor was
350,000,000 /  (100,000 x 7,000) = 0.5 or 50%.
                           87

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Section 301 (b)  of the Act requires the Administrator to take
into account, in determining the applicable control measures
and practices, the total cost of application  of  technology
in  relation  to  the  effluent  reduction  benefits  to  be
achieved from such application.  Among  the  above  factors,
the  capacity  factor  alone  would determine, for otherwise
similar  circumstances,  the  incremental  production   cost
associated   with   the  application  of  pollution  control
technology in relation to the effluent reduction benefits to
be achieved.

The  1970  National  Power  Survey  by  the  Federal   Power
Commission   (FPC)  describes  base-load,  intermediate,  and
peaking units as follows.  Base-load units are  designed  to
run more or less continuously near full capacity, except for
periodic  maintenance shutdowns.  Peaking units are designed
to supply electricity principally during  times  of  maximum
system  demand and characteristically run only a few hours a
day.   Units  used  for  intermediate  service  between  the
extremes  of  base-load  and peaking service |inust be able to
respond readily to swings in  systems  demand,  or  cycling.
Units  used  for  base-load  service  produce 60 percent, or
more, of their intended  maximum  output  during  any  given
year,  i.e.,  60  percent, or more, capacity factor; peaking
units less than 20 percent;  and  cycling  units  20  to  60
percent.   The FPC Form 67, which must be submitted annually
by all steam electric plants (except small plants or  plants
in small systems) reports annual boiler capacity factors for
each  boiler.   The  boiler capacity factor is indicative of
the gross generation of the associated generating unit.

Site Characteristics

Engineering criteria require an adequate supply  of  cooling
water,  adequacy  of fuel supply, fuel delivery and handling
facilities, and  proximity  of  load  centers.   These  have
always been important factors in the selection of powerplant
sites.  29«   Traditionally,  plants have been located in or
near population centers to  reduce  transmission  costs  and
satisfy  the  other  key site factors mentioned.  Table IV-4
shows a total of 153 plants located in the 50 largest cities
of the country.   This  total  represents  approximately  15
percent  of all plants in the industry, and does not include
suburban plants near the cities in question, or urban plants
in  smaller  population  centers.   Clearly,  a  significant
number  of  existing plants in the steam electric generating
industry are situated in locations which  interface  with  a
reasonable percentage of the country's population.
                           88

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                                    Table IV-4

                      URBAN  STEAM ELECTRIC  POWER  PLANTS
NO.
  1
  2
  3
  4
  5
  6
  7
  8
  9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
CITY
New York
Chicago
Los Angeles
Philadelphia
Detroit
Houston
Baltimore
Dallas
Washington
Cleveland
Indianapolis
Milwaukee
San Francisco
San Diego
San Antonio
Boston
Memphis
St. Louis
New Orleans
Phoenix
Columbus
Seattle
Jacksonville
Pittsburgh
Denver
Kansas City
Atlanta
Buffalo
Cincinnati
San Jose
Minneapolis
Fort worth
Toledo
Newark
Portland
Oklahoma City
Louisville
Oakland
Long Beach
Omaha
Miami
Tulsa
Honolulu
El Paso
St. Paul
Norfolk
Birmingham
Rochester
Tampa
Wichita
STATE
New York
Illinois
California
Pennsylvania
Michigan
Texas
Maryland
Texas
D.C.
Ohio
Indiana
Wisconsin
California
California
, Texas
Massachusetts
Tennessee
Missouri
Louisiana
Arizona
Ohio
Washington
Florida
Pennsylvania
Colorado
Missouri
Georgia
New York
Ohio
California
Minnesota
Texas
Ohio
New Jersey
Oregon
Oklahoma
Kentucky
California
California
Nebraska
Florida
Oklahoma
Hawa i i
Texas
Minnesota
Virginia
Alabama
New York
Florida
Kansas
POPULATION
7,894,862
3,369.359
2,809,596
1,950,098
1,513,601
1,232,802
905,759
844,401
756,510
750,879
744,743
717,372
715,674
697,027
654,153
641,071
623,530
622,236
593,471
581,562
540,025
530,831
528,865
520,117
514,678
507,330
497,421
462,768
452,524
445,779
434,400
393,476
383,818
382,288
380,555
368,856
361,958
361,561
358,633
346,929
334,859
330,350
324,871
322,261
309,828
307,951
300,910
296,233
277,767
276,554
NUMBER OF
 PLANTS
   12
    4
    4
    4
    6
    7
    6
    6
    2
    3
    3
    3
    2
    3
    7
    2
    1
    3
    4
    1
    3
    2
    3
    5
    3
    3
    1
    1
    2
    0
    2
    3
    2
    1
    2
    2
    4
    1
    2
    4
    1
    1
    1
    2
    2
    3
    2
    3
    4
    4
                                                      Total   152
                              89

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The trend in recent years toward larger units, combined with
the  advent  of  commercial nuclear power generation and the
institution of mine-mouth coal-fired plants has resulted  in
a greater number of plants being constructed in rural areas.
Site  selection  for  new  generating facilities is not only
governed  by  the  factors  cited,   but   increasingly   by
environmental considerations.  The prevention and control of
air  and water pollution is undoubtedly as important as many
of the traditional factors involved in the selection of  new
plant  sites.   Factors generally considered in decisions on
plant location include land requirements, water supply, fuel
supply and delivery, etc.

Land requirements are quite variable.  For  plants  situated
near population centers, land cost is a prime consideration.
The largest consumers of land are the fuel storage area, ash
disposal  area  and  water  cooling  ponds,  lakes  etc.  if
utilized.  Since they are public utilities, power generating
plants must have sufficient fuel storage capacity  to  allow
uninterrupted   operation   for  the  duration  of  a  major
transportation strike.  This means that unless the plant  is
very  near  its  source  of  supply,  it must have a storage
capability up to approximately  three  month1s  fuel.   Even
mine-mouth  plants  must  have fuel storage to allow them to
withstand a miners' strike.

Most steam plants require water  for  two  main  purposes  -
boiler  feed water make-up and steam condensation.  The cost
of preparation of the high purity boiler feed water required
by modern boilers is a function of the purity of the  source
water.   It  is  possible  to  use  saline water for cooling
purposes, but it cannot be used in a boiler.  Preparation of
boiler feed from saline  water  by  evaporation  or  reverse
osmosis  is  generally quite expensive.  The availability of
large quantities of cooling water has traditionally affected
the decisions made regarding plant location.  In areas where
water is critically short, recirculation  of  cooling  water
using  cooling  towers  or  ponds has been widely practiced.
This subject is discussed in detail in  subsequent  sections
of this report.

Plant  location may also be influenced by energy transporta-
tion  costs.   The  cost  of  transmission  of   energy   as
electricity must be weighed against the cost of transporting
fuel.   Generally,  fuel  availability  and economic factors
will be the major considerations regarding the  relationship
between fuel and plant siting.

The  trend  in  siting of generating plants using open-cycle
cooling is toward locations on oceans, estuaries and  lakes.
                            90

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Of  the plants installed near 1960, approximately 80% are on
rivers, 10% on lakes, 10% on estuaries and 2% used municipal
water.   For   the   plants   installed   in   the   1970's,
approximately  50-6OX are on rivers, 20-30% on lakes, 15% on
estuaries, 2% on municipal water and 2% on oceans.


The methods used to control atmospheric pollution  by  stack
gases  vary.   With plants burning solid fuel, a particulate
emission problem may exist.  The usual control system is the
electrostatic precipitator.  Finely divided solid  particles
suspended  in  a  gas  stream  will  accept an electrostatic
charge when they pass through an electrical field.  If  they
are  then passed between two oppositely charged plates, they
are attracted  to  one  of  the  plates,  depending  on  the
polarity of the charges.  On the plates they agglomerate and
may  be  removed  by  rapping the plates.  This operation is
usually carried out at temperatures between 121°  and  177°C
(250-350°F).  Finely divided solids may also be removed from
the  vent  gases  by  using  bag  filters  or  by intimately
contacting them with water in a venturi scrubber or similiar
device.

Sulfur dioxide  in  stack  gases  can  present  another  air
pollution   problem.    This,  of  course,  is  most  easily
controlled by firing low sulfur fuel, which  is  not  always
readily  available.  Many alternatives have been proposed to
remove the SQ2, and several are being used on  a  commercial
scale.   Most  involve  neutralization  of the acid SO2 with
alkaline  materials  such  as  soda  ash,  lime,  limestone,
magnesia  or dolomite, and ammonia.  The processes developed
to date consist of both once-through and recycle systems.  A
detailed analysis of air  pollution  control  systems  which
produce  a  liquid  waste  stream  is  presented  in another
section of this report.

Categorization

The Act requires, for the purposes of assessment of the best
practicable control technology currently available, that the
toal cost of application of technology in  relation  to  the
effluent   reduction  benefits  to  be  achieved  from  such
application be considered.  Other factors to  be  considered
are  the  age  of  equipment  and  facilities  involved, the
process employed, the engineering aspects of the application
of various types of  control  techniques,  process  changes,
nonwater  quality  environmental  impact  (including  energy
requirements) and other factors as deemed appropriate.   For
best  available  technology  economically achievable the Act
substitutes "cost of achieving such effluent reduction"  for
                           91

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'•total   cost   ...   in   relation  to  effluent  reduction
benefits...11 For new  source  standards  which  reflect  the
greatest degree of effluent reduction achievable through the
application  of  the  best  available  demonstrated  control
technology,   processes,   operating.   methods,   or   other
alternatives, the Act requires only the consideration of the
cost  of  achieving such effluent reduction and any nonwater
quality environmental impact and energy requirements.

There are two radically different types of waste produced by
steam electric powerplants.  The first type consists of  the
essentially  chemical  wastes which originate from different
processes and operations within a plant.  These  wastes  are
highly  variable from plant to plant, depending on fuel, raw
water  quality,  processes  used  in  the  plant  and  other
factors.  Some waste streams are not directly related to in-
dividual  generating units but result from auxiliary process
systems such as water treatment, ash disposal,  housekeeping
operations,  and  air  pollution  control.   However, all of
these  waste  streams  are  at  least  in  a  qualitive  way
comparable  to waste streams produced by other manufacturing
operations.

The second type of waste consists of the waste heat produced
by the plant and disposed to  the  environment  through  the
cooling  water  system.  As previously indicated, waste heat
is an integral part of the  process  of  producing  electric
energy.   As  long as electric energy is produced by the use
of thermal energy from fuels to produce  steam,  waste  heat
will  be produced, and will ultimately have to be dissipated
to the  environment.   Under  present  day  technology,  the
atmosphere  is  the final recipient for this heat, but water
is generally used as an intermediate recipient.  The choices
available in the control of thermal discharges therefore  in
most  cases  are limited to accelerating the transfer of the
waste heat from  water  to  the  atmosphere.   There  is  no
available  means  of  significantly  reducing the waste heat
itself.

Furthermore, while the technology for affecting this  trans-
fer  is available, its application is dependent on many fac-
tors not directly associated with  the  production  process.
The effectiveness of heat transfer devices is to some degree
governed  by atmospheric conditions.  The achievement of any
specific level of reduction does not follow the type of cost
- effectiveness curve associated with the  removal  of  more
conventional pollutions.

The  basic  categorization  in  this  report therefore is to
separate consideration of the chemical wastes from  the  ef-
                             92

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fects  of  thermal  discharges.   Within  the chemical waste
category, each plant is  considered  as  a  whole  and  sub-
elements  have  been  established  according  to the type of
wastes produced by each  plant.   In  the  consideration  of
thermal  discharges,  each  generating  unit  is  considered
separately.

Chemical Wastes

The origin and character of chemical wastes within a  power-
plant is dependent upon the factors indicated above.  Plants
utilizing  different  fuels will produce different wastes to
the degree that certain waste streams are completely  absent
in  plants  employing one type of fuel.  Coal pile runoff is
not  a  problem  in  oil-fired  plants,  and  similarly  ash
sluicing  is  not  necessary  in  gas-fired plants.  Nuclear
plants have closed waste systems to contain any waste  which
is,  or  may be, radioactive.  These wastes are handled in a
manner prescribed by the Atomic Energy Commission,  and  are
not  relevant  to the categorization of the industry for the
purposes of this project.  As a result, many  of  the  waste
streams  present  in  fossil-fired  plants  are not normally
present, or of concern in a nuclear plant.

Another factor, such as raw water  quality,  will  determine
the  type  of  water  treatment  employed  within a specific
plant, and in turn the wastes produced from water  treatment
processes.   Although  these  wastes are extremely variable,
depending  upon  the  treatment   employed   (clarification,
softening, ion exchange, evaporation, etc.), they are wastes
which  are  common  to all powerplants regardless of fuel or
other factors.  Other waste streams depend upon the specific
characteristics of the particular plant in question.

As a result, the industry has been categorized for  chemical
waste  characteristics  by  individual  waste  sources.  The
basis of evaluation of plants in  the  industry  will  be  a
combination   of   the   appropriate  waste  sources  for  a
particular powerplant.  Guidelines will be  established  for
each  waste  source, and can then be applied and utilized in
the manner of a building-block concept.  Waste  streams  may
be  combined,  and  in  many  cases  this would have obvious
advantages, and the appropriate guidelines would  then  also
be  combined  for  application  to  the  new  waste  stream.
Subcategories have  been  based  on  distinguishing  factors
within  groups  of plants.  Table IV-5 provides the informal
categorization  for  the  purposes  of  the  development  of
effluent  limitations  guidelines and standards for chemical
wastes, and  Table  IV-6  shows  the  applicability  of  the
                             93

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                      TABLi IV-5
               CHKi'ilCAL WASTE CATEGORIES
I.      Condenser Cooling System
       A.  Once-through
       B.  Recirculat irig

II.    Water Treatment
       A.  Clarification
       B.  Softening
       C.  Ion Exchange
       D.  Evaporator
       E.  Filtration
       F.  Other Treatment

ILL    Boiler or PWR. Steam Generator
       A.  Slowdown

IV.    Maintenance Cleaning
       A.  Boiler or PWR Steam Generator Tubes
       B.  Boiler Fireside
       C.  Air Preheater
       D.  Misc. Small Equipment
       E.  Stack
       F.  Cooling Tower Basin

V.      Ash Handling
       A.  Oil-Fired Plants
           1.  fly ash
           2.  bottom ash
       3.  Coal-Fired Plants
           1.  fly ash
           2.  bottom ash

VI.    Drainage
       A.  Coal Pile
       B.  Contaminated Floor and Yard Drains

VII.    Air Pollution Control Devices
       A.  SO 2 Removal

VIII.  Miscellaneous waste ."Streams
       A.  Sanitary  Wastes
       B.  Plant Laboratory and Sampling Systems
       C.  Intake screen Backwash
       D.  Closed Cooling Water Systems
       E.  Low-Level Had Wastes
       F.  Construction Activity
                  94

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                         TABLE IV-6
        APPLICABILITY OF CHEMICAL WASTE CATEGORIES
                      BY TYPE OF FUEL
Process_or_Oggration

I.     Condenser Cooling System
      A.  Once-through
      B.  Recirculating

II.   Water Treatment
      A.  Clarification
      B.  Softening
      C.  Ion Exchange
      D.  Evaporator
      E.  Filtration
      F.  Other Treatment

III.  Boiler or Generator Slowdown

IV.   Maintenance Cleaning
      A.  Boiler or Generator Tabes
      B.  Boiler Fireside
      C.  Air Preheater
      D.  Misc. Small Equipment
      E.  Stack
      F.  Cooling Tower Basin

V.     Ash
      A.  Bottom Ash
      B.  Fly Ash

VI.   Drainage
      A.  Coal Pile
      B.  Floor and Yard Drains
VII.  Air Pollution  (SO^) Control Devices
Nuclear  Coal  Oil  Gas
X
X
X
X
X
X
X
X
X
X




X




X
X
X
X
X
X
X
X
X
X
X
X
X
X
X'
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X

X

X
X
X
X
X
X
X
X
X
X
X
X
X
X

X



X
VIII. Miscellaneous
      A.  Sanitary Wastes
      B.  Plant Laboratory and
          Sampling Streams
      C.  Intake Screen Backwash
      D.  Closed Cooling Water Systems
      E.  Low-Level Rad Wastes
      F.  Construction Activity
   X
X
X
X
X
X
X
X
X

X
X
X
X

X
X
X
X

X
                          95

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categories  to  plants  utilizing  the  four basic fuels for
producing electricity.

Thermal Discharges

The most obvious factor influencing the rejection  of  waste
heat to navigable waterbodies is the type of condenser cool-
ing  system  utilized within a plant.  Powerplants which re-
cycle cooling water through a cooling device only affect the
receiving water by way  of  the  relatively  small  blowdown
stream  from  the  cooling  tower,  pond, etc.  On the other
hand, plants operating with once-through cooling systems are
primarily responsible for the discharge  of  waste  heat  to
receiving waters.  Consequently, the basic subcategorization
for thermal discharge characteristics divides the generating
units by type of cooling system utilized, into plants having
recirculating   cooling  systems,  or  once-through  cooling
systems.

As indicated above, the primary factor in  consideration  of
waste  heat  rejection  is  the generating unit in question.
Therefore, subcategorization of once-through cooling systems
has been made on a unit, rather than  a  plant  basis.   The
evaluation  of  generating  units  to further sub-divide the
industry considered in detail the various factors  described
in  this section of the report; namely, fuel, size, age, and
site characteristics and mode of  operation  utilized.   The
evaluation  of  these  factors  will  be  described below to
provide the rationale for the subcategorization developed.

The  consideration  of  fuel  as  a  factor  in  waste  heat
rejection  from  a  powerplant  essentially  focuses  on the
differences between present nuclear and fossil-fueled units.
In general, the inherent characteristics of  a  light  water
nuclear unit make it less efficient than fossil-fired units.
This  difference  in  efficiency results in the rejection of
more waste heat to receiving waters from nuclear units  than
from  comparable  fossil  units.  Subsequent sections of the
report will discuss the technical factors which  cause  this
difference.

Nuclear  units generally have basic similarities with regard
to age, size, location and utilization which  also  tend  to
differentiate  them from fossil-fueled units.  Nuclear units
can  be  generally  classified  as  being  relatively   new,
relatively  large, located in rural or semi-rural areas, and
operated as base-load facilities.

These  factors  are  extremely  variable  when  applied   to
fossil-fueled  units  on  a  broad basis.  Also, the thermal
                             96

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waste characteristics  of  units  burning  different  fossil
fuels  indicate  that  there  is no basis for distinguishing
between fossil fuels for the thermal categorization  of  the
industry.   Consequently,  the  basic  subcategorization  of
once-through cooling systems divides  the  industry  between
nuclear and fossil-fueled units.

A  major  factor  of  concern  with  regard to fossil-fueled
generating  facilities  is  the  utilization  of  individual
units.   An  earlier  portion  of this section of the report
described the relationship of this factor with age and  with
efficiency  or  heat rate of a generating unit.  In addition
to this aspect of utilization, another point of  concern  is
the   relationship  between  utilization  and  the  cost  of
installing facilities to treat waste heat.   Utilization  is
significant   in  economic  analysis,  as  it  provides  the
operating time against which capital costs may  be  applied.
Furthermore,   utilization   reflects   the   effluent  heat
reduction benefit to  be  achieved  by  the  application  of
control  technology.   As  defined  earlier, the utilization
aspect of power generation is defined  by  peaking,  cycling
and  base  load  generating  facilities.   Peaking units are
defined as facilities which  have  annual  capacity  factors
less  than  0.20,  while  cycling units have annual capacity
factors between 0.20  and  0.60  and  base-load  units  have
annual capacity factors in excess of 0.60.

Some  difficulty  could  be  encountered, for the purpose of
effluent  limitations,   in   determining   the   level   of
utilization that a generating unit will achieve in the years
to  come.   It  is  known,  however, that all of the nuclear
steam-electric   generating   units   and   all    of    the
high-pressure,  high-temperature,  fossil-fueled  units  500
megawatts (Mw) and larger have been  designed  as  base-load
units.  Almost all nuclear units are 500 Mw and larger.

All  of  these  units  presently  operating were placed into
service since 1960  (excepting only one  small  nuclear  unit
initially  operated  in  1957).  The units placed in service
during the 1960*s had 15 or more years of base-load  service
ahead  of  them  as  of  1970, and would thus have 8 or more
years of base-load life as of 1977.

A  further  difficulty  that   could   be  . encountered   in
determining  the  level  of utilization of a generating unit
relates to the fact that the only  official  record  of  the
utilization  of  individual  generating units is the Form 67
"Steam-Electric Plant Air and Water Quality  Control  Data",
which   must  be  filed  annually  with  the  Federal  Power
Commission.  Utilities are required to report  the  capacity
                            97

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and  average  annual  capacity factor (level of utilization)
for   each   boiler,   but   not   the    turbine-generator.
Furthermore,  prior  to  1950,  individual boilers were kept
small, in large part  because  boiler  outages  were  rather
numerous,  so  that it was common design practice to provide
multiple boilers  and  steam  header  systems  to  supply  a
turbine-generator.  Some stations have the headers connected
to  multiple  turbine-generators.   Hence, the problem could
arise in these cases as to what comprises a generating  unit
(boiler(s)  plus turbine-generator) and what is its level of
utilization.   Furthermore,  the  problem  of   applying   a
closed-loop  cooling  system  could  be more difficult where
multiple    boilers    supply     single     or     multiple
turbine-generators   due   to  the  physical  and  operating
problems arising from the multiple connections involved.

However, advances  in  metal  technology  since  1950,  with
associated  lower  costs  of  larger  units,  have  made  it
economical   and   reliable   to   have   one   boiler   per
turbine-generator.   The trend to the larger, one boiler per
turbine-generator units began to  be  significant  when  the
first  300  Mw  unit  was placed into service in 1955.  From
1930 until that time the largest steam electric unit in  the
U.S.  was about 200 Mw.  Hence, for units 300 Mw and larger,
the unit itself and its level  of  utilization  are  clearly
defined  and  the physical and operating problems associated
with a closed-loop  cooling  system  and  arising  from  the
multiple connections involved are not encountered.

Age  was  identified in the Act as a factor to be taken into
account  in  the  establishment   of   effluent   limitation
guidelines  and  performance standards.  As indicated above,
the   interrelationship   between   age,   utilization   and
efficiency,  has generally been well documented in the steam
electric generating industry.  Age is also important because
the remaining life of equipment provides the basis  for  the
economic write-off of capital investment.  Consequently, age
is   of   significance  in  subcategorizing  steam  electric
generating units not only for technical  reasons,  but  also
for economic considerations.

Federal Power Commission depreciation practices indicate the
estimated  average service life of equipment for steam elec-
electric production to be 36 years •*.  Figure IV-10,  which
shows  the  improvement  of  efficiency in the generation of
electricity since 1920, indicates a sudden dip in the  curve
in  approximately  1949,  or  24  years  ago.  Based on this
process  factor  and  the  anticipated   service   life   of
equipment,  it  was  decided,  for  the purposes of the cost
analysis, to segment fossil-fueled  units  by  age,  with  6
                         98

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(six-year)  segments defining the range of age with regard to
generating units.

Site  characteristics  were  considered as a possibility for
subcategorization of the industry  for  thermal  discharges.
The  basic  consideration  involving location related to the
situation of a plant with regard to its cooling water source
(ocean, river, estuary, lake, etc.).   However,  categoriza-
tion  along  these lines would in reality violate the intent
of  the  Act,  which   stresses   national   uniformity   of
application  and  is  technology  oriented.  The control and
treatment of waste heat is essentially  an  internal  matter
within  a  powerplant.  Absolute location will influence the
cost of such control and treatment, but will  not  generally
determine  its feasibility.  This type of location factor is
primarily related to environmental considerations, which are
taken into account under Sections 303 and 316  of  the  Act.
Consequently,   it   was   decided   not  to  establish  any
subcategories for thermal  waste  characteristics  based  on
location.
Size  was  another  factor  which conceivably could form the
basis for  thermal  waste  subcategorization  of  the  steam
electric  powerplant  industry.   Among  those technical and
economic factors considered relative to the size of  a  unit
were  availability  and  degree of practicability of control
and  treatment  technology,  unit  costs  of   control   and
treatment  technology and their relation to other generating
costs,  and  system  reliability.   A  basis  for   a   size
subcategorization  would be the precedent established by the
Federal Power Commission with regard to the requirements for
filing Form 67, "Steam Electric Plant Air and Water  Quality
Control Data".  The FPC does not require filing of this form
by  powerpiants  smaller than 25 megawatts, or plants larger
than 25 megawatts which do not belong to  a  utility  system
with  a  capacity  equal  to, or greater than 150 megawatts.
Consequently, the data available from this source would  not
cover   the   numerous  small  generating  plants  under  25
megawatts.

As a result of evaluation of  the  factors  outlined  above,
informal segmentation for the purposes of the development of
effluent  limitations  guidelines  and  standards  for  heat
includes a division between nuclear  and  fossil  units  and
further  division  of fossil units based on utilization, all
followed by age considerations, and finally segmentation  by
size of unit as defined by cost and other considerations.
                           99

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Summary

In  summary, the most significant of the basic components of
all steam electric powerplants which relate to  waste  water
characteristics   are   the   fuel   storage   and  handling
facilities, water treatment  equipment,  boiler,  condenser,
type  of  cooling  system,  and auxiliary facilities.  Steam
electric powerplants (plants)  are comprised of one  or  more
generating  units.  A generating unit consists of a discrete
boiler,  turbine-generator  and  condenser   system.    Fuel
storage  and handling facilities, water treatment equipment,
electrical transmission facilities, and auxiliary components
may be a part of a discrete generating unit or  may  service
more  than one generating unit.  The characteristic quantity
and intensity of the waste heat transferred in the condenser
from the expended steam to the cooling water is  related  to
the  combined  characteristics  of the plant components that
are its source.

The general subcategorization  rationale  is  summarized  in
Table  IV-7  the  subcategorization  rationale  for  heat is
summarized in Table IV-8 and the subcategorization rationale
for pollutants other than heat is summarized in Table IV-9.

The degree of nonthermal effluent  reductions  that  can  be
achieved  by  the application of specific control and treat-
ment  technologies  are  related  to  the  type  of   source
components  involved,  and  further to water use and quality
and other  considerations  peculiar  to  individual  plants.
Both  unit  and  plant  related  characteristics  affect the
degree of practicability of applying nonthermal waste  water
control and treatment technology.


Accordingly, the general categorization scheme developed was
approached  from  the basis that separate subcategorizations
would be constructed for  thermal  characteristics  and  for
nonthermal  characteristics so that the rationale supporting
the one would not necessarily be supportive  of  the  other,
and  candidate  approaches  to  either  could be utilized or
discarded  on  their  own  merits.   Numerous  factors  were
considered  as  candidates for further subcategorization and
are as follows:  the age of equipment  and  facilities,  the
process employed, waste source (nonthermal characteristics),
nonwater  quality  environmental  impact  (including  energy
requirements), site characteristics, size of plant, type, of
thermal  control  employed,  fuel  utilized, and utilization
characteristics of the plant, with only the age of unit, its
utilization,, its generating  capacity  (size)  and  type  of
thermal  control  employed  qualifying  as further bases for
subcategorization of thermal discharges,  and  waste  source
for  nonthermal  discharges.   Many of the above factors are
                          TOO

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                    Table IV-7

             GENERAL SUBCATEGORIZATION RATIONALE

      Subcategorization for heat, is approached separately
from Subcategorization for other pollutants because:

     •   Control and treatment technology for heat relate
         primarily to the characteristics of generating units,
         while nonthermal control and treatment technologies
         relate primarily to characteristics of stations.

     •   Control and treatment technologies are dissimilar; and

     •   The costs of thermal control and treatment technology
         are much greater than nonthermal control and treatment
         technologies.

-------
                                       Table IV- 8

               SUBCATEGORIZATION RATIONALE FOR POLLUTANTS  OTHER THAN HEAT
        Characteristic
         of Plant
Need for Sub-
categorization
               Rationale
o
ro
        Utilization (base—load,
          cyclic,  or peaking)
        Age
        Fuel
        Size
        Land Availability
       Water Consumption
       Non-Water Quality  Envir-
         onmental Impact  (inclu-
         ding energy  consumption)
       Process Employed
     No

     No

     Yes


     No


     No



     No



     No

     No



     Yes
       Climate
     No
Costs versus effluent reduction benefits
vary significantly but are small in all cases

Costs versus effluent reduction benefits
vary significantly but are small in all cases
Certain technologies are practicable for new
sources but not for others

Effects on costs versus effluent reduction
benefits are not significant

Costs versus effluent reduction benefits are
greater for small plants but still
relatively small

Treatment technology includes small-sized
configured equipment as well as lagoon-type
facilities

Negligible consumption

Not significant
Practicability of treatment technology
is related to the volumes of waste water
treated, therefore subcategories should
be based on the specific waste water streams,
especially those of significant volume

Not significant except for effect on rainfall
runoff treatment costs, but costs versus
effluent reduction benefits are approximately
the same and costs are relatively small

-------
                                        Table IV-9
                           SUBCATEGORIZATION RATIONALE FOR HEAT
     Characteristic  of  Unit
    Need for
Subcategorization
                     Rationale
o
GO
    Utilization(Base-load,
      cyclic,  or  peaking)
    Age
    Fuel
    Size
      Yes
      Yes
                                   Yes
                                   Yes
     Process  Employed

     Land Availability


     Water Consumption


     Climate
    Non-Water Quality
       Environmental Impacts
       •Saltwater Drift
       •Fogging


       •Noise


       •Aesthetics
      No

      Yes


      No


      No




      Yes



      No


      NO


      No
Coupled with age, this factor determines the
incremental cost of production versus the effluent
reduction benefits related to the thermal control
technology.
Coupled with utilization, this factor determines
the incremental cost of production versus the
effluent reduction benefits related to the thermal
control technology.
Nuclear-fueled units reject significantly more
heat to cooling water than do comparible
fossil-fueled units.
Retrofit outages in small plants  (typically older
peaking plants) and small systems would be more
likely to cause reliability problems. Size may
affect retrofit costs. Size is generally
related to age and utilization. Counterbalancing
of cost variations is not as likely for small
plants and systems.
All significant differences already accounted
for by factors of utilization, age, fuel, and size.
Numerous units, due to urban locations, have
insufficient land available to implement the
control technology.
Where required water  consumption  rights  can add  an
 incremental  but  insignificant  cost over  the cost
 of water use rights otherwise  required.
Variabilities are primarily cost related and
taken into account in the cost analysis
While technology is available to limit drift
to very low levels, significant impacts could
occur for units in urban areas on saltwater
bodies.
Technology is available to abate fogging in
the few cases where it might otherwise have
a significant impact.
Technology is available to abate noise in
the few cases where it might otherwise have
a significant impact.
Would only be a problem in a case-by-case
evaluation of alternatives.

-------
related as previously discussed.  A further example  is  the
relation  between age of generating units and their capacity
factor, as shown in Table IV-10.

Certain further factors can be identified each of which  are
not  sufficiently  significant to warrant their inclusion in
the general subcategorization framework but  which  will  be
examined  in detail in subsequent sections of this document.
Some of these factors are  the  following:   available  land
characteristics, size of the unit, accessibility of existing
cooling   system,   ability   of   existing   structures  to
accommodate a new recirculating cooling system, requirements
imposed  by  nearby  land  uses   (drift,   fogging,   noise,
structure  height),  climatic considerations (wind, relative
humidity), soil strengths, significance of  consumptive  use
of  water, main condenser cooling water flow rate, unit heat
rate, wet-bulb temperature, back-end loading, cooling  tower
plume  abatement,  noise  abatement, aircraft safety, system
reliability  requirements,  and  characteristics  of  intake
water (temperature, concentrations of constituents).
                            104

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                                     Table  IV-10



              DISTRIBUTION OF U.S. GENERATING CAPACITY BY AGE AND CAPACITY FACTOR*
Year Installed
Before 1956
1956-1960
.1961-1971
1972-1978
Capacity Factor
0 - 0.2
11,000 Mw
2,000
1,000
0
0.2 - 0.4
7,000 Mw
5,000
10,000
0
0.4 - 0.6
13,000 Mw
15,000
36,000
8,000
0.6 +
20,000 Mw
10,000
36,000
81,000
o
en
          *  Source:  FPC data

-------
                           PART A

                      CHEMICAL WASTES

                         SECTION V

                   WASTE CHARACTERIZATION
Introduction

In  this  part of the study (Part A) only the nonthermal, or
chemical wastes are dealt with.  Part B of the report  deals
with thermal discharges.

Chemical  wastes produced by a steam electric powerplant can
result from a number of operations at the site.  Some wastes
are discharged more or less  continuously  as  long  as  the
plant   is  operating.   Some  wastes  are  produced  inter-
mittently, but on a fairly regularly scheduled basis such as
daily or weekly, but which are  still  associated  with  the
production  of  electrical  energy.   Other  wastes are also
produced intermittently, but at less frequent intervals  and
are generally associated with either the shutdown or startup
of  a  boiler  or  generating unit.  Additional wastes exist
that are essentially unrelated to production but  depend  on
meteorological or other factors.

Waste  waters  are  produced relatively continously from the
following  sources   (where   applicable):    cooling   water
systems,  ash  handling  systems, wet-scrubber air pollution
control systems, boiler blowdown.

Waste water is produced intermittently, on a regular  basis,
by  water  treatment  operations which utilize a cleaning or
regenerative step as part  of  their  cycle   (ion  exchange,
filtration, clarification, evaporation).

Waste  water  produced  by the maintenance cleaning of major
units of  equipment  on  a  scheduled  basis  either  during
maintenance  shutdown  or  during   startup of a new unit may
result from boiler cleaning (water  side),  boiler  cleaning
(fire side), air preheater cleaning, stack cleaning, cooling
tower  basin  cleaning  and  cleaning of miscellaneous small
equipment.  The efficiency of a powerplant  depends  largely
on  the cleanliness of its heat transfer surfaces.  Internal
cleaning of this  equipment  is  usually  done  by  chemical
means,  and  requires  strong  chemicals  to remove deposits
formed on these surfaces.   Actually  the  cleaning  is  not
successful  unless  the  surfaces are cleaned to bare metal.
                       107

-------
and this means in turn that some metal has to  be  dissolved
in  the  cleaning solution.  Cleaning of other facilities is
accomplished by use of a water jet only.

Rainfall runoff results in drainage from coal  piles,  floor
and yard drains, and from construction activity.

A diagram indicating sources of chemical wastes in a fossil-
fueled  steam  electric powerplant is shown in Figure A-V-1.
A simplified flow diagram for a nuclear plant  is  shown  in
Figure A-V-2.  Heat input to the boiler comes from the fuel.
Recycled  condensate  water,  with  some  .pretreated make-up
water, is supplied to the boiler for producing steam.  Make-
up  requirements  depend  upon  boiler  operations  such  as
blowdown,  steam soot blowing and steam losses.  The quality
of this make-up water is dependant upon  raw  water  quality
and  boiler  operating  pressure.   For  example, in boilers
where operating pressure is below 2.8  MN/sq  m  (400  psi),
good   quality   municipal   water   may   be  used  without
pretreatment.  On  the  other  hand,  modern  high-pressure,
high-temperature  boilers  need  a  controlled  high-quality
water.  The water  treatment  includes  such  operations  as
lime-soda   softening,  clarification,  ion  exchange,  etc.
These water treatment operations  produce  chemical  wastes.
According  to  the  FPC23*, the principal chemical additives
reported for boiler water treatment are  phosphate,  caustic
soda, lime and alum.

As  a  result  of  evaporation, there is a build-up of total
dissolved solids (TDS) in the boiler water.  To maintain TDS
below allowable limits for bciler  operation,  a  controlled
amount  of  boiler  water  is  sometimes  bled  off  (boiler
blowdown) .

The steam produced in the boiler is expanded in the  turbine
generator  to produce electricity.  The spent steam proceeds
to a condenser where the heat of vaporization of  the  steam
is   transferred  to  the  condenser  cooling  system.   The
condensed steam (condensate) is recycled to the boiler after
pretreatment (condensate polishing)  if necessary,  depending
upon water quality requirements for the boiler.  As a result
of condensate polishing  (filtration and ion exchange), waste
water streams are created.

In   a  nonrecirculating   (once-through)  condenser  cooling
system, warm  water  is  discharged  without  recycle  after
cooling.   The  cool  water  withdrawn  from an ocean, lake,
river, estuary or groundwater source may generate biological
growth and accumulation in the  condenser  thereby  reducing
its  efficiency.   Chlorine is usually added to once-through
                        108

-------
                EAW WATSfe
S
                                                                         TYPICAL PLOW DIAGRAM - STEAM ELECTRIC  POWER  PLANT  (POSSILp-FUELED)
                                                                                      SOURCES OF CHEMICAL riASTES
                                                                                           FIGURE A-V-1

-------
                          RECENERANT
                          CHEMICALS
                                                       DEMORALIZED
     700 GPM
10,000-14. HOC CPM

MAKE-UP
SYSTEM

no GPM
6GPM
440 GPM

,
0
RAW WATER
OEMINERA'JZER



SANITARY
SYSTEMS

PLANT RAW
SERVICE
WATER SYSTEM

MINERALIZES
WATER
REGENERA



AND
SECONDARY
SYSTEMS
NT WASTE
blU(A(jt MIJX

CO
- — UtM
SEWAGE
TREATMENT



i_




NOENSATE
NERAHZERS


REGENERAM
l WASTE
Ul REGENERAM
1 HOLDUP UNK
1 1

fr.ni iwr.
*-


	 •
NEUIRtLlZATION
CHEMICALS







RECENERAta
CHEMICALS

CONDE\SATE
STORAGE
TA,\K


/oo-iooncpM



1


'
ulLUTIO's
               0000-11.400 GPM
               0-32 00 GPM
                                                                             SUMP
                                                                    » ATMOSPHERE
                                   Figure  A-V-  2

           SIMPLIFIED WATER  SYSTEM FLOW DIAGRAM FOR  A NUCLEAR  UNIT
108r

-------
condenser cooling systems -to minimize this fouling  of  heat
transfer  surfaces.  Chlorine is therefore a parameter which
must  be  considered  for  nonrecirculating  cooling   water
systems.

Cooling  devices  such as cooling towers are employed in the
recirculating cooling  systems.   Bleed  streams  (blowdown)
must  generally  be  provided  to  control  the  build-up of
certain dissolved solids or total  dissolved  solids  within
the   recirculating   evaporative  cooling  systems.   These
streams  may  also  contain  chlorine  and  other   chemical
additives.   According to the FPC23*, the principal chemical
additives  reported  for   cooling   water   treatment   are
phosphate, lime, alum and chlorine.

As  a  result  of fossil-fuel combustion in the boiler, flue
*jases are produced  which  are  vented  to  the  atmosphere.
Depending upon the type of fossil fuel, the flue gases carry
certain  amounts  of  entrained particulate matter  (fly ash)
which   are   removed   in   mechanical   dust   collectors,
electrostatic  precipitators  or  wet scrubbing or collector
devices.  Thus fly ash  removal  may  create  another  waste
water stream in a powerplant.

A  portion  of the noncombustible matter of the fuel is left
in the boiler.  This bottom ash is usually transported as  a
slurry  in  a  water  sluicing operation.  This ash handling
operation presents another possible source  of  waste  water
within a powerplant.

Depending  upon  the  sulfur content of the fossil fuel, SO2
scrubbing may be carried out to remove sulfur  emissions  in
the  flue  gases.   Such  operations generally create liquid
waste streams.  Note that SO2 scrubbing is not required  for
gas-fired  plants,  or  facilities  burning  oil  with a low
sulfur content.  Nuclear plants, of course, have no  ash  or
flue gas scrubbing waste streams.

As  a  result of combustion processes in the boiler, residue
accumulates on the boiler sections and  air  preheater.   To
maintain  efficient  heat  transfer rates, these accumulated
residues are removed by washing with water.   The  resulting
wastes represent periodic  (intermittent) waste streams.

In spite of the high quality water used in boilers, there is
a  build-up  of  scale  and  corrosion  products on the heat
transfer surfaces over a period of time.  This  build-up  is
usually  due to condenser leaks, oxygen leaks into the water
and occasional erosion of metallic parts  by  boiler  water.
Periodically, this scale build-up is removed by cleaning the
                           111

-------
boiler  tubes  with  different  chemicals  -  such as acids,
alkali, and chelating  compounds.   These  cleaning  wastes,
though  occuring  only periodically, contain metalic species
such as copper, iron, etc. which may require treatment prior
to discharge.

The build-up of scale  in  cooling  tower  basins  and  soot
build-up  in  stacks  require  periodic  washings  and these
operations also give rise to waste streams.

For coal-fired generating units, outside storage of coal  at
or  near  the  site  is necessary to assure continuous plant
operation.  Normally, a supply of  90  days  is  maintained.
Coal  is stored either in "active" piles or "storage" piles.
As coal storage piles are normally  open,  contact  of  coal
with   air  and  moisture  results  in  oxidation  of  metal
sulfides, present in the coal, to sulfuric acid.   The  pre-
cipitate  trickles  or  seeps  through  the coal.  When rain
falls on these piles, the acid is washed out and  eventually
winds up in coal pile runoff, creating another waste stream.
Similarly,  contaminated  floor  and yard drains are another
source of pollution within the powerplant.

Besides these major waste streams, there are  other  miscel-
laneous  waste  streams  in  a  powerplant  such as sanitary
wastes, laboratory and sampling wastes, etc. which are  also
shown in Figure No. A-V-1.

In  a  nuclear-fueled powerplant, high quality water is used
in  the  steam  generating  section.    Conventional   water
treatment  operations  give  rise  to chemical waste streams
similar to those in fossil-fueled  powerplants.   Similarly,
the cooling tower blowdown is another waste stream common to
both  fossil-fueled  and  nuclear  fueled powerplants.  Some
wastes in a nuclear plant contain radioactive material.  The
discharge of such  wastes  is  strictly  controlled  and  is
beyond  the  scope  of  this  project.   However,  the steam
generator in a PWR plant is a  secondary  system,  having  a
blowdown   and   periodic  cleaning  wastes  which  are  not
radioactive.  Some of the disposal problems associated  with
low-level radiation wastes from nuclear fuel powerplants are
briefly described in this report.

Data  was accumulated from different sources to characterize
the various chemical wastes described above.  The sources of
data include:

a.  Plants visits and collection of samples for analysis
                           112

-------
b.  Permit applications submitted by powerplants to the U.S.
    Army Corps of Engineers.

c.  Tennessee Valley Authority (TVA)  reports  of  operating
    plants

d.  EPA Region II - questionnaire

e.  EPA  Region  V  - summary of permit applications data by
    National Environmental Research Center, Corvallis

f.  Southwest Energy Study - Appendices

g.  U.S.  Atomic  Energy  Commission,  Environmental  Impact
    Statements

h.  In-house data at Burns and Roe, Inc.

These  data  were  included in Appendix 2 of the Development
Document  supporting  the  proposed   effluent   limitations
guidelines  and  standards  for  steam electric powerplants,
which was issued in March, 1974.  A code system was used for
individual plant identification.

Based on these data and other  industrial  and  governmental
literature,   recommended  effluent  limitations  guidelines
proposed  are  developed  for  chemical  wastes   from   the
following operations in steam electric powerplants.

   I.  Condenser Cooling System
       A.  Once-Through
       B.  Recirculating

  II.  Water Treatment
       A.  Clarification
       B.  Softening
       C.  Ion Exchange
       D.  Evaporator
       E.  Filtration
       F.  Other Treatment

 III.  Boiler or PWR Steam Generator Slowdown

  IV.  Maintenance Cleaning
       A.  Boiler or PWR Steam Generator Tubes
       B.  Boiler Fireside
       C.  Air Preheater
       D.  Misc. Small Equipment
       E.  Stack
       F.  Cooling Tower Basin
                            113

-------
   V.  Ash Handling
       A.  Oil-Fired Plants Fly Ash
       B.  Coal-Fired Plants
           1.  fly ash
           2.  bottom ash

  VI.  Rainfall Runoff
       A.  Materials Storage (Coal Pile)
       B.  Construction Activity

 VII.  Air Pollution Control Devices

VIII.  Miscellaneous Waste Streams
       A.  Sanitary Wastes
       B.  Plant Laboratory and Sampling Streams
       C.  Intake Screen Backwash
       D.  Closed Cooling water Systems
       E.  Low-Level Rad Wastes
       F.  Floor Drains
       G.  Others

Once-Through Cooling Systems

The common biocides used are chlorine or hypochlorites.  The
amount  of  chlorine  dosage  varies  from  site to site and
depends  upon  the  source  of  cooling  water  and  ambient
conditions.  For example, in winter the biological growth is
normally   not   as  pronounced  as  in  spring  or  summer.
Consequently, chlorine demand is less in winter.   Normally,
the chlorine is supplied as a slug rather than by continuous
injection.  The frequency of chlorine dosage differs in each
plant,  and  may  vary  from  once a day to ten times a day.
Treatment duration varies between 5  minutes  and  2  hours.
Chlorination  results in residual chlorine concentrations in
the range of 0.1 to 1 mg/1  (ppm).  Higher concentrations can
be found in cases where  higher  level  organisms,  such  as
jellyfish,   or   eels,  tend  to  accumulate  on  condenser
surfaces.

Since the  waste  characteristics  of  once-through  cooling
systems  designed  for  economical operation and the control
technology for the reduction of the discharge of  pollutants
from  this  source  reflect  in  many  instances the same or
similar technologies, these aspects are  discussed  in  more
detail in Section A-VII of the Development Document.
                            114

-------
Recirculating Cooling Systems

In  the  operation  of a closed, evaporative cooling system,
the bulk of the warm  circulating  water  returning  to  the
cooling  tower, pond, etc. is cooled by the evaporation of a
small fraction of it.  During this  evaporation  only  water
vapor  is  lost, except for leakage and some net entrainment
of droplets in the air draft  (drift  loss),  and  the  salts
dissolved  in the remaining liquid become more concentrated.
Most  natural  waters  contain  calcium   (Ca-H-) ,   magnesium
 (Mg-f-f) , sodium  (Na+), and other metallic ions, and carbonate
 (CO3—),  bicarbonate  (HCO3-),  sulfate  (SO4—),  chloride
 (C1-) and other acidic ions~in solution.   All  combinations
of  these ions are possible.  When the concentration of ions
in any possible combination exceeds  the  solubility  limits
under  the  existing conditions, the corresponding salt will
precipitate,  some  of  these  salts  are  characterized  by
reverse solubility, that is, their solubility decreases when
the  temperature rises.  If water saturated with such a salt
leaves the cooling tower at the cool water  temperature,  as
the  water  is  heated  in  passing  thru  the condenser the
solubility will decrease and the  salt  will  deposit  as  a
scale  on  the condenser tube walls and hinder heat transfer
thru the tubes.

According to Reference 141, the formation of  scale  may  be
controlled  in several ways.  The most common is to blowdown
a portion of the circulating water stream and  replace  that
quantity with fresh water so that the circulating water does
not reach saturation at any time.  Blowdown therefore is the
constant or intermittent discharge of a small portion of the
circulating  water  in  a closed cooling system to prevent a
buildup of high concentrations  of  dissolved  solids.   The
blowdown  (B) is a function of the available makeup  (B+D+Ev)
water quality and is related to evaporation (Ev)  and  drift
 (D) in the following manner:

                  C =  (B + Ev + D)/(B + D)

In  this  equation,  C  equals  cycles  of  concentration, a
dimensionless number which expresses the number of times the
concentration of any  constituent  is  multiplied  from  its
original  value in the makeup water.  (It does not represent
the number of passes through the system).  B, Ev, and D  are
expressed  in  consistent units  (e.g. percent of circulating
water flow rate or actual flow rate).

For average makeup water quality, conventional practice sets
the value of C between U and  6.  For extremely high  quality
makeup water  (or-treated water) C values of 15 and above are
possible.   For salt or saline water, C values as low as 1.2
to 1.5 may be required.  This is usually  not a materials  or
                           115

-------
operating limit, but rather a means of preventing biological
damage from blowdcwn salinity.

The  chemical  characteristics  of  the  recirculating water
(treated or untreated)  determine the maximum C value.  Table
A-V-1  provides  some  "rules  of  thumb"  to  be  used   in
establishing the maximum C value.  Note that the C subscript
designations   used   in   the  table  represent  individual
constituent concentrations and should not be  confused  with
C, cycles of concentration used above.

The "Limitation" column in Table A-V-1 indicates the maximum
value  allowed  in the recirculating water for each chemical
characteristic  given.    The  maximum  C  value   would   be
established  when  any one of the "Limitations" is exceeded.
Note that this table provides  "rule  of  thumb"  estimates,
which   may  not  be  applicable  to  unique  water  quality
problems.

The equation for C can be rewritten for blowdown (B):

                       B * Ev-D(C-1)
                           C - 1

In order to minimize the total amount of  makeup  water  and
blowdown the cooling tower should be operated at as high a C
value  as  possible.  The following data were computed using
the above equation and illustrate the effect  of  C  on  the
blowdown and makeup flow rates:

          C                    Blowdown            Makeup
(cycles of concentration)        (cf si	              (cfsi

          1.2                    107                128
          1.5                     42.8               64.2
          2.0                     21.4               42.8
          5.0                      5.3               26.7
         10.0                      2.3               23.7
         20.0                      1.1               22.5

This  table  was developed assuming an evaporation rate  (Ev)
of 21.4 cfs and a drift rate (D) of 0.05 cfs (0.005* of  950
cf s) .

There are several advantages to maintaining a high C value:

    a.   Minimizing  the  makeup  water  requirement,   thus
reducing  the  number  of organisms entrained in the cooling
water.
                           116

-------
                                      Table  A-V-1
                       RECIRCULATING WATER.QUALITY LIMITATIONS
                                 461
    Characteristic
       Limitation
         Comment
pH and Hardness
pH and Hardness
with addition of
proprietory chemicals
for deposit control.
Sulfate and Calcium
Langelier Saturation
   Index = 1.0
Langelier Saturation
   Index = 2.5
Langelier Saturation
   Index = pH-pHs

       where

pH = measured pH
pHs = pH at saturation
      with CaCO,
See  Figure A-V-3   for
nomograph solution.
(CSQ ) x (CCa) = 500,000
                                                           p
     = concentration of
       S04 in mg/1
    = concentration of
      Ca in mg/1 as CaCO,
Silica
CSi0
      = concentration of
        Si02 in mg/1
Magnesium and Silica
       x(CSi02} = 35'000
C..  = concentration of
      Mg in mg/1 as CaC03
Suspended Solids
Css = 400 mg/1
C   = concentration  of
 "   ss in mg/1
                                 117

-------
                  Figure  A-V-3
                                                                     228
NOMOGRAM  TO DETERMINE LANGELIER SATURATION  INDEX
        Courtesy  Power Engineering
    P.l.=VrS PC3 ',"LL :0'-l
    J; 3000


     i-vooo
                                           1
                                                  - 40

                                                  -'•  50
                                     pALK AVO
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                                                   i no
                Example:  Water at 124 F has a  pH
                -' 7 ?. fr.fA! buii'-s ;.;f '100 ppm. C3|-
                tium iiara'ness as CaCU.-, of 240 ppm,
                and alkalinity as CaCO:; of 196 ppm.
                Fiiiri rhe Langeiier saiurcjtion inde*..
                ioiution:  (i) join  400 ppm nn thp
                ir>i'thand scale with  1 ?.'i F nn th.-. *sm.
                C- .•• •.!•; liuie vsiiiP of  i./. /v) j.^jj.
                "•'0 f'Jirn with  nr'a r^JorvrCC  OCInt
                and extend to pC;i scale. K-.cd pCd =
                2.62. (3) Join  1S6. ppm with pALK
                rc-ference point,  extend to pALX scale
                and read pALK = 2.40. Add the three
                V3k;3s:
                   pHs=C  + pCa + pALK=6.72
                      pH-pHs = 7.2-6.72=+0.48
                           118

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    b.   Minimizing the  volume  of  biowdown  water  to  be
discharged.

    c.   Reducing the size and cost of makeup  and  blowdown
handling facilities (i.e., pumps, pipes, screens, etc.).

Values  for  evaporation  from cooling systems average about
0.75X of cooling water flow  for  every  10°F  of  condenser
delta  T for cooling towers and approximately 50% higher for
cooling ponds.  This is equivalent to a  range  of  15.0  to
30.0  gpm/Mw  for cooling towers and 22.5 to 45.0 gpm/Mw for
cooling ponds.  Drift constitutes a relatively small portion
of the required makeup water.  For new cooling towers, drift
losses can be kept as low as 0.005%  of  the  cooling  water
flow  for  mechanical  draft  towers  and 0.002X for natural
draft  towers.   Drift  losses  for  ponds  are  negligible.
Estimates  of  the  allowable  blowdown  flow based on these
factors can be made once the cooling water  flow,  condenser
delta T, and allowable concentration factors are known.

The  heat  content of the blowdown as a percent of condenser
heat rejection can be quite variable.  The heat  content  of
the  blowdown  can  vary  from a fraction of 1% of the total
condenser heat rejection to as high  as  7  to  8%  of  this
value.   Higher  rates of heat rejection in the blowdown are
due to larger blowdown flows  (smaller C values)  required  in
salt  water  systems  and systems that blowdown from the hot
side of the system.  Systems that  blowdown  from  the  cold
side  of the cooling system should contain no more than 1 to
2% of the condenser heat rejection.

Scale formation may be controlled by chemical means such  as
softening  or  ion  exchange to substitute more soluble ions
for the scale formers, such as Na+ substitution for Ca-H- and
Mg-H-.  Advantage may be taken of the greater  solubility  of
some  ions.  For instance SOU— may be substituted for CO3—
or HCO3-, as:                                            ~

          Ca CO3 + H2 SOU = CaSOU + H2O + CO2 (g)

         Mg(HCO3)2 * H2SO* = MqSOU +2H2O  +2CO2(g)

In these reactions, CO2 is released as a gas.  Sulfates have
a much greater solubility than carbonates and  bicarbonates,
and  scale  formation  is  reduced.   Organic "sequestering"
agents are used to tie up the  insoluble  metallic  ions  so
that   they   cannot   combine   with   the  carbonates  and
bicarbonates to  form  scale.   Many  of  these  agents  are
proprietary   compounds   and  their  compositions  are  not
generally known.  The use of chemical dispersants and makeup
                            119

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water softening to reduce or eliminate blowdovm  at  certain
powerplants  is  discussed  in Reference 22.   Eventually the
limit is reached and there must be some bleed through  drift
or  blowdovm  although  its quantity may be greatly reduced,
resulting in higher concentrations.  Data obtained from  the
study of fifteen plants reveals an extremely large variation
in   the   parameters   listed.   Generally,   the  important
pollutant parameters are:  total suspended solids (TSS), pH,
hardness, alkalinity, total dissolved solids and phosphorus.

In general, condenser materials are chosen so as  to  resist
corrosion   by   the   recirculating  water.    Consequently,
chemicals are generally not required  in  the  recirculating
water  for  corrosion  resistance, except in cases where the
recirculating water  (because of the make-up  water  quality)
has   high   chloride   concentrations  chromates  or  other
chemicals are added as corrosion  inhibitors.

In recirculating systems, growth organisms  such  as  algae,
fungi  and  slimes  occur  because  of  the  warm  and moist
environment.  Such biological growth will  affect  condenser
efficiencies  and  chlorine  is  commonly used as a biocide.
The chlorine dosage  is  usually  in  slugs.    The  residual
chlorine  is  generally  in the range of 1 mg/liter.  Higher
residual  chlorine  concentrations   may   cause   corrosion
problems.   In  cooling  towers  with  wood  filling, sodium
pentachlorophenate  is  sometimes  added  to  inhibit  fungi
attack  on  wood.   The chemicals are generally added to the
cooling tower basin to ensure  adequate  mixing.   Depending
upon  the  chlorine  dosage  frequency (one to three times a
day) and sodium salt addition, the  concentration  of  these
pollutants in the blowdown will vary for each case.

Since  the  waste  characteristics  of recirculating cooling
systems designed for economical operation  and  the  control
technology  for the reduction of the discharge of pollutants
from this source reflect in  many  instances,  the  same  or
similar  technologies,  these  aspects are discussed in more
detail in Section A-VII of the Development Document.

Water Treatment

All water supplies  contain  varying  amounts  of  suspended
solid  matter  and  dissolved  chemical  salts.  Table A-V-2
gives typical characteristics of powerplant water  supplies.
Salts  are  dissolved  from  rock  and mineral formations by
water as it flows into rivers and lakes.  In the boiler,  as
water  evaporates  to  steam, mineral salts deposit on metal
surfaces as scale.  Scale reduces transfer of  heat  through
the  metal  tubes,  and if allowed to accumulate reduces the
                           120

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         Table A-V-2

TYPICAL CHARACTERISTICnOF
POWERPLANT WATER SUPPLIES
Constituent
Calcium, as CaC00
Magnesium, as CaCO~
* *J
M Alkalinity, as CaC03
Sulfate, as S04
Chloride, as Cl
Silica, as StOp
Iron, as Fe
Manganese, as Mn
Oil
Suspended Solids
Concentrati
40 -
10 -
5 -
20 -
10 -
2 -
0.2 -
0.1 -
<1 -
10 -
pH 5.5 -
Specific Conductance, ymhos (18°C) 100 -
on (mg/1)
200
50
50
140
150
15
2.0
1.0
5.0
200
7.5
500
 121

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flow area, eventually causing  failure  of  the  tubes.   To
prevent  scaling,  water  is  treated for removal of mineral
salts before its use as boiler feed water.

Removal of the dissolved mineral salts can  be  accomplished
by  evaporation,  chemical precipitation or by ion exchange.
Evaporation produces a distilled-water-quality  product  but
is  not  always  economical and results in a stream of brine
waste.  Chemical precipitation is of limited use in the  re-
moval  of  dissolved  solids,  as  the  product water of the
process contains soluble quantities  of  mineral  salt.   To
produce a boiler feed water, chemical precipitation followed
by  evaporation is used occasionally, but cost is not always
economical.

Clarification

Chemical  precipitates  and  naturally  occurring  suspended
solids  are very fine and light.  Clarification is a process
of agglomerating the solids and  separating  them  from  the
water by settling.  Suspended solids are coagulated, made to
join  together  into  larger,  heavier  particles  and  then
allowed to settle.  Clarified water is drawn  off  and  fil-
tered  to  remove  the  last  traces  of turbidity.  Settled
solids, more commonly called sludge, are withdrawn from  the
clarifier   basin,   continuously   or   intermittently  and
discharged  to  waste.   Figures  A-V-4   and   A-V-5   show
simplified  flow  diagrams  for clarification and filtration
processes  respectively.   Surface  water,  in  addition  to
dissolved  impurities, may contain suspended matter, causing
turbidity or objectionable color.  Removal of  turbidity  by
coagulation  is  an  electro-chemical  phenomenon.  Iron and
aluminum ions of positive charge  form  a  bridge  with  the
negative  charge  of the sediments, causing an agglomeration
of  the  particles.   Most  commonly  used  coagulants   are
aluminum  sulfate  (alum, filter alum, A12(SOU)3 .  18 H2O),
ferrous sulfate (copperas, FeSO.fl . 2  H2_O) ,  ferric  sulfate
(ferrifloc,  Fe2   (SOj»)3),  and sodium aluminate  (soda alum,
Na2 A12 OU).  Polyelectrolytes and other coagulant aids  are
frequently used in the process.

Softening

In  the softening process, chemical precipitation is applied
to hardness and alkalinity.  Principal  chemicals  used  are
calcium hydroxide  (hydrated lime - Ca (OH) 2)  and sodium car-
bonate  (soda  ash-Na2CO3).  Calcium is precipitated as cal-
cium carbonate  (CaCO3) and magnesium as magnesium  hydroxide
(Mg (OH) 2) .
                           122

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TREATMENT
CHEMICALS
 RAW WATER
                 CLARIFIER
CLEAR WATER
                  SLUDGE
      FIGURE A-V-4 CLARIFICATION PROCESS
 RAW WATER
        WASH
                    1
                   FILTER
                            WASTE
                            FILTERED
                            WATER
       FIGURE A-V-5 FILTRATION PROCESS
                     123

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Chemical  precipitation of calcium and magnesium can be car-
ried out at ambient temperatures, which  is  known  as  cold
process  softening,  or  may  be  carried  out  at  elevated
temperatures, 100°C (212°F), known as hot process  softening.
Hot  process softening is generally employed for boiler feed
water in steam electric powerplants when steam is  generated
for  heating  purposes as well as electric power generation.
The hot process accelerates the reactions  and  reduces  the
solubility of calcium carbonate and magnesium hydroxide.

Since  there is always some carryover of fine particles from
the clarifiers, these are  generally  followed  by  filters.
Filters may contain graded sizes of sand, anthracite coal or
other  filter  media.   Filters  are  also  required in case
clarifiers have an upset and precipitates are  carried  over
into the clear water overflow.

Ion Exchange

Ion exchange processes can be designed to remove all mineral
salts  in  one  unit  process  operation.   These  processes
produce  high-quality  water  suitable   for   boiler   feed
purposes.   All  of  the mineral constituents are removed in
one process.   The  ion  exchange  material  is  an  organic
resinous  type  material manufactured in granular bead form.
Resin beads contain pores  that  make  them  similiar  to  a
sponge.   The  surface  area  is  electrically  charged  and
attracts to the surface chemical ions of opposite charge.

Basically there are two major types  of  resin,  cation  and
anion.   Cation  resin  attracts the positively charged ions
and anion resin attracts the negatively charged ions.   When
the  charded sites on the resin surface are filled with ions
exchanged from the water, the resin ceases to  function  and
must be regenerated.  (Figure A-V-6)

The  regeneration  process is a three-step operation for all
ion exchange units except mixed resin  units.   Mixed  resin
units  (Figure  A-V-7) contain a mixture of cation and anion
resin in a single vessel.  The resin  is  in  a  mixed  form
during the service run and is separated during the regenera-
tion.

During  the  service  run, water flow in an ion exchanger is
generally downflow through the  resin  bed.   This  downward
flow  of  water causes a compaction of the bed which in turn
causes an increase in resistance to flow  through  the  bed.
In  addition,  the  raw  water being treated always contains
some micro-size particles which collect at the  top  surface
of  the bed and add to the resistance to flow.  To alleviate
                            124

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RAW WATER.
  ACID
         CATION
                             L   I
DEGASI-
 FIER
                                     CASUTIC
ANION
                                                  DEIONIZED WATER
         WASTE
                   WASTE
    FIGURE A-V-6  ION EXCHANGE PROCESS CATIONIC AND ANIONIC TYPE
                          125

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        RAW WATER
       CAUSTIC
        ACID
                MIXED
                RESIN
                       WASTE
                       DEIONIZED WATER
FIGURE A-V-7  ION EXCHANGE PROCESS MIXED RESIN TYPE
              126

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this resistance, normal water flow to the bed is stopped and
direction of flow through the bed is reversed,  causing  the
bed  to  erupt,  and wash the solids out.  Ion exchange beds
are usually washed for a period of 10 to 15  minutes.   Flow
rates  vary  with  the size of vessel and the type of resin.
The flow rate is adjusted to expand the resin bed 80 to 100%
of its settled bed depth.  Flow rates  of  3.4-U.1  10~3  cu
m/s/sq  m  (5-6  gallons  per  minute  per  square foot) are
typical.  The second stage of regeneration is the contacting
step.  Chemical solution is passed  through  the  bed  at  a
controlled  flow  rate such that resin is contacted with the
chemical solution for a certain  time.   Cation  resins  are
contacted  for  approximately  30 minutes while anion resins
are contacted for  approximately  90  minutes.   Immediately
after  this chemical contact, the bed is given a slow rinse.
The normal volume of rinse is two bed volumes.  The  purpose
of the rinse is to wash the regenerant solution remaining in
the  voids  of the bed after the regenerant flow is stopped.
The bed is then rinsed until effluent  quality  reaches  de-
ionized   water  specification.   Quantity  of  rinse  water
depends on the resin.  Cation rinse water is approximately 8
cu  m  water  per  cu  m  resin.   Anion  rinse   water   is
approximately  10  cu  m  water  per cu m resin.  With mixed
resin units, there are  two  additional  steps  in  the  re-
generation  process.   After  rinsing,  the  water  level is
drained until it is just above the settled resin bed  level.
Air  is  injected  into the bottom of the vessel causing the
two stratified layers of resin to mix.  After  this  mixing,
the vessel is filled with water and the resin bed is given a
short final rinse.

Chemical  characteristic  of the spent regenerant depend, on
the type of service that  an  ion-exchanger  is  performing.
Cation  exchange  in  hydrogen  cycle  absorbs calcium, mag-
nesium, potassium, and sodium  ions  from  the  water.   The
cation  unit  is  regenerated  with sulfuric acid.  The acid
concentration is maintained low to prevent  calcium  sulfate
precipitation.   The  spent regenerant solution contains the
eluted ions with excess acid.

In order for the regeneration process to proceed there  must
be  a  driving  force.  The driving force is excess chemical
quantity.  The quantity of acid required  for  regeneration,
on  a weight basis, is 2-4 times the stoichiometric exchange
capacity of the resin.  On a weight basis,  the  waste  sul-
furic  acid  will  consist of 1/4-1/3 part mixed cations and
2/3-3/4 part of  excess  sulfuric  acid.   Concentration  of
cations  in  the  waste depends on their distribution in the
water supply.
                            127

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Occasionally, hydrochloric acid is used for  hydrogen  cycle
regeneration.   Hydrochloric acid yields a greater regenera-
tion efficiency than sulfuric  acid.   The  cost  of  hydro-
chloric  acid  is  generally  higher   than  sulfuric  acid,
therefore, it is used only when the economics justify it.

Anion exchange units are regenerated with sodium  hydroxide.
The concentration is approximately UX.  The spent regenerant
will   contain   the  eluted  anions.   These  are  sulfate,
chloride, nitrate, phosphate, alkalinity, bicarbonate,  car-
bonate, and hydroxide.  Silica in the form of HSio3~ is also
absorbed by anion exchangers and may be present in the spent
regenerant.

In   high-pressure  steam  electric  plants,  condensate  is
deionized to prevent dissolved  salts  from  condenser  tube
leaks  from entering the boiler system, and eliminate minute
quantities  of  iron  and  copper  formed  as  a  result  of
corrosion.   The  condensate is then polished in mixed resin
units.  The ion exchange resin is regenerated with  sulfuric
acid and sodium hydroxide.  Sometimes, ammonium hydroxide is
used in place of sodium hydroxide.  The quantity of iron and
copper found in the spent regenerants is usually negligible.

Sodium  cycle  ion  exchange  is the exchange of calcium and
magnesium  ions  for  sodium  ions.   Hard  water  is  often
softened  by  this  process,  but  the  content of dissolved
solids is not appreciably changed.  The  exchange  resin  is
regenerated  with  10%  sodium chloride solution.  The waste
regenerant  consists  of  approximately  1/3  part   calcium
chloride   and   magnesium  chloride  and  2/3  part  sodium
chloride.

Evaporator

Evaporation is a process of purifying water for boiler  feed
by  vaporizing it with a heat source and then condensing the
water vapor on a cool surface, and collecting it  externally
of  the  evaporator  unit.  In the process, a portion of the
boiling water is drawn off as blowdown.

The evaporator consists of a vessel, usually in a horizontal
position in order  to  provide  a  large  surface  area  for
boiling.   In steam electric plants, evaporators are usually
heated by a waste source of heat, such as  extraction  steam
from the turbine cycle.  The water evaporates into the upper
surface  of  the  vessel  and  is ducted to an external con-
denser.  In the lower portion of the vessel, a pool  of  the
boiling  water is maintained at a constant level to keep the
steam tubes immersed in liquid.  As  water  evaporates  from
                           128

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•the  pool,  the  raw  water salts in the pool become concen-
trated.  If allowed to concentrate too much, the salts  will
scale  the  heating  surfaces and the heat transfer rate di-
minishes.  To prevent scaling, a portion of the  pool  water
is  drawn off as blowdown.  A simplified flow diagram of the
process is shown in Figure A-V-8.

Chemical composition of the blowdown is similar to  that 'of
the  raw  water  feed except that it is concentrated several
times.  The blowdown is alkaline, with a pH in the range  of
9-11.   This  is  due to decomposition of bicarbonate ion to
carbon dioxide and carbonate ion.   The  carbon  dioxide  is
degassed  from  the evaporator leaving carbonate in solution
and yielding  an  alkaline  pH.   If  the  concentration  of
calcium  sulfate  is high enough, it will precipitate out of
solution.  Some steam electric power plants  feed  phosphate
to  the  raw water feed.  This phosphate reacts with calcium
and lessens  the  precipitation  of  calcium  carbonate  and
calcium sulfate.

Evaporators  are  usually  found in older low-pressure steam
electric plants.  Ultra pure water required  in  the  modern
high   pressure   units   may  generally  be  obtained  more
economically by the ion exchange processes.

A typical powerplant may employ a combination  of  the  dif-
ferent water treatment operations described above.  However,
the  waste streams from all these water treatment operations
are  generally   similar   in   pollutant   characteristics.
Consequently, a description of the combined pollutants found
in the waste streams is given below.

Character of Water Treatment Wastes

Water  treatment  waste streams should be described by three
parameters: 1) pH, 2) suspended solids concentration, and 3)
concentration parameters typical of  processes  involved  or
toxic  elements  involved  in  the  process.   Reference  21
reports waste water flows as shown in Table A-V-3.

Clarification wastes consist of clarifier sludge and  filter
washes.   Clarifier sludge could be either alum or iron salt
sludge, from coagulant chemicals.  If the clarifier is  lime
softening,  then  the  sludge  would be a calcium carbonate-
magnesium hydroxide sludge.   Filter  washes  would  contain
suspended  solids  either  as light carry-over floe from the
clarifier or  as  naturally  contained  in  unclarified  raw
water.   Activated  carbon absorber wash would contain light
suspended particles or very fine activated carbon  particles
due to attrition of the carbon.
                           129

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                                 FEED
                                WATER
                          CONDENSER
                                     CONDENSED
                                     BOILER FEED
STEAM

COND*
                  EVAPORATOR
                                EVAPORATOR
                                 SLOWDOWN
      FIGURE A-V-8 EVAPORATION PROCESS
               130

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                 Table  A-V- 3
      TYPICAL WATER TREATMENT WASTE
              WATER FLOWS (Ref. 21)
   PROCESS
 RANGE OF FLOWS
. gal/ 1000  Ib water
               treated
Clarifier  blowdown
Lime-soda
Raw water filtration backwash
Feed water filter
Sodium zeolite regeneration
Cation exchange regeneration
Anion exchange regeneration
Evaporator blowdown
Condensate filtration and
  ion exchange
Condensate powdex
       1-4
       1-4
       0-6
       0-6
     0.5  -  3
     0.5  -  3
     0.5  -  3
      12  -40

   0.02  -  0.6
   0.01  -  0.06
                      131

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Various  attempts  have  been  made  to  classify  clarifier
sludges.  Although these vary from plant to plant, the basic
characteristics are quite similar.  Alum sludge  is  a  non-
Newtonian,  bulky gelatinous substance composed of aluminium
hydroxide, inorganic-particles, such as clay or sand,  color
colloids,   micro-organisms  including  plankton  and  other
organic matter removed from water.

The major constituent in sludge from lime soda softening  is
calcium  carbonate.   Other consituents which may be present
are magnesium hydroxide, hydroxides  of  aluminum  or  iron,
insoluble  matter  such  as  clay, silt or sand, and organic
matter such as algae or  other  plankton  removed  from  the
water.

The American Water Works Association Research Foundation has
conducted a study among its members to gather information on
the  nature  of  waste  disposal problems in water treatment
plant to assist the utilities. **

Waste  sludges  from  clarifiers  generally  have  a  solids
content  in  the  range  of  3,000 - 15,000 mg/1.  Suspended
solids amount to approximately 75 - 80* of total solids with
the quantity of volatile solids being  20  -  25%  of  total
solids.   The  BOD  level usually is 30 - 100 mg/1.  A large
corresponding COD level of 500 - 10,000 mg/1 shows that  the
sludge   is  not  biodegradable,  but  that  it  is  readily
oxidizable.  The sludge has a pH of about 5-9.

Filter backwash is more dilute than the wastes  from  clari-
fiers.   Generally,  it  is  not  a  large  volume of waste.
Turbidity of wash water is usually less than 5 mg per  liter
and  the  COD  is  about 160 mg per liter.  The total solids
existing in filter backwash from plants  producing  an  alum
sludge  is  about  400  mg per liter with only 40 - 100 mg/1
suspended solids.

All ion exchange wastes are either acidic or alkaline except
sodium chloride solutions which are neutral.  While ion  ex-
change  wastes  do not naturally have any significant amount
of suspended  solids,  certain  chemicals  such  as  calcium
sulfate   and   calcium   carbonate   have   extremely   low
solubilities and are often precipitated  because  of  common
ion effects.  Calcium sulfate precipitation is common in ion
exchange  systems  because  of excess quantities of sulfuric
acid.

Evaporator blowdown consists of concentrated salts from  the
feed  water.   Evaporators  are  usually operated to a point
where the blowdown is three to five times the  concentration
                            132

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of  the  feed  water.   Due to the low solubility of calcium
carbonate and calcium sulfate, it  is  possible  that  there
will  be  precipitation of calcium carbonate and sulfate, if
present in the feed water.  While the concentrated salts  of
the  feed water are neutral, decomposition of bicarbonate to
carbon dioxide and calcium carbonate,  creates  an  alkaline
waste stream from the evaporator.

Table  A-V-U  shows  the arithemetic mean and standard devi-
ation for a number of parameters for water treatment wastes.
These data were gathered from  many  different  sources  and
reported  in  various ways.  Therefore they show wide varia-
tions.  As can be  seen,  the  standard  deviation  of  each
parameter  chosen,  is  two  to three times greater than the
mean value of the parameter.

Undoubtedly, other factors that do not appear  in  the  data
caused  this  variation.   Under the sub-heading of clarifi-
cation wastes, the reported data do not indicate whether the
waste stream is a sludge from a clarifier removing suspended
solids, a sludge from a lime softener for hard water,  or  a
wash-water   from   a   filter.    Obviously,  waste  stream
composition will vary depending upon its origin.

Similarly, data listed  under  ion-exchange  wastes  do  not
indicate  whether the waste is acid, caustic or brine waste.
There are no indicators of what source the waste  originated
from,  or  if the waste was neutralized before reporting. In
summary, data collected  on  water  treating  wastes  is  of
limited  value  because of the process variations which were
not  reported,  and  because  of  the  limited  quantity  of
information available on these waste streams.

Boiler or PWR Steam Generator Slowdown

Except  for  zero solid treatment systems, no external water
treatment regardless how efficient, is in itself  protection
against  bciler  scale  without  the  use  of  supplementary
internal chemical treatment of the boiler water.

The  primary  cause  of  scale   formation   is   that   the
solubilities   of  scale  forming  salts  decrease  with  an
increase in temperature.  The  higher  the  temperature  and
pressure  of  boiler operation, the more insoluble the scale
forming  salts  become.   No  method  of  external  chemical
treatment  operates  at a temperature as high as that of the
boiler water.  Consequently, when the boiler feed  water  is
heated  to the boiler operating temperatures, the solubility
of the scale forming salts is exceeded and they  crystallize
from solution as scale on the boiler heating surfaces.
                         133

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                            TABLK A-V-4

               .  ARITHMETIC MEAN AND DEVIATION OF

             SELECTED WATER TREATMENT WASTE PARAMETERS
                                           ARITHMETIC  STANDARD   0~
                                             MEAN     DEVIATION  m
                                               m           0-
CLAHIFICATION^WASTES
  Flow - M* per day
  Turbidity - J.T.U.
  Total Suspended Solids - mq TSS per
  Total Suspended Solids - kg TSS per day
  Total Hardness - mq CaCO_3 per 1
  Total Hardness - kq CaCD3_ per day
  Iron - mq Fe per 1
  Iron - kg Fe per day
  Aluminum
  Flow - M3 ner day
  Total Dissolved Solids - mg TDS per 1
  Total Dissolved Solids - kg TDS per day
  Sultate - mg SO4per 1
  Sulfate - kg SO4 per day
  Chloride - mg Cl per 1
  Chloride - kq Cl per day
  Sodium - mg Na per 1
  Sodium - kq Na per day
  Ammonia - mg NHj - N per 1
  Ammonia - kg NH_3 - N per day

EVAPORATOR_BLOWDOWN
  Flow - MJ per day
  Total Dissolved Solids - mg TDS per
  Total Dissolved Solids - kg TDS per day
  Total Suspended Solids - mg TSS per
  Total Suspended Solids - kg TSS per day
  sulfate - mg SOj* per 1
  Sulfate - kg SO4 per day
  chloride - mg Cl per 1
  Chloride - kg Cl per day


1
day






1
day








0
1
day
1
day




316
1,088
25,213
2,673
3,215
27
352
212
1 Piece
74,515
7,408
1,311
2,085
1,100
1,708
124
3. 112
558
46
1
-------
Calcium  and  magnesium  salts are the most common source of
difficulty with boiler scale.  Internal  chemical  treatment
is  required  to  prevent  deposit  scale formation from the
residual hardness concentration remaining in the feed water.
One of the most common sources of scale is the decomposition
by heat of calcium  bicarbonate  to  calcium  carbonate  and
carbon dioxide.

         Ca(HCO3)2 + Heat = CaCO3(s)  + H2O + CO2(g)

Deposits  cf iron oxide, metalic copper and copper oxide are
frequently  found  in  boilers  operating  with  very   pure
feedwater.   The source of deposits is corrosion.  Causes of
the  corrosive  action  are  dissolved  oxygen  and   carbon
dioxide.

To  prevent  calcium  and  magnesium  salts  from scaling on
boiler evaporative surfaces, internal treatment consists  of
precipitating  the  calcium  and magnesium salts as a sludge
and maintaining the sludge in a fluid form so that it may be
removed by boiler blowdown.  The blowdown can be  continuous
or   intermittent  and  the  operation  involves  controlled
discharge of a certain quantity of boiler water.   The  most
common chemicals used for precipitation of calcium salts are
the sodium phosphates.

Chelating   or  complexing  agents  are  sometimes  applied.
Tetrasodium salt  of  ethylenediaminetetracetic  acid  (Na<»-
EDTA)   and trisodium salt of nitrilotriacetic acid (Na3-NTA)
are the most commonly used chelating agents.  The  chelating
agents  complex  the  calcium, magnesium, iron and copper in
exchange for the sodium.

The solubility of iron in water  increases  as  the  pH  de-
creases  below  the  neutral  point.   To prevent corrosion,
neutralization of the acid  with  an  alkali  is  necessary.
Sodium   carbonate,  sodium  hydroxide  and/or  ammonia  are
commonly employed for this purpose.

Dissolved oxygen present in boiler water causes corrosion of
metallic surfaces.  Dissolved oxygen is introduced into  the
boiler,  not  only  by  the  makeup water, but by air infil-
tration in the condensate system.  In addition to mechanical
deaeration,  sodium  sulfite  is   employed   for   chemical
deaeration.

                  2 Na2SO3 + 02 = 2Na2SOU

It  is  common practice to maintain an excess of the sulfite
to assure  complete  oxygen  removal.   The  use  of  sodium
                          135

-------
sulfite  is  restricted  to low pressure boilers because the
reaction products are sulfate and dissolved solids which are
undesirable in high pressure boilers.

Hydrazine is a reducing agent which does not  possess  these
disadvantages for high pressure operation.  Hydrazine reacts
with oxygen to form water.

                    N2H4+ O2 = 2H2O + N2

The  excess  hydrazine  is decomposed by heat to ammonia and
nitrogen.

The characteristics of boiler blowdown are an alkaline waste
with pH from 9.5-10.0 for boilers treated with hydrazine and
pH from 10-11 for boilers treated with phosphates.

Blowdown from medium pressure boiler has a  total  dissolved
solids  (TDS)  in  the range of 100-500 mg/1.  High-pressure
boiler blowdown has a total dissolved solids in the range of
10-100 mg/1.  Blowdown frcm boiler  plants  using  phosphate
treatment  contain  5-50  mg/1  phosphate  and  10-100  mg/1
hydroxide  alkalinity.    Boiler   plants   with   hydrazine
treatment produce a blowdown containing 0-2 mg/1 ammonia.

In  PWR  nuclear-fueled  powerplants,  the  steam  generator
employs ultrafine quality water.  Consequently the  blowdown
frequency  and  the  impurities  are  much less than that in
fossil fuel plants.

The blowdown frequency is commonly once a day.  Most of  the
data  also  confirm  the  typical  alkaline  nature  of  the
blowdown.  The data do  not  show  completely  the  type  of
treatment  and  the  raw  water  treatment efficiency.  Con-
sequently,  the  data  have  greatly   varying   parameters.
Reference  21 reports waste water flows from boiler blowdown
ranging from 0-U gal/1000 Ib steam generated.

Equipment Cleaning

Chemical Cleaning Boiler or PWR Steam Generator Tubes

Boilers  are  subject  to  two  major   chemical   problems,
corrosion  and  scale formation.  Proper operation and main-
tenance involves the pretreatment of  boiler  makeup  water,
and  the  addition  of  various  corrosion and scale control
additives to the feed  water.   Boilers  operating  at  high
pressures  (and  temperatures) require more critical control
of boiler water chemistry than low pressure boilers.
                          136

-------
Even with the best preventive maintenance, occasional boiler
cleaning is a necessary operation for proper performance  of
steam  boilers.  Condenser leaks, oxygen leaks in the boiler
water and corrosion/erosion  of  metallic  parts  by  boiler
water may increase the frequency of boiler cleanings.

The  data  in Table A-V-5 shows pollutant concentrations for
specific cases.  Inasmuch as boiler cleaning is tailored for
individual  requirements,  generalization  about   pollutant
concentration  is  not  possible.   However,  the  data does
indicate generally observed high amounts of metallic species
and COD requirements.

In this study, boiler tube cleaning was not  categorized  on
the  basis  of once-through or drum-type.  However, it is to
be noted that similar cleaning as described earlier is  fol-
lowed for once-through type boilers.

In  nuclear  powerplants  of the PWR type, strict control on
the quality of steam generator water is maintained.   Clean-
ing  frequently  varies  with  plant  characteristics, as in
fossil-fuel power plants, but the cleaning methods  are  the
same.

Chemical  cleaning of boilers can be of two types - 1)  Pre-
operational—necessary for  new  boilers  before  going  on-
stream and 2)  Operational-necessary for scale and corrosion
products   removal   to  maintain  normal  boiler  operating
performance.

Preoperational Boiler Cleaning Wastes

During  the  manufacture  and  assembly  of   boiler   steel
components,  a black iron oxide scale (mill scale) is formed
on metal surfaces.  The removal of mill scale  is  necessary
to  eliminate  potential  galvanic  corrosion and erosion of
turbine blades which can occur because of trapped mill scale
in the steam path.  Similarly, the presence of  oil,  grease
(used  during  fabrication  and  assembly)  and construction
debris  can  be  detrimental  to   boilers.    Consequently,
preoperational cleaning of boilers is an important aspect of
powerplant start-up procedures.

Typical steps for preoperational cleaning involve:

(i)  an alkaline boilout using a solution containing caustic
or  soda  ash, phosphates, wetting or emulsifying agents and
sodium nitrite as an inhibitor to  protect  against  caustic
embrittlement.
                          137

-------
          TABLE  A-V-5




CHEMICAL HASTE CHARACTERIZATION
A
Site"

3409
3409
3410
3412
3414
3416
3404
3603
3603
3604
3604
3604
3604
3604
3605
3605
3605
3605
3605
3605
3606
3606
3609
3609
3609
3607
3610
3610
3610
3610
3611
3611
3612
3612
3612
3612
3612
3612
3612
3612
3612
3612
3614
3614
3614
3614
3614
3614
3613
3613
3613
B
Cleaning
months
24
24
12
24
12


22
23
15
20
13
7
20
50
60
SO
12
24
24
36
22
48
100
74
15
12
9
18
15
50
100
60
30
50
40
24
30
36
40
40
30
40
24
20
36
14
12
30
24
24
C
Boiler
n,3
174
174
106
215
303
190
571
314.58
117.1


278.8
163.4
163.4
261.19
261.19
261.19
143.45
143.45
189.3
183.1
183.1
108.95
108.95
108.95
148.903
136.18
136.18
136.18
136.18
129.6
129.6
52.65
52.65
52.65
52.65
77.17
77.17
77.17
77.17
137.54
137.54
59.9
74.4
74.4
74.4
74.4
74.4
74.9
74.9
74.9
INCREASE IN POLLUTANT QUAN .'ITY PER CLEANING CYCLE
BOILER TUBES' CLEANING
D EF GHIJKLMNOP
Volume Alkalinity (CaCOi) BOD ' COD Total Solids Dissolved Solids Suspended Solids
(1000 gal.) (Ib) Kg (Ib) kg (Ib) kg (Ib) kg (Ib) kg (Ib) kg
46 1380 626 104 47.2 4017 1823 11816 5369 8588 3899 176 80
46 1380 626 104 47.2 4017 1823 11816 5369 8588 3899 176 80
28 181 82 -9.8 -4.45 5091 2311 12024 5458 10684 4850 9.8 4.45
57 -158 -72 -8.3 -3.8 8302 3769 11972 5435 11225 5096 75 34
80 3770 1711.9 121.4 55 11101 5040 34817 15807 1983 900.4 505.2 229.4
50 158.4 71.94 -1.65 -0.75 9169 4163 39698 18023 37196 16887 246 111.7
150.8 -23.8 -10.84 0 0 -14.07 -6.39 99.34 45.1 99.34 45.1 0 0
83.09 -- -- -__ -----
30.93 -- -- _-_ -----
43.165 -- - - --- -- --
43.165 -- -- --- -----
92.92 -_- - - - - - --
35.97 -- -- --- -----
35.97 -- -- -_- -----
69.18 -- -- _-- -----
69.18 -- -- -_- -----
69.18 -- - - -_- -- --
37.89 -- -- --- -----
37.89 -- - - -_- -- --
50.0 -- -- --- -----
48.37 -- -- --- -----
48.37 -- -- -_- --___
28.78 -- - - -_- -- --
28.78 -- -- --_ -----
28.78 -- -- --- -----
39.33 -- -- --- -----
35.97 -- -- -__ _.---
35.97 -- -- --- -----
35.97 -- •- --- -----
35.97 -- -- -_- -----
34.23 -- -- --- -----
34.23 -- -- --- -----
13.9 -- -- -_- -----
13.9 -- -- --- -.---
13.9 -- -- -_- -----
13.9 -- -- --- -----
20.38 -- -- .-- -----
20.38 -- -- -_- -----
20.38 -- -- --- -----
20.38 -- -- --- -----
36.33 -- - - --- -- --
36.33 -- -- --- -----
15.82 -- -- _-- -----
19.66 -- -- --- -----
19.66 -- -- --- -----
19.66 --'- - --- -- --
19.66 -- -- --- -----
19.66 -- -- -_- -----
19.78 -- -- --- -----
19.78 -- -- _-- -----
19.78 -- -- -_.
Q R
Ammonia
(Ib) kg
16.7 7.58
16.7 7.58
1.2 0.54
9.8 4.45
52.86 24.0
3.2 1.454
0 0
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
.

-------
          TABLE A-V-5

CHEMICAL WASTE CHARACTERIZATION
A
Plant
Code

3409
3409
3410
3412
3414
3416
3404
3603
3603
3604
3604
3604
3604
3604
3605
3605
3605
3605
3605
3605
3606
3606
3609
3609
3609
3607
3610
3610
3610
3610
3611
3611
3612
3612
3612
3612
3612
3612
3612
3612
3612
3612
3614
3614
3614
3614
3614
3614
3613
3613
3613
B C
Nickel
(Ib)
95.8
95.8
-
—
294
108.4
-
Ill
-
-
-
100
-
-
81.9
-
-
-
-
-
577
-
33
-
-
46.2
-
-
44
-
41.8
-
-
-
-
-
-
-
-
-
44.0
-
-
-
-
-
24.23
-
24.23
-
-
kg
43.5
43.5
-
—
133.88
49.22
-
50.4
-
-
-
45.4
-
-
37.2
-
-
-
-
-
262
-
15
-
-
21
-
-
20
-
19
-
-
-
-
-
-
-
-
-
20
-
-
-
-
-
11
-
11
-
-
D E
Zinc
(Ib)
5.99
5.99
10.3
-0.045
169.6
91.56
0.00018
141
-
-
-
126
-
-
106
-
-
-
-
-
74.89
-
44 •
-
-
59.4
-
-
55
-
52.8
-
-
-
-
-
-
-
-
-
55
-
-
-
-
-
30.8
-
30.8
-
-
kg
2.72
2.72
4.67
-0.02
77
41.57
0.00008
64
-
-
-
57.2
-
-
48.1
-
-
-
-
-
34
-
20
-
-
27
-
-
25
-
24
-
-
-
-
-
-
-
-
-
25
-
-
-
-
-
14
-
14
-
-
INCREASE IN POLLUTANT O.UABTITY PER CLEANING CYCLE
BOILER TUBES' CLEANING (continued)
F GHIJKLH
Sodium Nitrate Hardness Bromide
(Ib)
1076
1076
2018
-
4885
12378
-55.9
-
-
2569
2569
3504
1902
2742
3363
3363
5007
2200
1515
2031
132
243
128
-
-
-
2603
1301
2603
-
3500
5374
1144
573
1144
573
3027
3027
-
-
-
-
201
-
55.7
-
1440
2161
2105
810
2105
kg (Ib) kg
488 0.56 0.25
488 0.56 0.25
916 -5.6 -2.54
-0.542 -0.25
2218 2.9 1.32
5620 0.817 0.371
-25.46
_
-
1166
1166
1590
863
1244
1526
1526 - ' -
2273
998
687
922
82
110.3
58
_
-
_
1181
590.6
1244
_
1589
2441
519
260
519
260
1374
1374
- - -
-
-
_
91.4
-
25.28
_
653
981
955
367
955
(Ib) kg (Ib)
I'll 550
1M1 550
•i-
-29.19 -13.25
89.86 40.8
-
1.25 0.57
-
_
484
484
492
582
484
-
-
_
503
503
773
635
847
444
- -
- -
-
476
635
476
476
465
465
481
243
481
243
270
270
- -
- -
- -
-
698
- -
193
-
-
-
201
328
201
kg
_
-
-
-
-
-
-
-
-
219.7
219.7
223
264
219.7
-
-
-
928
228
350.9
288
384
201
-
-
-
216
288
216
216
211
211
218
110
218
110
122
122
-
-
-
-
317
-
87.6
-
-
-
91.2
148.9
91.2
N O
Manganese
(Ib) kg
_ _
-
-
•>
-
-
0.0059 0.0027
30.8 14
-
-
-
27.9 12.7
-
- .
48.9 22.2
-
-
-
-
-
15.4 7
-
11 5
-
-
13.2 6
-
-
11 5
-
11 5
-
-
-
-
-
-
-
-
-
11 5
-
-
-
-
-
6.6 3
-
6.6 3
-
-
                                                                                         idity,  Oil and Grease,
                                                                                         rcurj,  Sulfite. Lead-
                                                                                        ileniOni, Pnenolgj Surfactant
                                                                              370
                                                                              370
                                                                              276
                                                                               23
                                                                              387
                                                                              100
                                                                               0

-------
TABLE A-V- 5
A

3409
3406
34 IS
3412
3414
3416
3404
3603
3603
3604
3604
3604
3604
3604
3605
3605
3605
3605
3605
3605
3606
3606
3609
3609
3609
3607
3610
3610
3610
3610
3611
3611
3612
3612
3612
3612
3612
3612
3612
3612
3612
3612
3614
3614
3614
3614
3614
3614
3613
3613
3613
B C D E
Phosphorus Sulfate
(Ib) kg (Ib) kg
4.07 1.84 11.26 5.11
4.07 1.84 11.26 5.11
0.4 0.18 -40 -18.6
-O.O8 -0.036
7.26 3.3 73.37 33.31
-0.001674 -0.00076 0.33 0.15
-0.0125 -0.0057 2.24 1.02
74 33.6
-
-
_
78.9 35.82
-
-
58.72 26.66
-
-
-
_
_
40.97 18.6
-
24.45 11.1
- - - -
-
33.76 15.33
- - - -
-
30.1 13.7
-
28.7 13.05
-
-
-
- . -
-
-
-
-
-
30.9 14.03
-
-
-
-
-
17.24 7.83
-
17.24 7.83
-
-
F
(1C)
7772
7772
19100
6142
25898
32191
6.03
40361
15052
21006
21006
45224
14588
14588
42085
38290
42085
18440
18440
24332
29422
29422
13167
13167
13167
19140
14588
17506
14588
14588
19477
16696
6768
8460
6768
8460
8266
8266
12398
11572
17101
14733
9625
11962
9568
11962
11962
11962
8022
8022
8022
G
kg
3528
3528
8671
2788
11758
14615
2.74
18324
6834
9537
9537
20532
6623
6623
19107
17834
19107
8372
8372
11047
13358
13358
597B
5978
5978
8690
6623
7948
6623
6623
8843
7580
3073
3841
3073
3841
3753
3753
5629
5254
7764
6689
4370
5431
4344
5431
5431
5431
3642
3642
3642
INCREASE
IN POLLUTANT QUANTIFY PEE CLEANING CYCLE
BOILER TUBES' CLEANING (continued)
H I
Fluoride
(Ib)
-
-
-
-
-
-
-
870
-
478
478
2509
514.7
514.7
3837
3837
3837
1050
1050
1385
-
-
1596
-
399
-
514.7
997
514.7
514.7
864.5
864.5
192.8
192.8
192.8
192.8
282
282
1130
1130
504
504
253
1092
546
546
552
829
549
362.3
275
kg
_
-
-
-
-
-
-
395
-
217
217
1139
233
233
• 1742
1742
1742
477
477
628
-
-
724
-
181
-
233.6
452.6
233.6
233.6
392.4
392.4
87.53
87.53
87.53
87.53
128
128
513
513
228.8
228.8
114.86
495
247.88
247.88
250.6
376.3
249.2
164.5
124.8
J K
Aluminum
(Ib)
_
-
-
-
-
-
-
18.94
-
-
-
17
-
-
13.87
-
-
-
-
-
11.0
-
28.6
-
-
8.8
-
-
8.8
-
6.6
-
-
-
-
-
-
-
-
-
8.8
-
-
-
-
-
4.4
-
4.4
-
-
kg
-
-
-
-
-
-
-
8.6
-
-
-
7.7
-
-
6.3
-
-
-
-
-
5
-
13
-
-
4
-
-
4
-
3
-
-
-
-
-
-
-
-
-
4
-
-
-
-
-
2
-
2
-
-
L M
Chromium
(Ib)
6.91
6.91
1.4
1.21
23.17
0.0832
0.035
-
-
-
-
16.9
-
-
13.87
-
-
-
-
-
11.01
-
6.6
-
-
8.8
-
-
—
-
6.6
-
-
-
-
-
-
-
-
-
8.8
-
-
-
-
-
13.2
-
4.4
-
-
kg
3.13
3.13
0.63
0.55
10.52
0.0378
0.0160
-
-
-
-
7.7
-
-
6.3
-
-
-
-
-
5
-
3
-
-
4
-
-
-
-
3
-
-
-
-
--
-
-
-
-
4
-
-
-
-
-
6
-
2
-
-
N 0
Copper
(Ib)
251.6
251.6
245.5
-
718
325
0.00006
800
800
900
800
500
300
600
200
100
25
500
600
600
200
300
400
200
300
300
500
400
500
500
600
400
200
100
200
300
300
400
100
100
300
200
500
100
100
100
50
50
200
200
200
kg
114.2
114.2
111.4
-
326
147.7
0.00003
363
363
408.6
363
227
136.2
272
90.8
45.4
11.35
227
272
272
90.8
136.2
181.6
90.8
136.2
136.2
227 '
181.6
227
227
272
181.6
90.8
45.4
90.8
136.2
136.2
181.6
45.4
45.4
136.2
90.8
227
45.4
45.4
45.4
22.7
22.7
90.8
90.8
90.8
P Q
Iron
(Ib)
599
599
1571
1668
1841
5491
0.001
3100
3100
2400
4900
3800
2200
2100
4000
3000
3000
1100
1100
5000
3500
4500
1500
2500
3000
3000
100
1000
1000
900
2000
2500
900
800
700
500
1000
1000
1500
1000
3000
1500
1600
1400
1200
1000
1000
500
1000
1000
1000'
kg
271.8
271.9 •
713.2
757.2
836
2493
0.00045
1407
1407
1089
2224
1725
999
953
1816
1362
1362
499
499
2270
1816
2043
681
1135
1362
1362
45.4
454
454
408
908
1135
408
363
318
227
454
454
681
454
1362
681
726
635
545
454
454
227
454
454
454
R S
Maqnesium
(Ib) kg
224 101.7
224 101.7
-
-
13.83 6.28
-
-
66 29.9
-
-
-
59.0 26.8
-
-
48.9 22.2
-
-
-
-
-
33 15
-
22 10
-
-
28.6 13
-
-
26.43. 12
-
24.23 11
-
-
-
-
-
-
-
-
-
26.43 12
-
-
-
-
-
13.22 6
-
13.22 6
-
-

-------
                   TABLE A-V-; 6




          CHEMICAL HASTE CHARACTBRIZATIOH



INCREASE IN POLLUTANT QUANT 17K PBR CLEANING CYCIZ





                AIR  PREHEATER CLEANING

Line

1)
2)
3)
4)
5)
6)
7)
A
Plant

3409
3410
3411
3412
3413
3414
3415
»
C
D
E
P
frISSinc'v Batch VoluM Alkalinity
eycl»/yr
12
12
8
12
5
6
4
»
409
852
1363
2272
265
162.8
378.6
(1000 gal.)
108
225
360
600
70
43
100
(Ib)
-72.02
-76.65
-90.08
-530.39
189.73
-19.71
-25.02
kg
-32.7
-34.8
-40.9
-240.8
86.14
-8.95
-11.36
G
COD
(Ib)
14.4
16.87
14.98
35.02
116.7
5.72
9.16
B

kg
6.54
7.66
6.8
15.9
53
2.6
4.16
I
Total
(Ib)
11951
24964
40528
65515
2616
4768
11257
J
Solids
kg
5426
11334
18400
29744
1188
2165
5111
K
Dissolve*
(Ib)
7907
16605
27022
44264
4467
3189
8249
L
Solids
kg
3590
7539
12268
20096
2028
1448
3745
M
Total
Suspended
(Ib)
1975
4008
6603
10788
477.9
785.24
1834
N
Solids
kg
897
1820
2998
4898
217
356.5
833
O
P
Sulzata
(Ib)
1066
2231
3601
6114
692
423.8
979
kg
484
1013
1635
2776
314.2
192.4
444.5
g
Chic
(Ib)
1.801
0
0
9989
0
-8.96
-14.16
*
arid*
kg
0.8178
0
0
4534
0
-4.07
-6.43
BOILER FIRESIDE CLEANING
8)
9>
3410
3411
2
8
2626
90.8
720
24
-240
5.99
-109
-2.72
1134
19
515
8.63
40861
4002
18551
1817
35127
3002
15948
1363
3823
119.09
1736
54.07
11949
299.4
5425
135.9
0
18.01
0
8.18
               AIR PREHEATER CLEANING  (continued)
Line

1)
2)
3)
4)
5)
6)
7)

8)
9)
fi**

3409
3410
3411
3412
3413
3414
3415

3410
3411
B C
Aamonia
(Ib)
2.378
4.49
8.1
12
0.722
0.925
2.176

1.49
0.039
kg
1.08
2.04
3.68
5.45
0.328
0.42
0.988

0.68
0.018
D E
Nitrate
(Ib)
3.414
5.06
11.25
5.48
0.471
1.074
3.37

14.75
0.7
kg
1.55
2.3
5.11
2.49
0.214
0.488
1.53

6.7
0.318
F G
Phosphorus
(Ib)
0.513
2.66
4.67
5.86
0.035
0.559
1.32

11.1
0.257
kg
0.233
1.21
2.12
2.66
0.016
0.254
0.6

5.04
0.117
H I
Hardness
(Ib)
3949
8255
13372
22196
476.8
1577
3709

35409
791.41
kg
1793
3748
6071
10077
216.5
716
1684
BOILER
16076
359.3
J K
Chromium
(Ib)
1.1.,'
24.25
39.03
59.19
0.749
0.458
0.533
FIRESIDE
0.0299
0.998
kg
0.529
11.01
17.72
26.875
0.34
0.208
0.242
CLEANING
0.0136
0.453
L H NO
Copper Iron
(Ib)
4.434
-
-
0
2.907
1.788
1.86
(continued)
_
0.249
kg (Ib)
2.018 1531
3189
5103
0 8506
1.32 3.495
0.812 2.13
0.848 2.379

900
0.113 30
kg
695.1
1448
2317
3862
1.587
0.967
1.08

408.9
13.63
P Q
Magnesium
(Ib)
874.45
1850
2986
4812
107.4
352.4
828

11949
190.35
kg
397
840
1356
2185
48.76
160
376

5425
86.42
R S
Nickel
(Ib)
67.55
140.72
225
375.3
28.63
17.93
20.83

30.02
-
kg
30.67
63.89
102.2
170.38
13
8.14
9.46

13.63
-
               AIR PREHEATER CLEANING  (continued)
Line,

1)
2)
3)
4)
5)
6)
7)
8)
9)
*
sas*

3409
3410
3411
3412
3413
3414
3415
3410
3411
B C
804 lull
(Ib)
1.799
0
0
8630
552
-0.35
1.66
0
9
kg
0.818
0
0
3918
251
-0.16
O.757
0
4.09
D
Zinc
(Ib)
4.43
8.97
14.93
25.02
0.283
1.788
2.07
28.72
2
E
kg
2.011
4.075
6.78
11.36
0.1285
0.812
0.942
13.042
0.908
P
BOD
(Ib)
3.6
0
0
15.01
2.335
1.793
1.668
0
0
G
kg
1.635
0
0
6.815
1.06
0.814
0.757
0
0
H
Turbidity
JTU
495
476
497
478
500
500
498
476
98
              BOILER FIRE3IDB CLEANING (continued)

-------
(ii)  draining  of the solution after achieving satisfactory
removal of  oil,  grease,  silica,  loose  scale,  dirt  and
construction debris etc.

(iii)  rinsing of the boiler

(iv)  acid cleaning of the boiler to remove mill scale using
corrosion inhibited hydrochloric acid or organic acids, such
as  citric  and  formic  acids  or  patented chelating scale
removers.

(v)   draining of the acid solution using nitrogen to prevent
metal rusting

(vi)  second rinsing of the boiler with demineralized water

(vii)   an alkaline boilout to neutralize trapped acid and to
remove trapped hydrogen gas molecules (which if left in  the
boiler can cause metal embrittlement over a period of time)

(viii)  and  finally  followed  by a passivation rinse using
sodium nitrite and phosphate solution.

These typical preoperational cleaning steps are followed for
drum type boilers.  For once-through boilers, process  steps
are  similar  except  that  instead  of  boilout, continuous
flushing is carried out.

The  pollution  parameters  associated  with  preoperational
boiler  cleanings  are extreme pH values (acidic or alkaline
solutions),  phosphates,, nitrates,  BOD  from  the  organic
emulsifying  agents,  oil  and  grease and suspended solids.
The   quantity   of   these   wastes   and   the   pollutant
concentrations vary for each specific case.

Reference U68 describes the preoperational chemical cleaning
program for a nuclear powerpiant.

Operational Boiler Cleaning Wastes

A  variety  of  cleaning formulations are used to chemically
clean boilers whose operation has deteriorated due to  build
up  of  scale and corrosion products.  Analyses of scale de-
posits are made on sample sections of  tubes  cut  from  the
boiler.   Based  on  the  composition of scale discovered in
these samples, a cleaning program is  selected.   Some  pro-
cedures  are  more  effective for copper removal, others for
iron removal, and still  ethers  for  silica  removal.   The
composition of boiler scale and corrosion products is brief-
                           142

-------
ly  described.  This is followed by a description of methods
used to renovate boilers.

Composition of Scale

Boiler  scale  contains  precipitated  salts  and  corrosion
products.     Precipitation    occurs   because   of   local
supersaturation of their  solution  concentration  near  the
heated tube surfaces.  These salts include calcium carbonate
and sulfate, calcium and magnesium phosphates and silicates,
and magnesium hydroxide as principal constituents.  Iron and
copper  oxides  are  present  as  corrosion  byproducts  and
various trace  metals  as  zinc,  nickel,  aluminum  may  be
present  either  as  constituents  of  the feed water, or as
corrosion products.  In addition, mud, silt, dirt  or  other
debris introduced via condenser leaks are also present.  Oil
contamination of boiler water results in carbonation of this
waste  and  this is incorporated into the boiler scale.  The
composition of boiler scale is dependent on the  composition
of  boiler  feed  water,  materials  of construction, boiler
chemical additives, and contaminants leaked into the  boiler
water,  and  therefore  will  differ  with  each  successive
cleaning of the boiler.

Frequency cf Boiler Cleanings

There are many factors which affect  the  cleaning  schedule
for  power  utility  steam  boilers.   High pressure boilers
require more critical  control  cf  feed  water  purity  and
consequently  usually  require  less  frequent cleanings.  A
review of boiler cleaning data in  Table  A-V-5  shows  that
cleaning  frequency varies from once in seven months to once
in one hundred months.  The mean time between boiler  clean-
ings  is  estimated  from these data as thirty months with a
standard deviation of eighteen months.

Reference 469, prepared by the ASME Research Committee  Task
Force  on  Boiler  Feedwater  Studies,  is  a  report  of an
investigation  of  current   practices   regarding   factors
influencing  the  need   (frequency) for chemical cleaning of
boilers.

Types of Boiler Tube Cleaning Processes

Alkaline Cleaning Mixtures with Oxidizing Agents for  Copper
Removal

These  formulations  may  contain  free ammonia and ammonium
salts,  (sulfate or carbonate), an oxidizing  agent  such  as
potassium   or  sodium  bromate  or  chlorate,  or  ammonium
                          143

-------
persulfate, nitrates  or  nitrites,  and  sometimes  caustic
soda.  Air is sometimes used as the oxidant.  These mixtures
clean  by the following mechanism:  Oxidizing agents convert
metallic copper deposits to copper  oxide.   Ammonia  reacts
with  the  copper  oxide  to  solubilize  it  as  the copper
ammonium blue complex.

Since metallic copper interferes with the conventional  acid
cleaning  process described below, this cleaning formulation
is frequently used to precede acid cleaning when high copper
levels are present in the boiler scale.

The pollutants introduced by these cleaning formulations are
as  follows:   ammonium  ion,  oxidizing  agents,  high  al-
kalinity,  and  high levels of iron and copper ion dissolved
from the boiler scale.

Acid Cleaning Mixtures

These mixtures are usually based on  inhibited  hydrochloric
acid  as  solvent,  although sulfuric, sulfamic, phosphoric,
nitric, citric, formic  and  hydroxyacetic  acids  are  also
used.   Hydrofluoric  acid  or  fluoride salts are added for
silica removal.  Corrosion inhibitors, wetting  agents,  and
complexing agents to solubilize copper may also be included.

These  mixtures  are  effective  in  removal of scale due to
water hardness, iron  oxides,  and  copper  oxide,  but  not
metallic copper.

The principal pollutants introduced to the waste stream from
these cleaning chemicals are acidity, phosphates, fluorides,
and  organic  compounds  (BOD).  In addition large quantities
of copper, iron,  hardness,  phosphates  and  turbidity  are
released  as a result of loosening and dissolving the boiler
scale.

Alkaline Chelating Rinses and Alkaline Passivating Rinses

These formulations contain ammonia,  caustic  soda  or  soda
ash,  EDTA,  NTA,  citrates,  gluconates, or other chelating
agents, and may contain certain phosphates,  chromates,  ni-
trates  or nitrites as corrosion inhibitors.  These cleaning
mixtures may be  used  alone,  or  after  acid  cleaning  to
neutralize residual acidity and to remove additional amounts
of iron, copper, alkaline earth scale compounds, and silica.
Their   use  introduces  the  following  pollutants  to  the
discharged wastes:   alkalinity,  organic  compounds   (BOD),
phosphates,  and  scale  components such as iron, copper and
hardness.
                          144

-------
Methods Using Organic Solvents

Organic solvents are also widely used to remove  iron/copper
scales  from boiler tubes.  Two common methods, described in
Reference 444, are:

    1.   Vertan  675 (R)   (Dow  trademark).    This   is   an
ammoniated salt of ethylenediaminetetraacetic acid.  In this
process  the  boiler  is  first  protected  by  injecting  a
corrosion inhibitor, then sufficient Verton 675 or  EDTA  is
pumped  in  to achieve a 5-10% solution.  The boiler is then
fired to 75-100 psi (about 300-325°F)  until  the  iron  has
been  picked  up, the boiler is cooled to 200°F, the chelant
strength is restored to about 5* and air is introduced  into
the unit.  This oxidizes the copper to the cupric form which
is  readily complexed.  The boiler is drained, rinsed and is
made ready for service.  The pH of  this  solvent  is  about
9.5.

    2.   Citrosolv  Process.   This  is   another   two-step
process.    It   starts  with  a  3%  citric  acid  solution
ammoniated to a pH of 3.5.  The solution is circulated at  a
temperature  of 200°F for 6-8 hours or until all of the iron
has been picked up.  The second step calls for  raising  the
pH  to 9.2 - 9.5 by addition of anhydrous or aqueous ammonia
after cooling the boiler to 150°F.  Air is then injected  to
oxidize the copper and finally sodium nitrite is injected to
assist in rendering passive surfaces.  A final demineralized
water or condensate rinse completes the job.

Proprietary Processes

Frequently boiler tubes are cleaned by specialized companies
using proprietary processes and cleaning chemicals.  Most of
these  chemicals  are similar to those described earlier and
the resulting wastes contain:  alkalinity, organic compounds
(BOD), phosphate, ammonium compounds,  and  scale  compounds
such as iron, copper and hardness.

Condenser Cleaning

The  other  major heat transfer component in a boiler system
is the condenser.  The  spent  steam  from  the  turbine  is
liquefied  in  the  condenser by the condenser cooling water
system.  Condenser tubes are made out  of  stainless  steel,
titanium  or  copper alloys.  Preoperational cleaning of the
condensers is done with alkaline solutions, with emphasis on
the steam side of the  condenser  because  of  high  quality
water  circulation.   Operational cleaning on the steam side
depends  upon  boiler  water  quality  and   is   not   done
                         145

-------
frequently.  The water side of the condenser is cleaned with
inhibited hydrochloric acid.

Boiler Fireside Cleaning

The  fireside  of  boiler tubes collects fuel ash, corrosion
products and airborne  dust.   Gas-fired  boilers  have  the
cleanest combustion process.

In  order  to  maintain  an  efficient heat transfer, boiler
firesides are cleaned with high pressure fire  hoses,  while
the  boilers  are hot.  Soda ash or other alkaline materials
may be used to enhance the  cleaning.   Depending  upon  the
sulfur  content of the fuel, the cleaning wastes are more or
less acid.

Data was available from only two plants for boiler  fireside
cleaning.   These  data  are shown in Table A-V-6.  The pol-
lutants in the waste stream may reveal extreme values of pH,
hardness and suspended solids as well as some metals.

Air Preheater Cleaning

Air preheaters are an integral part of the steam  generating
system.   They  are used to preheat the ambient air required
for combustion and thus economize thermal energy.  Two types
of preheaters are  used  —  tubular  or  regenerative.   In
either  case,  part  of  the sensible heat of the combustion
flue gases is transferred to the incoming fresh air.

In tubular air preheaters, cold fresh air is forced  through
a  heat exchanger tube bundle using a forced-draft-fan.  The
flue gases leaving the economizer flow around the tubes  and
heat   is   transferred   through   the   metal   interface.
Regenerative type preheaters are  used  more  frequently  in
large  powerplants.   In  this  type, heat is regenerated by
using metallic elements in  a  rotor.   The  rotor  revolves
between  two ducts — outlet duct carrying hot flue gases to
the stack and intake duct carrying fresh air to  the  boiler
windbox.  Heat is transferred to the metallic elements which
in turn transfer it to the fresh air by convection.

Soot  and  fly  ash accumulate on the preheater surfaces and
the deposits must be removed periodically to  maintain  good
heat  transfer  rates  as  well  as to avoid plugging of the
tubes or  metallic  elements.   Preheaters  are  cleaned  by
hosing them down with high-pressure water from fire hoses.

Depending  upon the sulfur content of the fuel, the cleaning
wastes are more or less acidic in nature.  The washing fluid
                          146

-------
may contain soda ash and phosphates or detergents which have
been added to neutralize  excess  acidity  or  alkaline  de-
pending  on  the  cleaning  product used.  Fly ash and soot,
rust, magnesium salts, and metallic ions  leached  from  the
ash and soot are normal constituents of the cleaning wastes.
Copper,  iron, nickel, and chromium are usually prevalent in
this discharge, and in oil-fired installations vanadium  may
also be present at significant levels.

Cleaning  frequency  is  usually  about  once  a  month, but
frequencies of H to 180 cleanings per year are  reported  in
Table A-V-5.

Chemical  data  for air preheater cleaning are also shown in
Table A-V-5.  Data for plant number 3412 appears to  deviate
considerably  from  the  other  plants, and much of the data
reported varies considerably from other plants, by  as  much
as an order of magnitude.

Feedwater Heaters Cleaning

According  to  Reference 4U4, the number of closed feedwater
heaters in the preboiler cycle ranges from H to  10.   Tubes
may  be  formed  from  admiralty  brass; 90/10, 80/20, 70/30
cupro-nickel; monel and arsenical copper in  the  nonferrous
group  and  carbon  steel and stainless steel in the ferrous
family.  Tube sizes are 5/8" or 3/4" O.D. by 15 to  80  feet
long.    They   may  be  straight  or  hairpin  bent  tubes.
Feedwater flows through the tubes, extracting heat from  the
steam which surrounds the tubes.

Pre-operationally  both  sides of the heaters may be cleaned
to remove oils, grease, dirt and preservative  coatings  put
on by the manufacturer.  The cleaning solvent is generally a
solution  of  O.OX  to  l.OX tri-sodium phosphate containing
wetting agents.  Recirculation at 180°F is maintained for 6-
12 hours.  Draining and  rinsing  with  demineralized  water
completes  the  job.   In  some  cases the water side of the
heaters are also acid cleaned using an organic acid such  as
3%  solution  of citric, ammoniated citric or hydroxyacetic-
formic acids  at  190°F.   Sometimes  these  jobs  are  done
simultaneously with the cleaning of the boiler.  Again there
is  a  reluctance to acid clean the steam side of the heater
for fear of acid "hanging up" in crevices.

Operational cleaning in general has not been required on the
ferrous alloy tubes.  Deposits found on the  water  side  of
the  copper  alloy tubing have been predominantly copper and
iron  oxides.   The  common  solvent  used  has  been  5-20%
hydrochloric acid, circulated for 6-8 hours at a temperature
                            147

-------
of   150°F.    Neutralization   of   the   system  has  been
accomplished by circulating a 0.5 - 1.0* soda ash or caustic
soda solution for 2-3  hours  at  120-150°F.   Rinsing  with
demineralized water completes the cleaning process.

Miscellaneous Small Equipment Cleaning

At infrequent intervals, other plant components such as con-
densate  coolers,  hydrogen coolers, air compressor coolers,
stator oil coolers, etc. are cleaned chemically.   Inhibited
hydrochloric  acid  is  a common chemical used for cleaning.
Detergents and wetting agents are also added when necessary.
The  waste  volume  is,  of  course,   smaller   than   that
encountered  in other type of chemical cleanings.  Pollutant
parameters are  low-high pH, total  suspended  solids  (TSS)
metallic components, oil, etc.

Stack Cleaning

Depending  upon  the  fossil  fuel  used, the stack may have
deposits of fly ash, and soot.  Acidity  in  these  deposits
can be imparted by the sulfur oxides in the flue gases. If a
wet  scrubber  is  used  to  clean  the flue gas, process or
equipment upsets can result in  additional  scaling  on  the
stack  interior.   Normally,  high-pressure water is used to
clean the deposits on stack walls.  These wastes may contain
total  suspended  solids  (1SS) ,  high  or  low  pH  values,
metallic species, oil, etc.

Cooling Tower Basin Cleaning,

Depending  upon the quality of the make-up water used in the
cooling tower, carbonates can  be  deposited  in  the  tower
basin.    Similarly,  depending  upon  the  inefficiency  of
chlorine dosages, some  algae  growth  may  occur  on  basin
walls.   Seme  debris  carried  in  the  atmosphere may also
collect in the basin.  Consequently, periodic basin washings
with water  is  carried  out.   The  waste  water  primarily
contains total suspended solids (TSS)  as a pollutant.

Ash Handling

Steam-electric  powerpiants  which  utilize oil or coal as a
fuel produce ash as a  waste  product  of  combustion.   The
total  ash  is of two sorts: bottom ash and fly ash.  Bottom
ash is the residue which accumulates in the furnace  bottom,
and  fly  ash  is  the material which is carried over in the
flue gas stream.
                           148

-------
Ash-handling  or  transport  is  the   conveyance   of   the
accumulated waste products to a disposal system.  The method
of   conveyance   may   be  either  wet  (sluicing)   or  dry
(pneumatic).  This section discusses the  wet  ash  handling
system and in particular* the waste water which it produces.

The  chemical characteristics of ash handling waste water is
basically a function of  the  fuel  burned.   The  following
table  from  Reference  278 lists commercial fuels for power
production.
          »
        Fuels Containing          Fuels Containing
              Ash                 Little or No Ash

   All coals                 Natural gas
   Fuel oil-"Bunker C"       Manufactured gas
   Refinery sludge           Coke-oven gas (clean)
   Tank residues             Refinery gas
   Refinery Coke             Distillates (most)
   Most tars                 Combustion-turbine exhaust
   Wood and wood products
   Other products of vege-
     table
   Waste-heat gases (most)
     Blast-furnace gas
     Cement-kiln gases

Of the fuels containing ash, coals and fuel oil  are  mostly
used in the power industry.

Coal

Coal  is  the  most widely used fossil fuel in United Stated
powexplants.  In 1972, 335 million tons of  coal  were  con-
sumed  in  the  U.S.  for power generation.  The average ash
content of coal is 11% for the nation, Z3B with a range from
6 to 20%.  It  may,  therefore  be  estimated  that  roughly
37,000,000  tons of ash were produced in 1972 by U.S. power-
plants.  Disposal of this quantity of solids from the  waste
water  stream  has  prompted  most utilities to install some
sedimentation facility.  In many cases, ash  settling  ponds
are  used.  A typical ash pond is illustrated in Figure A-V-
9, which is located in plant no.  4217.   However,  in  some
cases,  because  of  unavailability  of land, aesthetics, or
some   other   reason,   utilities   have   installed   more
sophisticated   materials-handling   systems  based  on  the
sedimentation process.

The characteristics of the water handling coal  ash  is  re-
lated  to the physico-chemical properties of that ash and to
                           149

-------


                           "*£:>JL'
rZ£3?^m%&:
       TYPICAL ASH POND
        PLANT NO. 4217
        Figure A-V-9
           150

-------
the volume and initial quality of the water used.  Table  A-
V-7  lists some of the constituents of coal ash.23a Table A-
V-8 shows the volume and time variabilities of water flow in
an ash handling system.  Reference  21  reports  that  water
requirements for ash handling are as follows:

         fly ash 1,200-40,000 gal/ton ash conveyed

         bottom ash 2,400-40,000 gal/ton ash conveyed

Data obtained from discharge permit applications on ash pond
overflows for 33 plants burning coal indicates a wide  range
in  the overflow quantities, from about 0.2 MGD  per 1000 Mw
of generating capacity to  about  50  MGD  per  1000  Mw  of
capacity.  The data, as MGD per 1000 Mw,  approximate a log-
normal  distribution,  with  50  percent  of  the  ash  pond
overflows being less than 5 MGD per 1000 Mw and  60  percent
less  than  10  MGD  per  1000 Mw.  Based on the annual coal
consumption reported for these plants (Ref.: Steam  Electric
Plant  Factors/1971), the overflows range from about 0.1 MGD
per million tons coal burned per year to about  16  MGD  per
million  tons  coal  burned per year, with a median value of
about 4 MGD per million tons coal burned per year.

The relative percentages of bottom ash and  fly  ash  depend
upon  the mode of firing and the type of combustion chamber.
Following figures are satisfactory averages, for a  coal  of
13,000 Btu/lb.

     Type of operation              Fly ash  (% of total ash)

Pulverized coal burners
Dry bottom, regardless of type                85
  of burner
Wet bottom                                    65
  (without fly ash reinjection)
Cyclone furnaces                              20
Spreader stokers
  (without fly ash reinjection)               65

The number of variables involved in characterizing the water
used  for  ash handling is such that it is not probable that
any two plants would exhibit the same waste  stream  charac-
teristics.   The approach taken in this report is to examine
a cross section of plant data.  There are no data  available
on the actual ash sluicing waste water.  However, since most
plants  now  employ  a  settling pond, the ash pond overflow
data  can  be  used  to  evaluate  associated  waste   water
characteristics.  These data are summarized in Table A-V-9.
                           151

-------
              Table A-V- 7
      CONSTITUENTS OF COAL ASH
                               238
Constituent
  Si°2
  A12°3
  Fe2°3
  CaO
  MgO
  so3
  C and volatiles
  P
  B
  U and Th
  Cu
  Mn
  Ni
  Pb
  Zn
  Sr
  Ba
  Zr
Percent
 30-50
 20-30
 10-30
0.4-1.3
1.5-4.7
0.5-1.1
0.4 1.5
1.0-3.0
0.2-3.2
0.1-4.0
0.1-0o3
0.1-0.6
O.O-Ool
 trace
 trace
 trace
 trace
 trace
 trace
 trace
 trace
               152

-------
                          Table A-V- 8
            TIME OF FLOW FOR ASH HANDLING SYSTEMS
      Plant No. 0110,  a 952 Mw unit  fueled by pulverized  coal
                 - basis is one 8-hr  cycle —
Duty
H. E. #1
Flushing
H. E. #2
Flushing
H. E. #3
Flushing
Purge
Fill
Pyrites Tank
Purge
Grlder Seal
Mill Rejects
Pressure Transfer
Hydrovac*
Bubblers
Cool Weirs
Pyrites Tank Make-up
Flow Rate, gpm
1,960
600
1,960
600
1,960
600
1,960
1,500
2,660
2,660
8
515
1
4,604
4
540
640
Duration, minutes
73
15
60
20
47
15
3x8 each
3 x 15 each
12
8
180
7x6 each
210
270
continuous
continuous
12
*NOTE:  Only significant Hem pertaining to fly ash handling.
       other Items pertain to bottom ash handling.
All
                             153

-------
                                                                                         TABLE A-V- 9




                                                                                CHEMICAL WASTE CHARACTERIZATION




                                                                               ASH POND OVERFLOW -i NET DISCHARGE





                                                                       CHANGE  IN PARAMETER LEVEL .FROM INTAKE  TO  DISCHARGE
Code Plant Capacity 	 £s>el_ . .


3412
3416
3404
3402
34O1
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
*3936
3927
2616
1808
1729
1718
393O
3930
•393O
1825
1825
1825
1825
•1825
3920
1816
2608
0111
4704
2119
2119
•2119
0107
3514
1716
1716
*1716
MM

1114.5
740
300
308
31
116.2
766
1178
1162
1232
690


1179


1086
1469
933
732
186
1042


500




1304
544
600
510
1300
823


2558
568
2152


676
MWHr/day

13205
10525
5420
4965
865
1629
6288
16155
3164
15563
0706


21872


18908
21705
14276
12050
2978
13856


3816




24813
7695
10149
7550
18169
9874


31458
5741
11315


11092
C - Coal
0 - Oil
C/0
C
C/0
C/0
C
C/0
C
C
C/0
C
0


C


C
C
C
C
C
C/0


C




C
C
C
C
C
C


C
C
C


C
Flow
n>3/day

19574
13100
2556
2726
9132
18.17
22716
49218
2726
98436
3786
32560
2650
35210
3786
22716
26502
5300
15901
15144
1817
53000
15144
3786
18930
37103
12115
6058
114
55390
27259
3786
5679
27782
15434
40694
82252
122946
2726
10865
1893
568
2461
(lOOOgpd)

5170
3460
675
720
2412
4.8
6000
13000
720
26000
1000
8600
700
9300
1000
6000
7000
1400
4200
4000
480
14000
4000
1000
5000
9800
3200
1600
30
14630
7200
1000
1500
7338
4076
10748
21725
32473
720
2870
500
150
650
mg/1

3560
-23
1879
54
-1338
-18509
-240
362
0
112
309
509
506

387
680

647
0
121
670
79
1124
1084

626
525
500
1000

300
1290
230
295.5
-1
475
61

182
-
414
324

Total solids
(Ib/day)

153490
-663
10577
324
-26914
-745
-12008
39247
0
24284
2574.9
36506
2954
39460
3227
34026
37253
7552
0
4035
2680
9222
37491
9013
46504
51163
14011
6669
250.2
72093
18614
10757
2876
18084
- 34
42578
11052
53630
1093
-
1724.7
40S.32
2129.39
kg/day

69688
-301
4802
147
-12219
-338
-5452
17818
0
11025
1169
16574
1341
17915
1465
15448
16913
3429
0
1832
1217
4187
17021
4092
21213
23228
6361
3028
113.6
32730
8451
4884
1306
8210
-15
19330
5017
24347
496.16
-
783
184.01
967
(Ib/MWHr)

11.621''
-0.064
1.952
0.065
-31.1
-0.457
-1.91
2.423
0
1.54
0.295
1.652
0.135
1.787
0.169
1.799
1.968
0.345
0
0.334
0.9
0.665
9.82
2.356
12.176
2.06
0.564
0.268
0.01
2.9031
2.41
1.06
0.362
0.9953
-.0034
1.SS35
.1513
1J7048
OJ1904
-
.X553
.0365
0.1928
kg/MWHr

5.272
-0.0292
0.886
0.0296
-14.12
-0.207
-0.867
1.1
0
0.7
0.134
0.075
0.061
0.0811
0.077
0.816
0.893
0.157
0
0.152
0.408
0.302
4.46
1.07
5.53
0.936
0.256
0.122
0.0045
1.319
1.098
0.481
0.164
0.4518
-.0016
.6145
.1595
0.7740
0.0864
-
.0705
.0166
0.0871
mg/1

3328
-110
1852
40
-1309
-18520
-129
330
108
106
328
486
499

447
650

620
0
364
646
75
1059
1081

611
435
460
500

-320
1210
225
-
-
-
-

193
844
445
277

Total
(Ib/day)

143495
-3174
10423
240.2
-26323
-741.41
-6453
35777
648.45
22984
2735
34856
2912
37768
2892
32524
35416
7237
0
12143
2586
8755
35328
9013
44341
49934
11608
6136
125.11
67803
-18614
10090
2812
-
-
-
-
-
1159
20201
1854
346.52
2200
Dissolved Solids
kg/day

65147
-1441
4732
109.04
-11951
-336.6
-2930
16243
294.4
10435
12417
15825
1322
17147
1313
14766
16079
3286
0
5513
1174
3975
16039
4092
20131
22670
5270
2786
56.8
30782
-8451
4581
1277
-
-
-
_
-
526
9171
842
157.32
999
(Ib/MWHr)

10.87
-0.308
1.92
0.483
-30.41
-0.455
-1.026
2.12
0.2048
1.475
0.3127
1.586
0.133
1.719
0.153
1.719
1.873
0.3326
0
1.006
0.868
0.632
9.25
2.356
11.606
2
0.467
0.247
.00504
2.72
-2.398
0.994
0.354
-
-
-
-
-
0.2019
1.785
.1672
.0312
0.1984
kg/MWHr

4.929
-0.14
0.873
0.219
-13.81
-0.206
-0.465
1
0.093
0.67
0.142
0.72
0.06
0.78
0.069
0.78
0.85
0.151
0
0.457
0.394
0.287
4.2
1.07
5.27
0.91
0.212
0.112
0.00229
1.237
-1.098
0.4513
0.1607
-
-
-
_
-
0.0917
0.8098
.0759
.0142
0.0891
mg/1

91
40
27
14
1
11
-111
32
0
-1
-13
23
7

17
94

17
0
-243
51
1
65
3

15
85
35
100

-4
36
5
-
-
-
-

-11
-337
-7
69

Total Suspended Solids
(Ib/day)

3923
1154
152
84.05
20.11
0.44
-5552
3469
0
-216.7
-108.3
1647
40.86
1687.86
141.76
4702
4843.76
198.45
0
-8105
203 . 96
116.74
2167.4
25
2192.4
1224.67
2268
4669
25.02
8186
-300
300
62.53
-
-
_
_
-
-66.05
-8066
-29.07
86.319
57.25
kg/day

1781
524
69
38.16
9.13
0.20
-2521
1575
0
-98.4
-49.2
748
18.55
766.55
64.36
2135
2199.36
90.1
0
-3680
92.6
53
984
11.35
995.35
556
1030
212
11.36
1809
-136.3
136.3
28.39
-
-
-
_
-
-29.98
-17767
-13.2
39.188
26
(Ib/MWHr)
x 106
2 97 J 00
112066
28044
16931
2323
270
-89867
213656
0
-13920
-12445
75110
1868
76978
7467
248678
256145
9141
0
-671800
68491
8266
567841
6555
574396
49339
91418
18819
1008
160584
-39017
29581
7868
-
_
_
_
-
-11504
-712900
-2621
7782
5161
kg/MWHr
x 106
134800
50878
12732
7687
1055
123
-40800
97000
0
-6320
-5650
34100
848
34948
3390
112900
116290
4150
0
-305000
31095
3753
257800
2976
260776
22400
41504
8544
458
72906
-17714
13430
3572
-
-
_
_
-
-5223
-323400
-1190
3533
2343
•total of more  than one waste stream  for  plant

-------
                                                                                       TABLE A-V-9




                                                                             CHEMICAL HASTE CHARACTERIZATION
ASH Dnun nupppiiw;.-
Plant
Code
3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
*3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
1825
1825
•1825
3920
1816
2608
0111
4704
2119
2119
-2119
0107
3514
1716
1716
•1716
Total Hardness ICaCCb )
mg/1
736
25
-
-12
-
-252
-
99
255
357
220
110

207
335

275
-
-
388
51
340
350

406
250
200
270

-
-
0
283
-134.8
272.3
31.3

-
-
83
74

(Ib/day)
31733
1010
-
-72.04
-
-10.04
-
10731
55293
2975
15777
642
16419
1724
16762
18486
3209
-
-
1552
5953
11341
2918
14259
33182
6671
2668
67.55
42588
-
-
0
17319
-4582
24408
5671
30079
-
-
346
92.57
438
kg/day
14407
458.5
-
-32.71
-
-4.56
-
4872
25103
1351
7163
291.55
7454
783
7610
8393
1457
-
-
705
2703
5149
1325
6474
15065
3029
1211.5
30.67
19336
-
-
0
7863
-2078
11081
2574
13655
-
-
157.1
42.02
199
(lb/MWHr)
x 106
2403000
98057
-
-14513
-
-6165
-
662995
3.546xl06
341409
720264
29361
749625
90969
886249
977218
147577
-
-
521445
429687
2970000
764860
3735000
1320000
268881
107541
2722
1699000
-
-
0
953233
-464000
775892
180278
956170
-
-
31057
8346
39403
kg/MWHr
x 106
1090000
44518
-
-6589
-
-2799
-
301000
1610000
155000
327000
13330
340330
41300
402357
443657
67000
-
-
236736
195078
1349000
347248
1696000
600000
122072
48824
1236
772132
-
-
0
432768
-210500
352255
81846
434101
-
-
14100
3789
17889
mg/1
152
2.2
120
8
-240
-996
45
-18
43
63
34
286
-26

158
201

60
123
128
527
98
220
300

180
225
314
132

-
200
28
93
61.5
-
-
-
129.9
446
230
-49

MPT* n Td~*HAR<7F (continuGd )







CHANGE IN PARAMETER LEVEL FROM INTAKE TO DISCHARGE
(Ib/day)
6554
63.48
675.5
48.01
-4826
-42.5
2251
-1951
258.19
13658
258.37
20513
-151.78
20665
1317
10057
11374
700
4308
4268
2109
11440
7339
2501
9840
14709
60044
4189
33.01
78975
-
1667
350.22
5691.5
2090.6
-
-
-
840.07
10675
959
-61.3
897.3
kg/day
2973
28.82
306.68
21.8
-2191
-19.3
1022
-886
117.22
6201
117.3
9313
-68.91
9244
598
4566
5164
318
1956
1938
957.5
5194
3332
1135.8
4467.8
6678
2726
1902
14.99
11321
-
757
159
2584
949
-
-
-
381.1
4846
435.4
-27.83
407.6
(Ib, MWHr)
x 106
496300
6163
124378
9676
-5570000
-26165
357929
-120704
81497
876651
29515
936123
-6940
929183
69603
531749
601352
32158
301762
352420
708205
825674
1922907
655599
2578506
592511
241993
168841
1330
1004675
-
164097
44057
313253
211730
-
-
-
146328
943400
86343
-5526
80817
kg/MWHr mg/1 (Ib/day)
x 106
225100 0.075 3.233
2798
56468
4393
-253000O
-11879
16250O
-5480O 0.011 1.19
3700O
3980OO 0.15 32.51
13400 0.1 0.722
42500O 6 0
-3151 -0.145 -0.8326
421849 -0.8326
31600 . -
241414
273014
14600 0.153 1.784
13700O 1.67 58.48
16000O
321525
374856 1.350 157.62
873000 0.021 0.7
297642 0.021 0.175
1070642 0.875
269000
109865
76654
604
456123
_
74500 6 50
20002
142217
96125
-
-
-
66433 5.30 32.12
4283OO -
39200 -0.22 -0.916
-2509 0.1 0.125
36691 -0.12 -0.791
kg/day
1.468
-
-
-
-
-
-
0.541
14.76
0.378
0
-0.384
-0.384
-
-
-
0.81
26.55
-
-
71.56
0.318
0.0795
0.3975
-
-
-
-
-
-
22.72
-
-
-
-
-
-
14.58
-
-0.4160
0.0568
-0.3592
(Ib/MWHr)
x 106
244
-
-
-
-
-
-
72.68
2070
94.71
0
-39.6
-39.6
-
-
-
81.49
4097
-
-
11376
182.82
46.25
229.07
-
-
-
-
-
-
4912
-
-
-
-
-
-
5597
-
-81.49
11
-70.49
kg/MWHr mg/1
x 106
111 -0.113
0
-
0.01
-
0.139
0.00001
33 -0.014
940
43
0 0
-18 -0.03
-18
0.0005
0.007
-
37 0.011
1860
-
-
5165 0.001
83
21
104
0.080
0.004
0.007
0.005
-
-
2230
-
-
-
-
-
-
2541 0
-
-37
5
-28
(Ib/day)
-4.86
0
-
0.059
-
0.0055
0.0005
-1.515
_
-
0
-0.174
-0.17
0.0044
0.35
0.354
0.1277
-
-
-
0.116
-
-
-
6.54
0.105
0.092
0.001251
6.738
-
-
-
-
-
-
-
-
0
-
-
-
-
kg/day
-2.21
O
-
0.027
-
0.0025
0.00023
-0.688
_
-
0
-0.079
-0.079
0.0019
0.159
0.1609
0.058
-
-
-
0.053
-
-
-
2.97
0.048
0.042
0.000568
3.06
-
-
-
-
-
-
-
-
0
-
-
-
-
(lb/MWHr)
x 106
-368
0
-
11
-
3.407
0.079
-92.5
_
-
0
-8.8
-8.8
0.218
17.6
17.81
5.88
-
-
-
8.81
-
-
-
262
4.4
4.4
0.005
270.85
-
-
-
-
-
-
-
-
0
-
-
-
-
kg/MWHr
x 10s
-167
0
-
5
-
1.547
0.036
-42
-
-
0
-4
-4
0.099
8
8.099
2.67
-
-
-
4
-
-
-
119
2
2
0.023
123.03
-
-
-
-
-
-
-
-
0
-
-
-
-
*total of more than one waste stream for plant

-------
                                                                                      TABLE A-V- 9




                                                                             CHEMICAL WASTE CHARACTERIZATION
ASH POND OVERFLOW t- MIT DISCHARGE
Plant
Code
3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
•1711
3936
3936
•3936
3927
2616
1808
1729
1718
393O
3930
*393O
182S
1825
1825
1825
•1829
382O
1816
2608
0111
4704
2119
2119
*2119
0101
3514
1716
1716
*1716

•9/1
0
-4
-
-
52
-1609
982
-
26
-
-3
173

30
32

73
14
-
-
3
92
88

27
23
ia
37

—
21
-
-
-
-

-
-
-49
-1M


(Ib/day)
0
-115.4
-
.
1046
-63.43
106467
-
5638
-
-215.63
10O8
793
250.22
1601
1851.22
852.4
489
-
-
350.2
3068
733.83
3801
2204
613.6
240.15
9.25
3067
_
287.7
-
-
-
-
-
-
-
-U7.66
-170
-397.6
Sodium
kg/day
0
-52.4
-
-
56.07
-28.8
48336
-
2560
-
-97.9
458
361
113.60
726.98
840.58
387
222
-
-
159
1393
333.16
1726.16
1001
278.6
109.03
4.2
1392.83
-
130.5
-
-
-
-
-
-
-
-85.2
-77.24
-162.4
- (continued )
CHANGE IN PARAMETER I£VED FROM INTAKE TO DISCHARGE
Alkalinity (CaCCh )
(Ib/MWHr)
x 106
0
-11204
-
-
1209000
-38940
6.58xl06
-
361233
-
-9845
46176
36331
13200
84656
97856
39207
34350
-
-
25275
B03964
192308
996272
88100
24737
9678
372.2
122887
_
37600
-
-
-
-
-
-
-
-16916
-15339
-32255
kg/MHHr
X 106
0
-5087
-
-
548500
-17679
2.99xl06
-
1640OO
-
-4470
20964
16494
6000
38434
44434
178OO
15595
-
-
11475
365000
873 OS
4423O8
40000
11231
4394
169
55794
-
171OO
-
-
-
-
-
-
-
-7680
-6964
-13644
mg/1
-19
-6
0
160
-
-
-110
10
0
2
7
-67
64

13
13

69
-67
28
-94
-15
120
95

75
48
70
65

-38
216
-63
226.4
-6.2
-93.6
-13.7

-16
443.7
-22
15

(Ib/day)
-819.2
-173.1
0
960
-
-
-5504
1084
0
433.7
58.37
-4804
373
-4431
108.37
650.50
758.87
805.5
-2345
934
-376.2
-1751
4002
792.2
4792.2
6130
12810
934
16.25
19890
-2282
1799
-787174
13855
-210.7
-8390
-24R4
-10854
-96.07
10620
-91.74
18.76
-72.98
kg/day
-371.6
-78.6
0
436
-
-
-2499
492.2
0
196.9
26.5
-2181
169.6
-2010.4
49.20
295.33
344.53
365.7
-1065
424
-170.8
-795
1817
359.67
2176
2783
581.6
424
7.38
3786
-1035
817
-357.77
6235
-95.68
-3809
-1118
-4927
-43.61
4821
-41.65
8.51
-33.14
(Ib/MHHr)
x 106
-62000
-16808
0
193508
-
-
-875110
66960
0
27753
6696
-218061
17083
-200978
5726
34392
40118
37004
-162995
77312
-126330
-126378
1048458
207605
1256063
24669
51625
37638
656
114588
-296600
177482
- 99125
755868
-21346
-266709
-77985
-344694
-16736
938600
-8260
' 1692
-6568
kg/MHHr
x 106
-28100
-7631
0
87853
-
-
-397300
30400
0
12600
3040
-99000
7756
-91244
2600
15614
18214
16800
-74000
35100
-57354
-57376
476000
94253
570253
11200
23438
17088
298
52024
-134500
80577
- 45033
343164
-9691
-121086
-35405
-156491
-7598
426100
-3750
768
-2782
mg/1

-0.03
0
-2.4
-
0.66
-3
-5
0
0.1
-5
0
-4.5
-
0.83
1.01

0.51
0
0.38
0.12
-0.04
3.4
1.2

0.55
0.12
1.1
0.5

0.6
-0.13
-
-
-
-
-

-
.
0.4
-5

(Ib/day)
-
-0.859
0
-14.4
-
0.026
-150
-541
0
21.67
-41.69
0
-
-
6.91
50.52
57.43
5.94
0
12.68
0.48
-4.67
113.43
10
123.43
44.9
3.2
14.67
0.1233
62.89
30.02
-1.083
-
-
-
-
-
-
-
-
1.670
-6.255
-4.585
Ammonia (N)
kg/day
-
-0.39
0
-6.54
-
0.012
-68.1
-246
0
9.84
-18.93
0
-
-
3.14
22.94
26.08
2.7
0
5.75
0.218
-2.12
51.5
4.54
56.04
20.4
1.454
6.66
0.056
28.57
13.63
-0.492
-
-
-
-
-
-
-
-
0.76
-2.84
-2.08
(Ib/MHHr)
x 106
-
-83.39
0
-2903
-
16.21
-23852
-33480
0
13.92
-4790
0
-
-
365.68
2671
3036
273.12
0
1000
160.8
-337
29713
2623
32336
1806
129.9
592.5
5.044
kg/MHHr
x 106
-
-37.86
0
-1318
-
7.36
-10829
-15200
0
6.32
-2175
0
-
-
166
1213
1379
124
0
500
73
-153
13490
1191
14681
820
59
269
2.29
mg/1
-
-
0
0.24
-
-0.33
-0.73
0.12
0
1.3
0.04
1.0
0.16

0.8
0.6

0.33
0
0.72
1.19
0.09
4.2
0.97

6.1
2.6
0.07
4.6
2533 1150.3
3900
-105.72
-
-
-
-
-
-
-
-
149.78
-564
415.78
1771
-48
-
-
-
-
-
-
-
-
68
-256
-188
-0.8
-1.35
-0.19
-
-
-
-

-
—
0.09
0.23

(Ib/day)
-
-
0
1.44
-
-0.01
-36.52
13
0
282
0.33
71.7
1.51
73.21
6.87
30.02
36.89
3.85
0
24
4.75
10.5
140
8.08
148.08
498
69.38
0.934
1.149
569.46
-48.04
-11.25
-2.37
-
-
-
-
-
-
-
0.374
0.287
0.661
Nitrate (Ml
kg/day
-
-
0
.65
-
-0.005
-16.58
5.9
0
128
0.15
32.560
0.689
33.249
3.12
13.63
16.75
1.75
0
10.9
2.16
4.77
63.6
3.67
67.27
226.3
31.5
0.424
0.522
258.74
-21.79
-5.11
-1.08
-
-
-
-
-
-
-
0.17
0.13
0.3
(Ib/NNHr)
x 10*
.
-
0
290
-
-6
-5806
804
0
18061
37.45
3260
70.48
3330
361
1588
1949
176.2
0
1982
1597
757
36696
2119
38815
20044
2797
37.44
46.25
22924
-6000
-1110
-299.6
-
-
-
-
-
-
-
33
26
59
kg/MWHr
x 106
-
-
0
132
-
-3
-2636
365
0
8200
. 17
1480
32
1512
164
721
885
80
0
900
725
344
16660
962
17622
9100
1270
17
21
10408
- 2700
-504
-136
-
-
-
-
-
-
-
15
12
27
•total of
                    one waste stream for plant

-------
                                                                                       TABU: Arv- 9




                                                                             CHEMICAL WAS1E CHARACTERIZATION



                                                                            ASH POND OVERFLOW! -  NET  DISCHARGE (contlnuted)





                                                                      CHANGE IN PARAMETER  I£VEL  PROM INTAKE TO DISCHARGE
tode Chloride

3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
•3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
1825
1825
*1825
3920
1816
2608
Olll
4704
2119
2119
*2119
0107
3514
1716 '
1716
*1716
mg/1
2415
-1
1700
13.5
-140
-
15
75
1
34
81
21
-16

35
51

161
2
1
41
8
120
120

30
29
32
152

-
41
-
-2.5
-43.7
-13.4
-16.4

-
73
163
26

(Ib/day)
104121
-28.85
9570
81.01
-2815
-
750.5
8130
6
7372
675.3
1506
-93.4
1412.6
291.85
2551
2842
1879
70.04
33.35
164.1
934
4002
1000
5002
2451
773.78
426.8
38.01
3689
-
341.4
-
-153
-1485
-1201
-2971
-4172
-
1747
679.6
32.52
712.1
kg/day
47271
-13.1
4345
36.78
-1278
-
340.74
3691
2.726
3347
306.6
683.7
. -42.4
641.3
132.5
1158.5
1291
853.3
31.8
15.144
74.5
424
1817
454.3
2271
1113
351.3
193.8
17.26
1675
-
155
-
-69.46
-674
-545.3
-1349
-1894
-
793.2
308.56
14.76
323.32
(Ib/MWHr)
x 106
7885000
-3215
1765918
16319
-3230000
-
119350
503295
1898
473678
77588
68859
-4271
64588
15431
134909
150340
86594
4907
2768
55101
67400
1049000
262240
1311000
98804
31189
17207
1533
148733
-
33480
-
-8421
-150449
-38183
-94458
-132641
-
-
61273
2932
64105
Copper
kg/MWHr mg/1 (Ib/day) kg/day (Ib/MWHr) kg/MWHr
x 106 x 106 x 106
3577000 -0.001 -0.043 -0.0196 -3 -1
-1460 00 00 0
801727 -
7409 -0.006 -0.0359 -0.0163 -6.6 -3
-1470000 - - - ...
_
54185 - - - -
228496 - - - -
862 - - - -
215050 - - - -
35225 0.02 0.166 0.075 18.94 8.6
31262 ' -
-1939 -
29323 ...
7006 - - - -
61249 -
68255 -
39314 0.005 0.0573 0.026 2.62 1.19
2228 -. - - -
1257 -
25016 -0.037 -0.148 -0.0672 -50.66 -23
30600 - - - -
476226 - - - -
119057 -
595283 -
44857 - - - -
14160 -
7812 -
696 - - - -
67525 -
-
15200 -
-
-3823 -
-68303 - - - -
-17335 -
-42884 - - - -
-60219 ...
0.06 0.36 0.1635 62 28
_
27818 - - - -
1331 -
29149 -

mg/1
-0.479
0.045
-
-4.6
-
-
-
0.6
-
0.28
0.001
0
-0.252

0.034
0.040

0.099
1.770
-
-0.593
-0.387
-
-

0.02
0.09
0.032
0.098
0.141
-
-
-
0.44
2.894
_

0.15
-
-
-


(Ib/day)
-20.65
1.297
-
-27.62
-
-
-
65
-
60.7
0.008326
0
-1.4978
-1.4978
0.2819
2.0
2.2819
1.15
61.98
-
-2.37
-45.8
-
-
-
1.634
2.4
0.4270
0.0245
4.4855
-
-
-
26.92
98.37
_
-
0.9
-
-
-
-
Iron
kg/day
-9.376
0.589
-
-12.54
-
-
-
29.53
-
27.56
0.00378
0
-0.68
-0.68
0.128
0.908
1.208
0.524
28.14
-
-1.077
-20.8
-
-
-
0.742
1.09
0.194
0.0111
2.037
-
-
-
12.22
44.66
— t
-
0.409
-
-
.-
-

(Ib/MWHr)
x 106
-1600
125.55
-
-5563
-
-
-
4008
-
3898
0.9559
0
-68.28
-68.28
14.98
105.72
120.70
52.86
4341
-
-797
-3306
-
-
-
63.87
96.9
17.6
0.984
179.35
-
-
-
1482
9963
_
-
32
-
-
-
-
Manqanese
kg/MWHr mg/1 (Ib/day) kg/day (Ib/MWHr)
x 106 x 106
-726 -
57
-
-2626 -
-
_
-
1820 -
- - -
1770 0.02 4.34 1.97 277.5
0.434 0.0002 0.001652 0.0
-------
s
     Plant
                                                                                            TABIE  A-V- 9




                                                                                  CHEMICAL HASTE CHARACTERIZATION




                                                                                 ASH POND OVERFLOW - NET DISCHARGE  (continued)






                                                                          CHANGE IN PARAMETER USVEL FROM INTAKE TO  DISCHARGE
                                                                                                                                                                                  Zinc
~"""- —
3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
*3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
1825
1825
^825
3920
1816
2608
0111
4704
2119
2119
•2119
0107
3514
1716
1716
•1716
mg/1
156
-
-
-11
-
-
-
18
-
25
-
-3
10

15
14

21
0.1
-
-
-2
-
-

0
12
11
12

-
-
-
-3.8
-1.9
-
-

-
10
6
18

(Ib/day)
6724
-
-
-54.03
-
-
-
1951
-
5420
-
-215.6
58.37
-157.23
125.11
700
825.11
244.5
3.50
-
-
-233.48
-
-
-
0
320.26
146.76
2.99
470
-
-
-
-232.55
-64 . 58
-
-
-
-
239.36
25.02
22.52
47.54
kg/day
3053
-
-
-24.53
-
-
-
886
-
2461
-
-97.9
26.5
-71.4
56.8
318
374.8
111
1.59
-
-
-106
-
-
-
0
145.4
66.63
1.36
213.4
-
-
-
-105.58
-29.32
-
-
-
-
108.67
11.36
10.22
21.58
(Ib/MWHr)
x 106
509200
-
-
-10885
-
-
-
120704
-
348017
-
-9846
2669
-7177
6608
37037
43645
11233
3898
-
-
-16850
-
-
-
0
12907
5914
121.1
13942
-
-
-
-12800
-6542
-
-
-
-
21100
2247
2031
4278
kg/MWHr
x 106
231000
-
-
-4942
-
-
-
54800
-
158000
-
-4470
1212
-3258
3000
16815
19815
5100
1770
-
-
-7650
-
-

0
5860
2685
55
8600
-
-
-
-5811
-2970
-
-
-
-
9600
1020
, 922
1942
mg/1 (Ib/day) kg/day (Ib/MWHr) kg/MWHr mg/1 (Ib/day) kg/day (Ib/MWHr) kg/Mifflr mq/1
x 106 ' x 106 x 106 x 106
- - - - - -0.054 -2.32 -1.057 -175 -80 -0.014
----- 0.162
0.00013
-. -_ - -----
----- 0.17
- - - - 0.117
-- -- - _---_0
----- -0.073
-_ -_ - -----
0.0002 0.044 0.0197 2.77 1.26 0.01 2.167 0.984 139.2 63.2 0.03
-- - ----- 0.011
-. _- - -----
- - -- - _____
-- - -----
-- - ----- 0.009
-- -- - ----- 0.009
__ _ -_-_
0.011 0.1277 0.058 5.88 2.67 0.003
_- -- - -----
-0.01
-0.002 -0.00793 -0.0036 -0.44 -0.2 -----
-- -- - ----- o.03
- - - 0.015 0.5 0.227 130.83 59.4 0.003
- - - - - 0.008 0.066 0.0302 17.62 8 0.013
- - - 0.566 0.257 148.45 67.4
-- -- - ----- o.07
-- -- - --- - - -0.007
-- -- - ----- -0.006
-- - ----- 0.001
--_- ----
_- _- _ -----
-- -- - -----
-- -- - --___
-- -- - -----
-- _- - -----
-- -- - -----
-- -- - -----
.-_- -----
oo oo o _-_-- 0.05
-- - -----
-- -- - ----- 0.12
-- -- - ----- -0.02
.--- ----
(Ib/day)
-0.603
4.67
0.00073
-
3.41
0.00467
0
-7.9
-
6.5
0.09
-
-
-
0.0749
0.45
0.5249
0.035
-
-0.332
-
3.5
0.099
0.108
0.207
5.7
-0.185
-0.079
0.000251
5.436
-
-
-
-
-
-
-
-
0.30
-
0.5
-0.025
0.475
kq/day
-0.274
2.12
0.00032
-
1.552
0.00212
0
-3.59
-
2.953
0.041
-
-
-
0.034
0.2044
0.2384
0.0159
-
-0.151
-
1.59
0.0450
0.0492
0.0942
2.59
-0.084
-0.036
0.000114
2.47
-
-
-
-
-
-
-
-
0.14
-
0.227
-0.0113
0.216
llb/MWHr)
X 106
-45
453.7
0.134
-
3951
2.86
0
-489
-
416.23
10.35
-
-
-
3.94
24.23
28.17
1.6
-
-2.75
-
253.3
24.229
28.63
52.959
231.27
-6.6
-2.2
0.011
222.48
-
-
-
-
-
-
-
-
50
-
44
-2.2
41.8
kg/MWHr
x 106
-20
206
0.061
-
1794
1.301
0
-222
-
189
4.7
-
-
-
1.79
11
12.79 •
0.73
-
-1.25
-
115
11
13
24
105
-3
-1
0.005
101
-
-
-
-
-
-
-
-
24
-
20
-1
19
    •Total of more than one waste  stream for plant

-------
                                                                                        TABI£  A-V- 9

                                                                              CHEMICAL WASTE CHARACTERIZATION

                                                                             A3H POND  OVERFLOW -  NET DISCHARGE  (continued)

                                                                      CHANGE IN PARAMETER  I£VEL FROM INTAKE  TO  DISCHARGE
Plant
Code


3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
3936
*3936
3927
2616
1808
1729
1718
3930
3930
*3930
1825
1825
1825
1825
*1825
3920
1816
2608
0111
4704
2119
2119
*2119
0107
3514
1716
1716
*1716
Phosphorus ^p'
mg/1

-
-
0
0
-
-0.5
-0.33
-0.7
-
-0.09
-1.19
-0.7
~

0.1
0.2

0.14
0
0.26
0.08
-0.05
-
-

-
-
-
-

-0.09
0.41
-0.06
-
-
-
-

-
-
-0.23
-0.23

(Ib/day)

-
-
0
0
-
-0.02
16.5
-75.88
-
-19.51
-9.91
-50.22
-
-50.22
0.815
10
10.815
1.63
0
8.65
0.319
-5.83
-
-
-
-
-
-
-
-
-5.4
3.41
-0.749
-
-
-
-
-
-
-
-0.958
-0.280
-1.238
kg/day

-
-
0
0
-
-0.01
-7.49
-34.45
-
-8.86
-4.5
-22.8
-
-22.8
0.37
4:54
4.91
0.74
0
3.93
0.145
-2.65
-
-
-
-
-
-
-
-
-2.45
1.55
-0.34
-
-
-
-
-
-
-
-0.435
-0.13
-0.565
(lb/l*mr)
x 106
-
-
0
0
-
-10
-2623
-33480
-
-1253
-1136
-2290
-
-2290
41.8
528
569.8
74.89
0
718
107.93
-420
-
-
-
-
-
-
-
-
-702.6
337
-94.7
-
-
-
-
-
-
-
-85.9
26
-59.9
kg/MWHr
x 106
-
-
0
0
-
-5
-1191
-15200
-
-569
-516
-1040
-
-1040
19
240
259
34
0
326
49
-191
-
-
-
-
-
-
-
-
-319
153
-43
-
-
-
-
-
-
-
-39
12
-27
                                                                             Sulfite,  Lead, Oil  and  Grease,
                                                                             Phenols,  Surfactants. Alqicldes
                                                                 -5
                                                                 13

                                                                -29
                                                                183
                                                                  8
                                                                  0
                                                                 10
                                                                 27
                                                                -14
                                                                  1
                                                                 -2
                                                                -22
                                                                -2.2
                                                                16.3
                                                                -13
                                                                -13
*total of more than one waste stream for plant

-------
In that table, plant capacities range from 31 Mw to 2,533 Mw
and  the  ash  pond  overflow  varies between 1,817 cu m/day
(480,000 gpd) and 122,946 cu m/day (32,473,000 gpd).

Because of the large variation in quality of  coal  used  in
powerplants,   the  data  also  show  a  wide  variation  in
concentration of trace metals in the effluent.  Some of  the
metals discharged may be harmful to aquatic life.

Oil

The  ash content of fuel oils is low (about 1% of the amount
commonly found in coal). 27a  It is generally 0.10 to  0.15%
by weight, although it may be as high as 0.2%.

The  quantity  of ash produced in an oil-fired plant is very
small, but the settling characteristics of oil ash  are  not
as  favorable  as those of coal ash.  It has been found that
in some cases recycling oil fly into the furnance  increases
efficiency and eliminates the fly ash disposal problem.  De-
pending  on  the vanadium content of the oil, the dry bottom
ash can actually be a saleable by-product.

Most oil ash deposits are partially soluble and can  be  re-
moved by water washing.  Generally the washing is done while
the unit is out of service.  In-service water washing at re-
duced  loads  has  been  practiced to some extent, using the
hot, high-pH boiler water in carefully regulated amounts.

Limited data are available on the characteristics of oil ash
handling waste water.  Table A-V-9 lists 6 plants which  use
both  coal  and  oil, but only one plant is listed using oil
alone.  No data are reported for vanadium in waste  streams.
In  certain  cases,  however, when other means of collecting
the vanadium are not available, the content of  vanadium  in
waste  water  should  be  evaluated, because of its possibly
toxic effect on aquatic life.

Coal Pile Runoff                             \

For coal-fired generating plants, outside storage of coal at
or near the site is necessary  to  assure  continuous  plant
operation.   Normally,  a  supply  of 90 days is maintained.
These storage piles are typically 8 to 12 meters  (25-40  ft)
high  spread  over  an  area  of  several  square meters (or
acres).  Typically from 600 to 1,800 cubic  meters  (780  to
2340  cu  yd)  are required for coal storage for every Mw of
rated capacity.  As such a 1000 Mw plant would require  from
600,000  to  1,800,000  cubic meters (78,000 to 2,340,000 cu
yd)  of  storage.   Depending  on  coal  pile  height,  this
                          160

-------
represents  between  60,000  to 300,000 square meters (15-75
acres)  of coal storage area.

Coal is stored either in active piles or storage piles.   Ac-
tive piles are open and contact of active coal with air  and
moisture  results in oxidation of metal sulfides, present in
the coal, to sulfuric acid.  The precipitation  trickles  or
seeps  into coal piles.  When rain falls on these piles, the
acid is washed out and eventually  winds  up  in  coal  pile
runoff.   Storage  piles are sometimes sprayed with a tar to
seal their outer surface.  In such cases, the  precipitation
runs down the side of the pile.

Based  on typical rainfall rates, pile runoff may range from
64,000 to over 32,0000 cubic meters (17 to 85  million  gal-
lons) per year with average figures around 75,000 to 100,000
cubic  meters (20 to 26 million gallons) per year.  Table A-
V-10 presents the amount of coal consumed per day, area  and
height  of  coal  pile,  average  rainfall  and  runoff from
various coal-fired generating plants across the country.

Liquid drainage from coal storage piles presents a potential
danger of stream contamination, if it is  allowed  to  drain
into  waterways  or  to  seep  into useful aquifers.  Ground
seepage  can  be  minimized  by  storing  the  coal  on   an
imprevious  base.   Vinyl liners of various thicknesses have
been used for that purpose.  To prevent the sharp  edges  of
coal particles from puncturing the liner, a 15 cm(6") bed of
sand or earth is placed on top of a liner before forming the
coal pile.

Water  pollution  associated with coal pile runoff is due to
the chemical pollutants and suspended solids usually  trans-
ported in coal pile drainage.  Drainage quality and quantity
is variable, depending on the meteorological condition, area
of  pile and type of coal used.  Areas of high average rain-
fall have much higher drainage than  those  of  low  average
rainfall.   Contact of coal with air and moisture results in
oxidation of metal sulfides to sulfuric acid and  precipita-
tion  of  ferric compounds.  High humidity areas have higher
precipitation and produce larger runoffs.

Coal pile runoff is commonly characterized as having  a  low
pH   (high  acidity)  and  a high concentration of total dis-
solved solids including iron, magnesium and sulfate.   Unde-
sirable  concentrations  of  aluminum, sodium, manganese and
other metals may also be present.  Contact of coal with  air
and  moisture  results  in  oxidation  of the metal sulfides
present in the coal to sulfuric acid.  Pyrites are also oxi-
dized by ferric ion to produce ferrous sulfate.   When  rain
                          161

-------
                                                      TABLE A-V-10
                                                  COAL PILE  DRAINAGE
PLANT
ID

4701
4706
4702
4705
4703
2120
4704
2119
0112
5305
COAL CONSUMED/DAY
Ibs Kgs
xlflS xlO6
15 6.81
31 14.07
15 6.81
27.6 12.53
20.6 9.35 '
25.4 11.53
14.34 6.51
47.6 21.6
35.8 16.25
-
AREA OF PILE
Acres M^
x!03
25 101.85
58 236.29
75 305.55
28 114.07
18 73.33
61 248.5
21 85.55
25 101.85
25 101.85
120 488.8
HEIGHT OF PILE
Ft. Meters
40 12.19
25 7.62
17 5.18
25 7.62
40 12.19
22 6.7
25 7.62
-
40 12.19

AVERAGE ANNUAL
RAINFALL
Inches Meters
44 1.117
-
54.7 1.389
-
45.84 1.164
-
43.1 1.094
44.4 1.1277
: -
60 1.524
RUN -OFF PER YEAR
Million M3
Gallons xlO3
20 75.7
-
25 94.62
-
25 94.62
-
17 64.34
22 83.27
26.5 100.3
-
CTl
ro

-------
falls  on these piles, the acid is washed out and eventually
winds up in the coal pile drainage.  At the low pH produced,
other metals such as aluminum, copper, manganese, zinc, etc.
are dissolved to further degrade the water.

Coal pile runoff, like coal mine drainage, can be classified
into   three   distinct   types   according   to    chemical
characteristics.   The  first  type of drainage will usually
have a pH of 6.5 to 7.5 or greater, very little or no  acid-
ity,  and contain iron, usually in the ferrous state.  Alka-
line drainage may occur where no acid-producing material  is
associated  with  the  mineral  seam  or  where  the acid is
neutralized by alkaline material present in the coal.   Some
alkaline waters have high concentration of ferrous ion, and,
upon  oxidation and hydrolysis, precipitate large amounts of
iron.                                      .

A second type of drainage is highly acidic.  This water con-
tains large amount of iron, mostly  in  ferrous  state,  and
aluminum.

Although  the  exact  reaction  process  is  still not fully
understood, the formation of acid coal pile drainage can  be
illustrated  by  the  following equations.  Initial reaction
that occurs when iron sulfate and sulfuric acid

     2 F6S2+7 02 +2 H2O = 2 FeSOU+2 H2SOU

Subsequent oxidation of ferrous sulfate produces ferric sul-
fate:

     4 FeSOtt+2 H2SOU+O2 = 2Fe2 (SO4) 3+ 2 H2O

Depending on physical and chemical conditions, the reaction
may then proceed to form ferric hydroxide or basic ferric
sulfate:

     Fe2(S04)3+6H20 = 2Fe (OH) 3+3H2SOU

     Fe2(S04)3 + 2H20 = 2Fe (OH) (SOU) +H2SO4

Pyrites can also be oxidized to ferric ions as shown below:

    FeS2+lU Fe+'+8H2O = 15
Regardless of the reaction mechanism, the oxidation  of  one
mole  of pyrite ultimately leads to the release of two moles
of sulfuric acid  (acidity) .
                          163

-------
Other constitutents found in coal pile drainage are produced
by secondary reactions of sulfuric acid  with  minerals  and
organic compounds present in the coal.  Such secondary reac-
tions  are  dependent upon type of coal and physico-chemical
conditions of the pile.

The pollution of streams by  coal-pile  runoff  may  be  at-
tributed   to  higher  concentration  of  dissolved  solids,
mineral acid, iron, and sulfate present in the  runoff.   In
addition,  aluminum,  copper,  zinc  and  manganese  may  be
present.  The degree of harm caused  by  these  elements  is
compounded  by  synergisir amcng several of them; for example
zinc with copper.  The harmful effects of iron,  copper  and
zinc  solutions can be greater in the acid water polluted by
coal pile drainage than in neutral or alkaline water.   Data
reported  from various plants are shown in Table A-V-11.  An
inspection  of  these  data  reveals  an   extremely   large
variation   in   the   pollutant   parameters  listed.   The
concentration of runoff is dependent on  the  type  of  coal
used,  history  of  the  pile  and rate of flow.  Plant nos.
1729, 3626, and 0107  using  high  sulfur  coal  are  highly
acidic   (low  pH),  and  have  high  sulfate  and  metallic
concentrations.

The acidity, sulfate and metal concentrations of  plant  no.
3505  which  uses  very low sulfur coal are very small.  The
concentration of pollutants during heavy  rainfall  will  be
very small after an initial removal of precipitated material
from  coal,  while  during low flow conditions the retention
time may be high enough to complete oxidation, resulting  in
higher runoff concentrations.

Floor and Yard Drains

A  steam  electric powerplant contains a number of potential
sources of wastewater in the nature of piping and  equipment
drainage  and  leakage.   The  list  in  Table  A-V-12  is a
representative  compilation  of   sources,   showing   major
contaminants,  the  likely  frequency, potential severity of
discharges,  and  control   technologies   that   might   be
considered.
The floor drains within a powerplant which collect equipment
drainage  and  leakage generally include dust, fly ash, coal
dust  (coal-fired  plants)  and  floor  scrubbing  detergent.
This  waste  stream  also  contains lubricating oil or other
oils which are washed away during  equipment  cleaning,  oil
from  leakage  of  pump  seals, etc., and oil collected from
spillage around storage tank area.
                          164

-------
                                                                                           TABLE  A-VT11

                                                                                   CHEMICAL WASTE CHARACTERIZATION



                                                                                         COAL PILE DRAINAGE
Line

1)
2)
3)
4)
5)
6)
7)
8)
9)
10)
11)
Plant
Code

3402
3401
3936
1825
1726
1729
3626
0107
5305
5305
5305
B
AlXalinitv
mg/1
6
0
0
-
82
-
-
0
21.36
14.32
36.41
C
mg/1
0
0
10
-
3
-
-
-
-
-
-
D
mg/1
1080
1080
806
85
1099
-
-
-
-
-
-
E
rag/1
1330
1330
9999
6000
3549
-
-
45000
-
-
-
P
mg/1
720
720
7743
5800
247
-
28970
44050
-
-
-
G
mg/1
610
610
22
200
3302
-
100
950
-
-
-
H
Ammonia
mg/1
0
0
1.77
1.35
0.35
-
-
-
-
-
-
Discharge Concentrat
Nitrate Phosphorus
mg/1
0.3
0.3
1.9
1.8
2.25
-
-
-
-
-
-
mg/1
_
-
1.2
-
0.23
-
-
-
-
-
-
ions.
mg/1
505
505
-
-
-
-
-
-
8.37
2.77
6.13
L
Acidity
mg/1
_
-
-
-
-
-
21700
27810
8.68
10.25
8.84
M
Total
Hardneaa
• mg/1
130
130
1109
1850
-
-
-
-
-
-
-
N
Sulfate
mg/1
525
525
5231
861
133
6837
19000
21920
-
-
-
O
Chloride
mg/1
3.6
3.6
481
-
23
-
-
-
-
-
-
P
Aluminum
mg/1
_
-
-
-
-
-
1200
825
-
-
-
Q
Chromium
mg/1
0
0
0.37
0.05
-
-
15.7
0.3
-
-
-
                                          Discharge Concentrations
      Plant
Line  Code       Copper
  1)
  2)
  3)
  4)
  5)
  6)
  7)
 10)
 11)
    3402
    3401
    3936
    1825
    1726
    1729
    3626
8)  0107
9)  5305
    5305
    5305
                  mg/i
1.6
1.6
                  1.8
                  3.4
C
Iron
mg/1
0.168
0.168
-
0.06
-
0.368
4700
93000
1.0
1.05
0.9
D E
Haqnesium Zinc
mg/1 mg/1
1.
1.
89 2.
174 0.
0.
-
12.
23
-
-
-
6
6
43
006
08

5




P G
Sodium pH
mg/1
1260 2
1260 2
160 3
4
7
2
2
2
6
6
6
pH
.8
.8

.4
.8
.7
.1
.8
.7
.6
.6

-------
                                           Table A-V-12
                                     Equipment  Drainage, Leakage 444
Source Major Contaminants
Oil-water Heat
Exchangers
Oil Tank, Lines &
Transformer Rupture
Floor spills
Oil Drips and
Tank Leakage
Sump Discharges from
Service Bldg. & Yard
Chemical Tank
Rupture
Chemical Tank
Leakage
Oil
Oil
Suspended Solids
or Oil
Oil
Oil and
Suspended Solids
Regenerant and
cleaning chemicals
Regenerant and
cleaning chemicals
Frequency
Remote
Possibility
Remote
Possibility
Daily
Daily
Often
Remote
Possibility
Occasional
Potential Severity Potential Control Techniques
Severe
Severe
Slight
Slight
Slight
Severe
Slight
1. Continuous Gravity Separation
2. Detection and Batch Gravity
Separation
3. Detection & Mechanical Separation
A.' Maintain pressure of water
greater than oil
1. Isolation from Drains
2. Containment of Drainage
1. Plug Floor Drain
2. Route Floor Drainage Throut .
Clarif ier & gravity or meet anical
separation
1. Isolate from Floor Drains
2. Route to Gravity or Mechanical
Separation
1. Isolate and route through clarified
and gravity or mechanical
separation
1. Containment of Drainage
2, Isolation from Drains
3. Route Drains to Ash Pond or Hold-
ing Pond for neutralization
1, Isolate from Floor Drains
2, Route Drains to Ash Pond or
Holding Pond
NOTE:   oil Spill  Contingency Plans would apply to significant oil releases.

-------
No data regarding the flow and  composition  of  this  waste
stream  have  been reported, however, oil, suspended solids,
and phosphate from floor scrubbing detergent may be  present
in the floor drains.  The discharge stream will be acidic if
any  wash water from air preheater or fireside of the boiler
winds up in floor drains.

Air Pollution Control Devices
A number  of  processes  have  been  proposed  for  removing
particulate  and  SO2  emissions  from stack gases.  Some of
these  processes   have   been   suggested   for   potential
application  in fossil-fuel powerpiants.  In general the SO2
removal processes can be categorized, according to Reference
123, as follows:

     (1)  Alkali scrubbing using calcium carbonate or lime
          with no recovery of SO2.
     (2)  Alkali scrubbing with recovery of SO2 to produce
          elemental sulfur or sulfuric acid.
     (3)  Catalytic oxidation of SO2 in hot flue gases to
          sulfur trioxide for sulfuric acid formation.
     (4)  Dry-bed absorption of SO2 from hot flue gases
          with regeneration and recovery of elemental sul-
          fur.
     (5)  Dry injection of limestone into the boiler furnace
          for removal of SO2 by gas-solid reaction.

The removal of particulates from stack  gases  can  also  be
carried out separately - using an electrostatic precipitator
or a dry mechanical collector, wet scrubbing for SO2_ removal
can be applied subsequently.

The  waste  water  problems  are  mainly  concerned with wet
processes (first three types mentioned  above).   Wastewater
problems  associated  with particulate  (fly-ash) removal de-
vices are described in an earlier portion of this section of
the report.

At present three wet processes  are under development or  in
use:  alkali  scrubbing  with  and without SO2 recovery, and
oxidation of SO2 for sulfuric acid production.  Of the three
processes, data is available mainly for the alkali scrubbing
process without S02 recovery, s and  consequently  only  this
process is described briefly in the following paragraph.

Flue  gas  from electrostatic precipitators  (optional equip-
ment) is cooled and  saturated  by  water  spray.   It  then
                          167

-------
passes  through a contacting (scrubbing)  device where SO2 is
removed by an aqueous stream of lime absorbent.   The  clean
gas  is  then reheated (optional step) and vented to the at-
mosphere through an induced draft  fan  if  necessary.   The
lime  absorbent  necessary  for  scrubbing  is  produced  by
slaking and diluting quicklime in commercial  equipment  and
passing it to the delay tank for recycle as a slurry through
the  absorber  column (s).   Use  of  the delay tank provides
sufficient residence time for the reaction of dissolved  SO2
and  alkali  to  produce  calcium  sulfite and sulfate.  The
waste sulfite/sulfate is them pumped as a slurry to a  lined
settling pond or mechanical system where sulfite is oxidized
to sulfate.  The clear supernatent liquid is returned to the
process  for reuse.  The waste sludge containing fly ash (if
electrostatic precipitator  is  not  employed)  and  calcium
sulfate is sent f,or disposal (as a landfill).

The  process  described  above has the potential for scaling
problems.  The calcium salts tend to form a  deposit,  which
may cause equipment shutdown and  maintenance.

The  process is a closed loop type and consequently there is
no net liquid discharge from the process.  The  disposal  of
sludge   has  been  covered  in  the  literature.   However,
depending upon the solids separation efficiency in a pond or
mechanical equipment, there may be  excess  free  water  as-
sociated   with   the   sludge.   To  dewater  this  sludge,
mechanical filtration equipment may be necessary.

To date eleven or more utilities have  committed  themselves
to  full-scale  installation  of the alkaliscrubbing process
without SO 2 recovery.  During  the  course  of  the  present
study,  visits  were  made  to  two plants for observing the
scrubbing devices.  However, in plant no. 1720, the scrubber
was not running because of operational problems.   The  pro-
cess for the other plant  (no. 4216) is described below.

Plant  no.  1216  of  79 Mw capacity burns 0.7X sulfur coal.
The boiler gases are split into two streams -  approximately
7556  going  to  a scrubber and the remaining 25% going to an
electrostatic precipitator.  The exhaust gases from the  two
are then recombined and vented to atmosphere at 210°F.  This
splitting of the boiler gases is done to reheat the scrubber
exhaust gases which are at 12U°F (saturated).  This stack gas
reheating  is  achieved  to  minimize  scaling problems from
moist gases.  The scrubber is not specifically used for  SO2
removal.    Rather,   the  primary  function  is  to  remove
particulates.  On the other hand, seme SO2  pick-up  may  be
achieved based on Figure A-V-30 where the net output from the
process   (thickener underflow) is richer in sulfate than the
                            168

-------
.STACK GASES
  @~210°F
                                                                                                      , LIME SLURRY .
                                                                                                                                -450 GPM
                                                                                                                              •
                                                                                                                                pH 5.6
                                                                                      FLYASH FROM
                                                                                      PRECIPITATOR
                                                                                      AND SERVICE
                                                                                      WATER DISCHARGES
                                   ~ 90.000 SCFM
              STEAM TO TURBINES
                    1
                    BOILER
                 (79 MW PLANT)
.~ 270.000 SCFM ,
                             •    FLUE GASES    •

                               •~ 360.000 SCFM      ^
                                        INLET      ^-*
                                   SCRUBBER LIQUOR
NOTE: IN THIS PLANT 25% OF THE
      FLUE GASES GO THROUGH
      THE ELECTROSTATIC PRECIPITATOH
      AND NOT THROUGH THE SCRUBBER
                                         ~3500 GPM
                                                 OVERFLOW
                                                 ~ 2500 GPM
                                                                   / UNDERFLOW.

                                                                      800-1000 GPM '
      OVERFLOW
                                                           750 GPM
                                                          RIVER WATER MAKEUP
                                                              ~ 160 GPM
p



^



\
^r
T r
1 v

?)

| ~65 GPM
M



MAX
STREAM #:
PARAMETER
pH


ACIDITY PP
ALKALINITY MO
HARDNESS
SULFATE
SULFITE
TDS DRY 103°C
TSS

ECTROLY
I
ICKENER
^

TE
©
UNIT
IN PPM

_
CaCO3
CaCOj
CsCOj
S°4
S03
PPM
PPM
11
HOLDING
SUMP

1 vO
/TN1
SETTLING
POND

C-Lc OVERFLOW
• '* 'TO RIVER

^ LOSS TO SOIL
i
I J -500 GPM
1
INLET
SCRUBBER
WATER
2.0
3900
0
1950
4095

cl
7910
8480
2
THICKENER
UNDERFLOW
2.7
3600
0
1950
4067
<1
7665
176.680
3
LIMED
WATER
9.2
0
68
1800
1287
<1
2390
318.800


4
DISCHARGE
TO POND
6.7
5
80
696
520
<1
1095
70,780








5
DISCHARGE
TO RIVER
7.2
5
32
484
377
<1
750
5
R
RIVER
WATER
6.7
3.7
22
58
25
<1
130
130
i
                                     UNDERFLOW  f_"\
                                                                                         . 36-60 GPM

                                     FIGURE A-V-10  FLOW DIAGRAM AIR POLLUTION CONTROL SCRUBBING SYSTEM AT PLANT NO. 4216

-------
process input (river water).  However, some of the  increase
in  sulfate  may  be  due  to  chemicals  added  to  enhance
particulate removal.  The flow  diagram  and  the  different
stream compositions are shown in Figure No. A-V-10.

For  a  more  complete review of the status of air pollution
control  technology  for  steam  electric  powerplants,  see
References 470-473.
Sanitary Wastes

The  amount  of  sanitary  waste  depends upon the number of
employees.  This in turn  is  dependent  upon  the  type  of
plant-rcoal,  oil,  or  gas, its size and its age.  A power-
plant employs administrative personnel and  plant  personnel
(plant  crews and maintenance personnel).  Coal-fired plants
require more operational personnel then others.  For a coal-
fired  plant,  the  breakdown  in  types  of  employees   is
typically as follows:

     operational personnel:      1 per 20-40 Mw
     maintenance personnel:      1 per. 10-15 Mw
     administrative personnel:   1 per 15-25 Mw

A  typical three boiler 1,000 Mw coal-fired plant may employ
150-300 people.  Whereas, in a oil plant  of  similar  size,
the total number of employees may be in the range of 80-150.

The   typical   parameters   which  define  the  pollutional
characteristics of sanitary wastes are BOD-5  and  suspended
solids.   The  following table lists per capita design esti-
mates for the waste stream:
Office-Admin.     0.095cu m/day     30 g       70 g
                  (25 gpd)         (0.07 Ib)   (0.15 Ib)

Plant             0.133 cu m/day    40 g       85 g
                  (35 gpd)         (0.09 Ib)   (0.19 Ib)

Knowing the number of personnel in the office-administrative
and plant categories, the characteristics of the raw  sewage
waste  stream can be estimated.  Typically, for an oil-fired
plant generating 1,000 Mw the personnel required might be 20
office and administrative, and 85 plant personnel.  The  raw
sewage  characteristics  for  this plant can be estimated on
the basis presented above as follows:
                           170

-------
                  FLOW
                 BOP-5
Office-Admin.
Plant
Total
1.890 cu m/day
(500 gpd)

1.125 cu m/day
(2975 gpd)

3.015 cu m/day
(3475 gpd)
  635 g
(1.40 Ib)

  3480 g
(7.65 Ib)

  4115 g
(9.05 Ib)
  1360  g
(3.00 Ib)

  7330  g
(16.15
  8690 g
(19.15 Ib)
The  sanitary  waste  from  steam  electric  powerplants  is
generally  similar  to  municipal  sanitary  wastes with the
exception that powerplant wastes  do  not  normally  contain
laundry   or  kitchen  wastes.   Moreoverf  the  per  capita
hydraulic loading for  powerpiant  personnel  is  relatively
small   (25  to  35 gallons) in comparision to domestic usage
(100 to 150 gallons).  Normally the  local  health  agencies
dictate  requirements  for  treating  sanitary  wastes.   In
metropolitan areas, the raw sewage may be  discharged  to  a
municipal   treatment   plant.   In  rural  areas,  packaged
treatment plants for sanitary wastes may be employed.

Plant Laboratory and Sampling Streams

Laboratory facilities are maintained in many steam  electric
powerplants to carry out chemical analysis for checking dif-
ferent  operations  such  as  ion exchange, water treatment,
boiler tube cleaning requirements, etc.   The  size  of  the
laboratory  depends  upon  the  size,  type,  and age of the
plant.  Modern high pressure  steam  plants  require  closer
control   on   the  operations  and  consequently  increased
laboratory  activity.   In  nuclear  plants  the  use  of  a
laboratory is extensive.

The   waste   from   laboratories   vary   in  quantity  and
constituents, depending upon the use of the  facilities  and
the type of powerplant.

Laboratory  facilities  for  steam electric powerplants also
vary considerably depending on the age of the plant and  the
extent  to  which different companies rely on plant labs for
their   chemical   analysis   needs.    For   some   plants,
particularly  small  and older plants, no laboratory work is
done on site and samples are shipped to central laboratories
for analysis.   In  others,  and  especially  modern,  high-
pressure  steam  plants  and  nuclear  facilities, much more
laboratory support is required.
                        171

-------
Laboratory wastewater can contain a wide array of chemicals,
although  they  are  usually  present  in  extremely   small
amounts.  Chrarcteristics are also highly variable and could
entail  a  wide range of pH.  It has been common practice to
combine laboratory drains  with  other  plant  plumbing  and
consequently  data  on  representative  analysis,  flows  or
special treatment procedures are not available.  In general,
it would appear that a toxic materials inventory approach to
account for chemicals that might be discharged to laboratory
drains would be more practical than conducting  an  analysis
on the wastewater.

If  a  problem  is  shown  to exist because of contamination
through a laboratory  drain,  approaches  to  control  would
involve a wide range of alternatives ranging from a revision
of  the  specific test procedure causing the difficulty to a
batch analysis, containment and separate  treatment  of  the
waste or removal from the site.
Intake Screen Wash

Powerplants  require  water  for various operations.  Plants
using once-through type condenser cooling systems  draw  the
cooling  water  from a waterbody such as an ocean, a lake, a
river, etc.  On the other hand, plants using a recirculating
condenser cooling system need less  water  intake  than  the
once-through  types.   Depending upon the water requirements
and the source of intake water, traveling screens  are  used
to  prevent  river  debris, fish, leaves, etc. from entering
the intake system.  The accumulated debris is collected  and
the screens hosed down to prevent plugging.

Service Water System

Service  water  systems  supply water which is used for such
house services as bearing and gland cooling  for  pumps  and
fans, auxiliary cooling and heat exchangers, hydrogen cooler
and  fire  pumps.  In many cases toilet and potable water is
included in this category.

According to Reference 21, there are basically two types  of
service  water  systems.  Once-through service water systems
are most common.  In these types raw water with no treatment
chemical is added.  These types of systems are  operated  in
parallel  to  the condenser cooling water system.  Raw water
is  used  and  no   continuous   treatment   is   practiced.
Occasional  shock chlorination is given to similar levels as
with condenser cooling water.   Chlorination  treatment  is,
however,  much less frequent.  Many nuclear plants integrate
                        172

-------
•the  emergency  core  cooling  system  with  a  once-through
service  water  system.   Once-through service water systems
can be used exclusively or in conjunction  with  closed-loop
recirculatory   systems.   With  recirculatory  systems  the
makeup can be supplied from either raw or city water.   This
makeup  is  pretreated  to  a  high  degree of purity.  This
closed loop recirculatory water is treated to a high  degree
to   prevent:  corrosion  within  the  system.   In  general,
chromates are used in  conjunction  with  caustic  soda  for
control of pH at 9.5 to 10 up to levels of 250 ppm.  Borate-
nitrate  corrosion  inhibition  treatment  is  also  used to
levels of between 500 to 2,000  ppm.   Generally,  there  is
little  or no loss from these closed-loop systems.  The only
occasions when water loss can occur are  during  maintenance
or  occasionally  if  the  system  has  to  be  drained  for
cleaning, which although infrequent can  occur  at  a  three
year frequency.

Service  water  requirements  cover a wide range.  For once-
through systems water flows range from 0.5 to 35 gpm per  Mw
of  rated  plant  capacity.  Typically, the flow is 10 to 11
gpm per Mw of rated capacity.  Where closed-loop systems are
operated a figure of 22 to 23 gpm per Mw of  rated  capacity
is   typical.   On  this  basis,  closed-loop  blowdown  can
typically be 5 gallons per  day  with  a  settleable  solids
content  of 1 to 2 ppm.  Service water requirements of plant
no. 4251, a nuclear unit of 851 Mw using 480,000 gpm of main
condenser cooling water, are as follows:

    Primary plant component cooling water      5,800 gpm
    Secondary plant component cooling water   16,000 gpm
    Centrifugal water chiller                  3,000 gpm
    Control room air conditioner                 210 gpm

Low Level Rad Wastes

The radioactive waste handling system is beyond the scope of
this study.  Some of the low level rad wastes from a nuclear
powerplant  contain  boron  and  •therefore   can   also   be
considered  as  chemical  wastes.  Consequently, a brief de-
scription of the waste handling systems in a nuclear  power-
plant  is  included.   The sources of radioactive wastes are
the reactor coolant and spent fuel coolant and  the  various
systems  with  which  these  coolants come into contact.  In
general, the radioactive fluids are treated  by  filtration,
ion  exchange, and distillation.  The fluids are then either
recycled for use in the  plant  or  diluted  with  condenser
cooling water for discharge to the environment.
                         173

-------
Most  commercial  nuclear  powerplants  in  the  country are
either pressurized water reactors (PWRs)   or  boiling  water
reactors  (BWRs).   In  a  pressurized  water  reactor,  the
primary coolant is maintained  at  a  pressure  (2,200  psi)
sufficient  to  keep  it  from  boiling.   After the primary
coolant is heated in the reactor, it flows through the  tube
side  of  large  heat  exchangers  generating  steam  on the
shellside.  This steam is used to drive the turbine  and  is
then condensed and returned to the steam generator through a
series  of  preheaters.  Thus, in a PWR, the primary coolant
is isolated from the steanb-condensate system.  However, some
leakage through defects in steam-generator tubes  may  occur
resulting  in  contamination of the steam-condensate system.
There  are  several  other  fluid  systems  which   may   be
contaminated.   In  a  PWR,  boron  is  used  in the primary
coolant to help control reactivity.   As  the  fuel  burn-up
progresses,  the  boron concentration is lowered by feed and
bleed of reactor coolant.

Two systems are associated with  this  process.   The  first
system,  which  is  sometimes called the chemical and volume
control system  (CVCS), is on stream at all times and is used
to control the radioactivity chemistry and volume of reactor
coolant.  Reactor  coolant  is  continously  bled  from  the
primary system into the CVCS where it usually passes through
filters  and  ion  exchangers.   The  coolant  can  then  be
returned to the reactor or diverted to the second system  to
allow addition of water with a different boron concentration
to  the  reactor through the CVCS.  The second system can be
labeled the boron management system (BMS).  It processes the
reactor coolant letdown after it has passed through the CVCS
ion exchangers.  Processing in the BMS usually includes  gas
stripping  to  remove  hydrogen  and  the  radioactive noble
gases, ion exchange, and distillation.  The  distillate  may
be  recycled  for  use  as  reactor  coolant or diluted with
condenser cooling water for discharge  to  the  environment.
The  concentrated  bottoms from the distillation process are
either recycled as boric acid for use in the reactor coolant
or  mixed  with  cement  and  placed  in  drums  or   larger
containers  for shipment to a solid radioactive waste burial
site.

Provisions are made so that after  reactor  shutdown  it  is
possible  to  cycle  reactor  coolant through ion exchangers
prior to flooding the reactor area and fuel  transfer  canal
with water from the refueling water tank.  However, there is
still  some  residual  activity  in both the refueling water
tank and the fuel storage pools.  Thus, it is possible  that
refueling water, spent fuel coolant, new fuel pool water and
secondary  coolant  are  contaminated  as  well  as  reactor
                          174

-------
coolant and letdown.  Also, the fluids used to  transfer  or
regenerate  resins in any of the systems mentioned above may
be contaminated.  Therefore, all  leaks  and  resin-handling
and regeneration fluids from these systems are collected and
processed  in  a  radioactive waste management system (WMS).
This WMS also uses filtration, ion exchange, or distillation
or a combination of the three to produce very  low  activity
water   suitable   in   most  cases  for  discharge  to  the
environment.  Because the WMS processes a  wide  variety  of
liquids, some of which may be contaminated with oil or other
undesirable  substances,  the  WMS effluent is generally not
recycled.  Figure A-V-11 shows a block diagram of the liquid
radioactive waste management system for a PWR.

In BWRs, the reactor coolant is itself boiled and thus flows
through the steam  condensate  system.   The  condensate  is
usually  heated  and returned to the reactor.  The solutions
produced in handling or regenerating the ion exchange resins
constitute the major radioactive liquid waste in a BWR.    In
addition  to  the  equipment  for  "polishing  condensate" a
system is provided  for  filtering  and  demineralizing  the
reactor  coolant.   This  system,  called  the reactor water
cleanup  system   (RWCS),  takes  coolant  from  the  reactor
vessel,  cools  it, filters and demineralizes it and returns
it  to  the  reactor  coolant   system,   thus   controlling
nonvolatile corrosion products and impurities in the reactor
water.   Because  no boric acid is used in the reactor water
under normal  circumstances  there  is  no  feed  and  bleed
operation  for  boron concentration control and consequently
no boron management system.

As in the PWR, the water for  refueling  also  becomes  con-
taminated  and any leakage of refueling water as well as any
leakage and resin regenerating or  transporting  fluids  and
filter  backwash   (from  any  of  the  contaminated  systems
discussed above) is collected  and  treated.   Treatment  of
wastes  in a BWR also includes filtration, ion exchange, and
distillation.  The exact design of  the  systems  vary  from
plant  to  plant; however, from the liquid radioactive waste
point of view, BWRs may be placed  in  two  categories:   (1)
those  which  use  disposable  ground  resin  in  filter de-
mineralizers for condensate polishing, and  (2)  those  which
use  resin  regenerable  in  deep  bed  demineralizers.   In
general, it appears that the former system is favored except
where saline cooling water is used.

The use of regenerable resin means  that  large  volumes  of
regenerant  solutions  have  to be processed every day.  The
processing usually involves the  use  of  large  evaporators
with  total  through-put  capacity on the order of 0.0025 cu
                         175

-------
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m/s (HO gpn)  or more for some plants.  The  distillate  from
these  evaporators  is  generally  sent to high-purity waste
system for further treatment by ion exchange.  About 90%  of
the  effluent  of  this high-purity waste system is recycled
for use in the reactor and 10* discharged.

In those plants which use ground resin units for  condensate
polishing,  no  regeneration takes place since water is used
only to transport the powder.  Thus, considerably less fluid
has to be treated  and,  since  the  radionuclides  are  not
dissolved into the water, only mechanical separation such as
settling,  filtration  and  centrifuging is used for initial
treatment of the water.  Again the water is sent to a  high-
purity  waste system where it is treated by ion exchange and
the bulk of the water is recycled for  use  in  the  reactor
with the remainder discharged into the cooling water.

BWRs  usually  use ground resin filter demineralizers in the
RWCS.  The liquid from transporting ground resin in the RWCS
is treated in the same way as that  used  for  ground  resin
condensate polishers.

Other  liquid  wastes from BWRs are treated by ion exchange,
evaporation, and filtration.  Other sources  of  wastes  are
floor   drains   and  laundry  drains  (including  personnel
decontamination  and  cask  cleaning).    Distillates   from
evaporation  of  these waste are generally discharged to the
environment.   Concentrated  bottoms  from  evaporators  and
solids  from  dewatering  equipment are drummed for off-site
shipment.  Figure A-V-12 shows a block diagram of the liquid
radioactive waste handling systems of  a  BWR  of  1,100  Mw
capacity.

It  is  difficult  to  establish  the exact amount of liquid
which will be released by  the  radioactive  waste  handling
systems  of  a  power  reactor.   The  number  and  type  of
shutdowns and  load  changes  the  amount  of  leakage  from
various  systems,  and  the  degree  of recycle of processed
waste  all  affect  the  quantities  of  liquid  discharged.
However,   in   the   process   of  obtaining  licenses  for
construction  and  operation  of   a   nuclear   powerplant,
estimates  are  made  of  these  releases  based on expected
operating conditions.  A  review  of  several  Environmental
Impact  Statements  for  PWRs  and BWRs indicates a range of
effluent quantities which are expected to be discharged.

PWR wastes processed in the BMS are usually of  high  enough
quality  to  be  recycled.   In general, the distillate from
BMS's contains concentrations much lower than 1 mg/1 of  all
chemicals  other than boric acid which is present at a maxi-
                          177

-------
oa
                                                               CONDENSATE
                                                           DEMjNERALIZERS  (6)
                LOW CONDUCTIVITY WASTE
                  EQUIPMENT DRAINS FROM
                  DRY WELL. REACTOR BUILOIN6
                  AND TURBINE BUILDIN6  ETC.
                HIGH CONDUCTIVITY  WASTE
                  FLOOR  DRAINS FROM
                  DRYWELL  AND REACTOR.
                  TURBINE. AND RADWASTE
                  BUILDINGS. ETC.
                CHEMICAL WASTE
                  LABORATORY DRAINS
                  SAMPLE  DRAINS. ETC
                  DECONTAMINATION
DETERGENT WASTE	

  CASK CLEANING
  PERSONNEL DECONTAMINATION








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20.000 gal.


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20.000 gal.










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DRAIN
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                                                                                              RADIATION
                                                                                               MONITOR ~
                                              DETERGENT""!
                                             DRAIN TANKS
                                                                  SOLID WASTE
                                                               DISPOSAL  SYSTEM
                                                               SPENT RESIN AND
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                                                               DRUMMING   STATION
 DRUMMED
 WASTC TO
' OFF - SITE
 DISPOSAL
                                                                                                          4.000 gpm
                                                                                                 DISCHARGE
                                                                                                 STRUCTURE
                                                                                                           J  INTAKE
                                                                                                           r51 STRUCTURE
                                                                                              	"• —	' COLUMBIA  RIVEN -_ -. _-ir~" .-_•..-.
                                               LIQUID RADIOACTIVE  WASTE  HANDLING  SYSTEM
                                                     1100  Mw  BWR NUCLEAR PLANT
                                                           FIGURE  A-V-12

-------
mum concentration of 60 mg/1.  The anticipated quantities of
BMS discharge for a sampling of PWRs ranges from 0  to  over
5,000,000  gal/year.   The quantity of distillate discharged
from the BMS depends on the  operating  mode  of  the  plant
(i.e.  base  loaded  or load following), number of shutdowns
and the degree of distillate recycling.

Distillate from the WMS can generally be  expected  to  have
the  same  chemical  purity as that from the BMS although it
may  occasionally  contain  a  few  mg/1  of  sulfates   and
chlorides  resulting  from  processing  condensate  polisher
regenerants during primary to secondary leaks.
                                                         •.
Some of the fluids routed to the  WMS  are  not  necessarily
treated  by  the  radwaste evaporator.  These wastes are ex-
pected to  be  of  such  low  activity  that  they  will  be
filtered,   monitored,  and  then  treated  as  conventional
wastes.  The quantity of liquid discharged from the WMS of a
PWR can vary widely.   For  example,  during  a  primary  to
secondary  leak,  plant condensate polishers may process the
polisher regenerants through the WMS.  While this means that
millions of gallons of distillate may be discharged from the
WMS, it doesn't add to overall plant waste discharged  since
the regenerants would have to be processed and discharged at
nearly  the  same  rate  by chemical treatment system in the
event there were no primary to secondary leak.

As discussed  above,  the  nature  and  quantity  of  liquid
discharged  by the radioactive waste systems of a BWR differ
greatly between units  which  use  ground  resin  condensate
polishing  and  those which use conventional ion exchangers.
Even within a given type of plant there is a large variation
in techniques  for  handling  the  various  wastes  and  the
anticipated  discharge  quantities  vary  considerably.  For
example one plant using ground resin condensate polishers is
expected to discharge approximately 1.5 million gallons  per
year   while   another  also  using  similar  polishers  may
discharge five times that amount.

Because of the treatment requirements  for  removing  radio-
isotopes  from  waste  streams,  it  is  expected  that most
discharges from radioactive waste systems in BWRs will  con-
tain extremely low concentrations of chemical pollutants.

Construction Activity

There are liquid wastes associated with on-site construction
activities.   Such wastes will depend upon the type and size
of construction and the location.
                          179

-------
Generally, waste water resulting from construction  activity
will  consist Of storm water runoff from the site during the
course of construction.  This stream can be characterized by
suspended solids and turbidity resulting from  the  errosion
of soil disturbed by the construction activity.

Construction  activity  referred  to here concerns buildings
and equipment immediately related to  powerplants  and  does
not  address  the  construction  of cooling ponds or cooling
lakes, visitor centers, access roads, etc.

Chemical Discharges in General

Effluents  from  steam  electric  powerplants  contribute  a
significant portion (14%) of the total national discharge of
metals  from  major  industrial point sources.  According to
information filed by  point  source  dischargers  under  the
National  Pollution  Discharge  Elimination  System  (NPDES)
permit program, steam electric powerplants contribute 50% of
the chromium, !<*% of the copper, 10% of the iron, 21% of the
zinc, and 14% of  all  metals  as  a  whole,  found  in  the
discharges   of   U.S.    industries   designated  as  major
dischargers by EPA.

Data from NPDES permit applications stored in  the  computer
file  were  analyzed in order to determine the percentage of
total  heavy  metal  pollutants  contributed  by  the  steam
electric  power  industry.   The  analysis was done for four
specific metals: chromium, copper, iron, and zinc.

Data were available for 67% of all major dischargers and for
66% of the major steam electric powerplants.  The other  33-
3<*%  were  not  entered into the computer file.  The figures
include in most cases the contribution  from  cooling  water
discharge.

Table  A-V-13 shows the relative contribution of metals from
powerplants compared to other major industrial sources.

Extrapolating this data to all major and  minor  dischargers
caused  little  variation  in the percentage contribution of
powerplants regardless of the  assumptions  made  concerning
the relative contributions of major to minor dischargers.

A   study   by   an  EPA  contractor  (ERGO)  of  coal-fired
powerplants  showed  the  following   estimates   of   daily
discharge  from  existing   (1973) coal-fired powerplants, in
pounds.  This study covered only the coal-fired  plants  and
did  not  include  cooling water discharge.  The results are
given in Table A-V-14
                        180

-------
                  Table A-V-13
  Total Metals Discharged from Powerplants
in the U.S, (1973) Compared to Other Industrial
Sources ( Includes cooling water discharges)
Pollutant
Chromium
Copper
Iron
Zinc
Total
Discharges by Major
Steam Electric Power-
plants, Ib/day
15,365
2,739
20,683
20,099
58,886
Percentage of
All Major
Dischargers
50
14
10
21
14
                  Table A-V-14

     Total Iron and Copper Discharges from
      Coal-Fired Powerplants in the U0S,
               ,   (1973)
Source
Ash Ponds
Boiler Cleaning
Condenser Cleaning
Total
Iron, Ib/day
10,200
1,500
-
11,700
Copper, Ib/day
180
150
40
370
              181

-------
Total suspended solids in waste water streams from a typical
1,000 megawatt coal-fired plant are as follows:

         Low-volume wastes              500 Ib/day
         Coal-pile runoff               500 Ib/day
         Ash sluicing             1,240,000 Ib/day

A conventional ash pond  for  a  1,000  megawatt  coal-fired
plant  achieving  an average effluent total suspended solids
concentrations of 30 mg/1 and using 10,000,000  gallons  per
day  of  sluice  water would discharge 2,650 Ib/day of total
suspended solids.

Summary of Ch  lieal Usage

Table  A-V-15  lists  chemicals  used  in   steam   electric
powerplants corresponding to various classes of uses.  Table
A-V-16,  from  the  U.S.  Atomic Energy commission document,
"Toxicity of Power Plant Chemicals to Aquatic  Life,"  lists
chemicals  specifically  associated with nuclear powerplants
and includes some chemicals not included in Table A-V-15.**2
Table A-V-17 gives the annual use of high  tonnage  chemical
additives  by  powerplants.   Table  A-V-18  gives  chemical
compositions of trade-name microorganism control chemicals.

Classification of Waste Waters Sources

Waste  water  sources  can  be  classified  as  high-volume,
intermediate-volume, ... ^-volume, or rainfall run-off.  Table
A-V-19 lists the individual waste water sources according to
the above classification.

The  available  da\.a on waste water flow rates corresponding
to  the  various  waste  water  sources  in  steam  electric
powerplants  are  summarized  in  Table  A-V-20  along  with
typical concentrations of major pollutants.
                           182

-------
                                             Table  A-V-15

                                  CHEMICALS  USED IN  STEAM  ELECTRIC  I U./ERIIANTS
                                          Major source  is  Reference 21.
         Use
Coagulant in clarification
  water treatment
Regeneration of ion ex-
  change water treatment
Lime soda softening
  water treatment
Corrosion inhibition or scale
  prevention in boilers

pH control in boilers

Sludge conditioning


Oxygen scavengers in boilers

Boiler cleaning
Regenerants of ion exchange
  for condensate treatment
   Chemical
Aluminum sulfate
Sodium aluminate
Ferrous sulfate
Ferric chloride
Calcium carbonate
Sulfuric acid
Caustic soda
Hydrochloric acid
Common salt
Soda ash
Ammonium hydroxide
Soda ash
Lime
Activated magnesia
Ferric coagulate
Dolomitic lime
Disodium phosphate
Trisodium phosphate
Sodium nitrate
Ammonia
Cyclohexylamine
Tannins
Lignins
Chelates such as EDTA,NTA
Hydrazine
Morphaline
Hydrochloric acid
Citric acid
Formic acid
Hydroxyacetic acid
Potassium bromate
Phosphates
Thiourea
Hydrazine
Ammonium hydroxide
Sodium hydroxide
Sodium carbonate
Nitrates
Caustic soda
Sulfuric acid
Ammonex
      Use
Corrosion inhibition or scale
  prevention in cooling towers
Biocides in cooling towers
pH control in cooling towers

Dispersing agents in
  cooling towers
Biocides in condenser cooling
  water systems
Additives to house service
  water systems
                                                              Additives  to primary coolant
                                                                 in nuclear units

                                                              Numerous uses
  Chemical

Organic phosphates
Sodium phosphate
Chromates
Zinc salts
Synthetic organics
Chlorine
Hydrochlorous acid
Sodium hypochlorite
Calcium hypochlorite
Organic chromates
Organic zinc compounds
Chlorophenates
Thiocyanates
Organic sulfurs
Sulfuric acid
Hydiochloric acid
Lignins
Tannins
Polyacrylonitrile
Polyacrylamide
Polyacrylic acids
Polyacrylic acid salts
Chlorine
Hypochlorites
Chlorine
Chromates
Caustic soda
Borates
Nitrates
Boric acid
Lithium hydroxide
Hydrazine
Numerous.proprietary
  chemicals

-------
                                                                              Table  A-V-16

                                                     CHEMICALS ASSOCIATED WITH NUCLEAR POWER  PLANTS                                    Aauatic  Life-
                                           Reference:  U.S.  Atomic Energy Cocomisaion report "Toxicity of Power  Plant  Chemicals  to Aquatic  Lire
 CORROSION &  SCALE  INHIBITORS

  Chroraates

  Sodium chronate
  Sodium dlchromate
  Zinc chrornate
  Zinc dichroaste
  Potassium chroeute
  Potassium dlchroaate

  Phoaphates and Polyphosphates

  Calcium oet*pho«phate
  Sodium phosphate
  Sodium metaphosphate
  Sodium hexametaphoephate
  Sodium cripolyphosphate
  Sodium pyrophoaphate
  Zinc  phosphate
  Sodium orthophosphate
  Calcium  phoaphace

  Organic  polyphosphates

|  Glassy Silicates

  Sodium silicate

  Nitrites and  Hitratea

  Sodium nitrite
  Sodium altrate
  Potassium nitrate

   CTanatea

   Sodium  ferrocyanate

   Fluorides

   Sodium fluoride

  Amines (alao used as biocldea)

  Octadecylamina
  Ethylenedlaaine
  Cyclohexy1amlne
  Benzylamina
  Horphln*


  Che 1 at ing Agents

  Ethylenedlaaine  Tetraacetic  acid  (EOTA)
  Nitrilotrlacetlc acid  (NTA)
  LTSR - "low  temperature  scale  remover"
   (a proprietary  compound  produced  by  Dow
  Chemical)
                                       CLEANING  & NEUTRALIZING COMPOUNDS     BIOCIDES  (particularly cooling  tower use)
 Alkaline Cleaning  Stage

 Sodium hydroxide
 Calcium hydroxide
 Sodium phosphate
 Sodiua sulfate
 Sodium trlphosphate
 Aamonlum hydroxide
 Acid Cleaning Stage
 Citric acid
 SulCurie acid
Neutralising (paaslvating)  Stage

Sodium carbonate
Sodium sulfate
Sodium phosphate
Sodium dlphosphate
Sulfurlc acid
Lithium hydroxide
Mnrphollne
Sodium lignosulfonate
Cyclohexy1amlne
Ammonium sulfate
Ammonium hydroxide
Ammonia

Oxygen Rjeducejra

llydrazine
Morphollne
Sodium aulflte
Cobalt sulfate
Cobalt

Reactivity Control

Boric acid
Boron
Oxidizing Biocides

Chlorine
Bromine
Sodium hypochlorlte
Calcium hypochlorite
Potassium permanganate
Chlorinated cyanurates and inocyanuratea

Persulfate Compounda

Potassium hydrogen peraulfate

Hon - oxidising Biocides
A.  CatIonic Surftee Active Agent*

      Sulfonium

      Phoaphonium

      Araonium

      lodonlum

5.  Dithlocarbaaic Acid Salts
1.  Chlorinated and/or phenylated phenols:
      Chloro-0-phenylphenol
      2-Tert-flutyl-4-chloro-5-methylphenol               6.
      0-Benzyl-p-chlorophenol
      t> ,6-Dlchlorophenol
      2,4-Dinltrochlorobenzene
      2,6-Dlnltrochlorobenzene
      2,4,5-Trichlorophenol
      l,3-Dlchloro-5,5-Dlmethylhydranotln
      Trlchloromethyl sufone (Bis)
      Sodlun salts  (atea) of:
       0-Phenylphenol
        2,4,5-Trichlorophenol
          (flodium 2,4,5-Trlchlorophenate)
 '      Chloro-2,phenylphenol
        2-Chloro-4-phenylphenol
        2-Bromo-4-phenylphenol
       2.3.4.6-Tetrachloroohenol
        Pentachlorophenol
      Potassium salts  (ates) of:
        2,4,S-Trichlorophenol
  2.   Quaternary Amines  (quaternary ammonium compounds)
       Dllauryl dimethyl ammonium chloride
       Dilauryl dimethly ammonium oleate
       Dodecyl  trlmethyl aamonlum chloride
       Trimethyl ammonium chloride
       Octadecyl trlmethyl ammonium chloride
       N-Alkyl benzyl-N.N.N.-trisethyl
             annonlum chloride
       Alkyl-9-oethyl benzyl ammonium chloride
       Lactory mercuriphenyl annonlum lactate
       Atkvl  dlraethvl benzvl ammonium chloride
       3,4-Dlchloro benzyl ammonium chloride
       Fbenylmercuric trlhydroxyet^yl
            aamonlum lactate
       Plienyloercuric trlethanol annonium lactate
       Alkyl  (Ciz  to Cifl) dimethyl  benzyl-aanwniuni
                           chlorides
       1-Alkyl  (C& co C.g) amino-3 anInopropane monoacetate
      Sodium dimethyl dlethyl dlthiocarbamate

      Ulsodium ethylene bladlthiocarbamate

    Organic Amines (often used with  pentachlorophenol)

      Primary Rosin Amines

        Sodium carboxethyl rosin  amlne

        Rosin amine acetate

     Other Amines (primary beta-amloes and
        beta-dlamlnes )
        Chloramlne

        Benzylamlne

        Cyc lohexy 1 ami ne

        E thy lenedi amine

        Polyethyleneamlne

    Zinc and Copper Salts

        Zinc sulfate

        Copper  sulfate

        Copper citrate
                                                                                                      Arsenates
                                                                                                      Arsenic acid
                                                                                                      Sodium srsenite
                                                                                                      CORROSION PRODUCTS
                                                                                       3.   Organo-metalllc  Compounds

                                                                                            Organotlns
                                                                                              Bis (Tributyl  Tin)  oxide
                                                                                            Orgenosulfurs
                                                                                            Disulfldes
                                                                                            Organothlocyanates
                                                                                            Methylene bisthiocyanate
                                                                                                       Copper Ions
                                                                                                       Zinc  ions

                                                                                                       Inorganic Scale and Precipitates

                                                                                                       Calcium carbonate
                                                                                                       Calcium phoaphate
                                                                                                       Calcium sulfate
                                                                                                       Calcium hydroxide
                                                                                                       Magnesium carbonate
                                                                                                       Magnesium hydroxide
                                                                                                       Magnesium phosohat*
                                                                                                       Iron  oxides

-------
            Table A-V-17
      Use of High Tonnage Chemical
Additives by Steam Electric Powerplants
             (1970) 4bi
Chemical
Alum
Caustic Soda
Chlorine
Lime
Phosphate
Total
Cooling Water
Additive,
tons
2,470
-
24,642
13,324
865
41,301
Boiler Water
Additive,
tons
1,751
37,998
985
7,824
1,100
49,658
Total,
tons
3,221
37,998
25,627
21,148
1,965
90,959
                185

-------
Table   A-V-18
                                          Chemical composition of d
                                                                          nucruofgannm control chemicals
                                                                          Composition
                                                                                                    Usage
                  NALCO21-S
                    Sodium pentachlorophrnale                                 21.3
                    Sodium 2,4.5-trichlorophenale                               11-9
                    Sodium tall* of olhei chlorophenoh                           3.0
                    Inert ingredients                                           63.8
                  NALCO 25-L  or NALCO 42S-L
                    1 -Alkyl (C6  to C, j)-3mino-3-aminopropane
                     propioiule -copper acetate complex                        15.0
                    liopropyl alcohol                                          30.0
                    Copper expressed as metallic                                0.55
                    Inert ingredients                                           55.0

                  NALCO 201
                    Potassium pentachtoropherute                               15.7
                    Pol.mium 2,4,5-trichlorophenate                             9.0
                    Potassium said of other chlorophenob                         1.8
                    Inert ingredienti                                           70.3

                  NALCO 202
                    Meth)-l-l,2-dibromopropionat«                              29.7
                    Inert ingredienti                                           70.3

                  NALCO 207
                    MclhylenebisthiocyanaU                                   10.0
                    Inert ingredienti                                           90.0
                  NALCO 209
                    l,3-Diehloro-5.5-dimetriy!hydanloin                          25.0
                    Inert ingredients     "                                     75.5
                  NALCO 321
                    I -A Iky I (Cj to C| i)a amino-3-aminopropane monoacebte      20.0
                    liopropyl alcohol                                          30.0
                    Inert ingredients                                           50.0
                  NALCO 322
                    I • Alkyl (C$ toC]()tf amino-3-aminopropane monoacetate      19.8
                    2,4.5-Trichlorophenol                                       9.5
                    Iiopropyl alcohol                                          27.0
                    Inert ingredients                                           43.7
                  NA LCO 405
                    2,4-L)initrochlorobenzene                                   22.2
                    J,b-I)initroch!orobenzene                                    2.8
                    Inert ingredients                                           75.0

                   Betz A-9
                    Sodium penlachlorophenate                                24.7
                    Sodium 2,4,$-trtchlorophenate                               9.1
                    Sodium salts of other chlorophe nates                         • 2.9
                    Sodium dimethyl dithiocarbamale                            4.0
                    N-Alkyl(Ci) - 4%,C,4 - 50%.C,» - 10^)
                      dtmelhylbenzylammomum chloride                          5.0
                    Inert ingredients (including solubilizinf and
                      dispersing agents)                                        54.3

                    Bet! C-5
                      1.3-Uichloro-S,5-dimethylhydantoin                          50
                      Inert ingredients (including solubiliiing and
                       dispersing agents)                                         50
                    Retz C-30
                      Buftrichloromethyl) tulfone                                 20.0
                      Methylenc billhiocyanate                                    5.0
                      Inert ingredients (including solubilizinf and
                        dispersing agents)                                         .75.0
                    Betz C-34
                      Sodium dimethyl dithiocarbamale                            15.0
                      Nabam (disodium cthylene bisdithiocarbamaie)                15.3
                      Inert ingredients (including solubiliztng and
                        dispersing agend)                                         69.7

                    beuJ-12
                      N Alkyl (d i - 5%. C| 4 - 60%. C,« - 30%, C,» - 5%)
                        dimethylbcnzybmmonium chloride                         24.0
                      BiMtributyltin) oxide                                        5.0
                      Inert ingtcdients (including solubilizing and
                        dispersing agents)      .                                  71.0
                    B«lzF-14
                      Sodium pentachtorophrnale                                 20.0
                      Sodium 2,4,5-trtchlorophenala                               7.3 '
                      Sodium salts of chlorophenilc                                2.5
                      Dehydroabutyl ammonium phenoxide                         2.0
                      Inert ingredients, including dispersants                        68.0
Periodically, as needed,
  25-400 ppm of continuously
Weekly. 20- 300 ppra
Periodically, as needed.
  300 - 400 ppm or 12  60 ppm
  continuously
5-200 ppm periodically or
  continuously

Weekly, 25 -50 ppm


As needed, 50-100 ppra


Weekly, 5-200 ppm



As needed, 10- 200 ppm





As needed. 100-200 ppm
                        JAs-in fatty acids of coconut oil.
                        From company \ourcei and Environmental Protection Agency.
                                              186

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                   Table  A-V-19

      CLASS OF VARIOUS WASTE WATER SOURCES
     Class
                Source
High Volume
Nonrecirculating main condenser
  cooling water      	
Intermediate Volume
Nonrecirculating house service water
Blowdown from recirculating main
  cooling water system
Nonrecirculating ash sluicing systems
Nonrecirculating wet-scrubber air
  pollution control systems
Low Volume
Clarifier water treatment
Softening water treatment
Evaporator water treatment
Ion exchange water treatment
Reverse osmosis water treatment
Condensate treatment
Boiler blowdown
Boiler tube cleaning
Boiler fireside cleaning
Air preheater cleaning
Stack cleaning
Miscellaneous equipment cleaning
Recirculating ash sluicing systems
Recirculating wet-scrubber air
  pollution control systems
Intake screen backwash
Laboratory and sampling streams
Cooling tower basin cleaning
Rad wastes
Sanitary system
Recirculating house service water
Floor drainage
Miscellaneous streams
Rainfall Runoff
Coal pile drainage
Yard and roof drainage
Construction activities
                      187

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                                     Table A-V-20
              TYPICAL CHEMICAL WASTES FROM A  COAL-FIRED POWERPLANT
Waste Stream
Ion exchange
Boiler blowdown
Boiler cleaning
Boiler fireside cleaning
Air preheater cleaning
Miscellaneous cleaning
Laboratory operations
Floor drains
Recirculating bottom
ash sluicing blowdown
Ash pond overflow (once-
through fly ash)
Coal pile drainage
Flow, 1
GPD/MW
88
52
0.25
4.44
11.7
1.11
10
30
400

5000
3
•J
Typical Concentrations of Major Pollutants /mg/1
TSS
46
25
127
582
1882
1000^
100^
100^
1000

60

864
Iron
—
—
2100
142
1610
-
-
'_
_

—

—
Copper
w
-.
380
—
-
-
-
_
_

—

—
Sulfate
2085
_
—
1650
1130
-
-
—
_

. 510

6880
Hardness
_
—
520
4661
3700
-
-
_
_

244

1025
Notes:  1. Based on  the  average  of  available  data
        2. Assumed values
        3. Based on  0.02 acres/Mw coal pile and  40  inches  of rainfall per year;
             the f-low  is calculated to be  59,500 GPD for a 1000 Mw plant

-------
                           PART A

                      CHEMICAL WASTES

                         SECTION VI

             SELECTION OF POLLUTANT PARAMETERS

Definition of Pollutants

Section 502(6)  defines the term "pollutant" to mean  dredged
spoil,  solid  waste,  incinerator residue, sewage, garbage,
radioactive materials, heat, wrecked or discarded equipment,
rock,  sand,  cellar  dirt  and  industrial,  municipal  and
agricultural  waste  discharged  into  water.   This  report
addresses all  pollutants  discharged  from  steam  electric
powerplants  with  the  exception  of  both  high-level  and
low-level radioactive wastes of  nuclear  powerplants.   The
exclusion  is  made  for two reasons:  (1)  administratively,
the permiting or licensing  authority  for  nuclear  plants,
from  the  standpoint  of  radiation safety resides with the
U.S. Atomic Energy Commission; and (2)  it is not known  that
the   application  of  conventional  waste  water  treatment
technology for  the  control  of  non-radiation  aspects  of
radioactive  waste  will  not  result  in  the creation of a
radiation hazard (e.g.  due  to  the  concentration  of  the
suspended solids removed).

Introduction

Section A-V describes various operations in a steam electric
powerplant  which  give  rise  to chemical wastes.  Reported
data were included for each waste stream wherever available.
The waste streams are specific to each powerplant and depend
upon factors such as raw water quality,  type  and  size  of
plant,   age  of  plant,  ambient  conditions  and  operator
preferences.  Table A-VI-1 summarizes the pollutants present
in the various chemical waste streams based on data recorded
in Section A-V, Waste Characterization, and knowledge of the
respective processes.  The data in many cases  show  a  wide
variation  from plant to plant.  This wide variation in data
and the presence of many pollutants in a single waste stream
makes the selection of characteristic pollutants a difficult
task.  Table A-VI-2 summarizes  the  number  of  plants  for
which  data  was  recorded  in  Section  A-V  for each waste
stream.
                             189

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                                                  TABLE A-VI-1
                             APPLICABILITY  OF  PARAMETERS TO CHEMICAL WASTE STREAMS
PARAMETER
ALKALINITY
BOD
COD
TS
TDS
TSS
AMMONIA
NITRATE
PHOSPHOROUS
TURBIDITY
FECAL COLIFORM
ACIDITY
HARDNESS, TOTAL
SULFATE
SULFITE
BROMIDE
CHLORIDE
FLUORIDE
ALUMINUM
BORON
CHROMIUM
COPPER
IRON
LEAD
MAGNESIUM
MERCURY
NICKEL
SELENIUM
VANADIUM
ZINC
OIL & GREASE
PHENOLS
SURFACTANTS
ALG 1C IDES
CHLORINE
MANGANESE
Condenser
Cooling
System
Once
Through
X



















X
rRecircu-
latinq
X
X
X










X


V
X
X
Water
Treatment
Clarifi-
cation Wastes
x
x
X




0)
3
I
X 0)
H tT>
ll
X
X
X

Evaporator
X
x
x
Boiler
Blowdown
X
x
X


















!

x x

x
x
|

i

X x
V V

x x | x : x
x ! x x x

V

x
X
X XX X X









X




X

' X

X
Jf



X
y
X

X




X

X




1

X , X
x x



X X
y
X
V


X



X

X




X





X

Chemical
Cleaning
Boiler
Tubes
x
X
X








X

X

X

X
V

X
X
X

X
X

X

X
X

X


X

[Air Pre-
heater
x
X
X








X

X
J£





X
X
X

X












Boiler
Fireside
x

X








X

X
x



V

X
X
X

X



X






X

Ash Pond
Overflow
x
x
x




x
x


X
X
X
X


X
V

X
X
X
X
X
X

X
V
X
X
X
X


X

Icoal Pile 1
Drainage j







x
x


X

x
Floor 1
Drains |

Air Pollution
Devices
S<->2 Removal
V
X | X
X








X
y
X
' X



v -

X '
X
X
X
X
X

X

X

X


X
X









X


X
X
X
X



V



X

X



1 X

X

Y-


X


X




X
,
Sanitary
Wastes

x
X




X
X

X





X










W
II



















X







t

1


X
X






































































1






















































































                          Miscellaneous streams such as laboratory sampling, stack chemical  cleanings,  etc.
                          are not included since the species are accounted for  in other  streams.  .
                                                      190

-------
                                  TABLE  A-VI-2
                                   CHEMICAL WASTES-
                            NUMBER OF PLANTS WITH RECORDED DATA
PARAMETER

ALKALINITY
BOD
COD
TS
TDS
TSS
AMMONIA
NITRATE
PHOSPHOROUS
TURBIDITY
FECAL COLIFORM
ACIDITY
HARDNESS, TOTAL
SULFATE
SULFITE
BROMIDE
CHLORIDE
FLUORIDE
ALUMINUM
BORON
CHROMIUM
COPPER
IRON
LEAD
MAGNESIUM
MERCURY
NICKEL
SELENIUM
VANADIUM
ZINC
OIL & GREASE
PHENOLS
SURFACTANTS
ALGICIDES
CHLORINE
MANGANESE
Condenser
Cooling
System
Dnce
Through
_
-
-
_
_
—
-
-
-
—
-
—
-
1
-
	
2
-
-
—
-
-
-
-
-
_
-
-
-
-
-
-
-
-
-
-
Recircu-
lating
6
4
4
4
6
5
5
6
9
-


-
6
11
-

10
2
1
-
4
1
5


6
_
1




5
-
2
-
-
-
3
Water
Treatment
Clarification
Wastes
5
4
5
6
6
6
5
6
6
6


-
6
6
-

6
-
1
-
5
4
5


5
—
2




5
-
-
-
-
-
-
Ion Exchange
Wastes
12
12
12
16
18
16
15
17
20
7


-
15
23
-

21
-
-
-
14
8
13


17
2
5




16
2
5
-
_
_
4
Evaporator
5
7
7
8
9
8
7
7
9
5


-
7
7
-

8
-
-
-
8
5
5


6
2
2




8

3
2
_
-
2

Boiler
Slowdown
17
18
17
17
18
17
15
14
19
10


-
11
16
-

17
-
-
-
11
7
8


6
_
5




13
-
5
-
-
-
-
Chemical
Cleaning
Boiler
Tubes
6
6
6
6
6
6
6
5
17
6


-
4
5
-

17
10
11
-
15
17
17


13
_
14




17
-
-
-
-
-
12
Air Pre-
heater
7
7
7
7
6
7
7
7
7
7


-
7
7
-

7
-
-
-
7
5
7


7
_
7




7
-
-
-
-
-
-
Boiler
Fireside
2
2
2
2 I
2
2
2
2
2
2


-
2
2
-

2
-
-
-
2
1
2


2
-
1




2
-
-
-
-
-
-
Ash Pond
Overflow
27
-
-
28
26
26
21
21
18
12


-
19
27
-

25
-
12
-
12
7
16


15
2
4




16
-
-
-
-
-
5
Coal Pile 1
Drainage
9
4
5
6
7
7
5
5
2
3


3
4
8
-

4
-
2
-
6
4
7


2

-




7
-
-
-
-
-
-
Floor
Drains
3
3
3
3
3
3
3
3
3
3


_
-
1
_

3
_
_
_
1
-
_


_

—




1
1
1
-
—
—
—
Air Pollution
Devices
SOj Removal
1
-
-
-
1
1
-
1
1
M
_
_
1
2
2

—
_
1
_
1
1
_
i

1

1




-
-
_
-
-
_
-
Sanitary
Wastes
-
—
-
-
-
-
-
_
_
—
_
_
_
H
_

^
_
_
_
_
-
_


—

_




—
_
_
—
-
_
-
•0
nj tn
K i
II
-
—
-
-
-
-
-
_
_
_
_
_
—
_
_

—
_
_
_
—
-
_


-

_




—
-
_
-
-
_
'-





































                                            191

-------
Common Pollutants

Since powerplant waste effluents are primarily  due  to  in-
organic chemicals, the common pollutants reflect the general
level of inorganic chemical concentration.

pH Value

pH  value indicates the general alkaline or acidic nature of
a waste stream, and represents perhaps the most  significant
single  criteria  for  the  assessment  of  its  pollutional
potential.  While a pH in the neutral range between 6.0  and
9.0 does not by itself assure that the waste stream does not
contain  detrimental  pollutants, a pH outside of this range
is an immediate indication  of  the  presence  of  potential
pollutants.

Total Dissolved Solids

Total  dissolved solids represents the residue  (exclusive of
total  suspended  solids)  after  evaporation  and  includes
soluble  salts  such  as  sulfates, nitrates, chlorides, and
bromides.    Total   dissolved   solids   are   particularly
significant as a pollutant in discharges from closed systems
which  involve recirculation and re-use.  These systems tend
to concentrate dissolved solids as a result  of  evaporation
and  require  blowdown  to  maintain dissolved solids within
ranges established by process  requirements.   The  blowdown
may  contain  specific  pollutants  in  detrimental  amounts
depending on the number of cycles of concentration.

Total Suspended Solids

Total suspended solids  is  another  pollutant  which  is  a
characteristic  of  all the waste streams.  Suspended solids
are significant as an  indicator  of  the  effectiveness  of
solids separation devices such as mechanical clarifiers, ash
ponds,  etc.   One  of  the  functions  of  water  use  in a
powerplant is to convey solids from one stage of the process
to another or to a point of final disposal.  Some  processes
used  in  a powerplant create suspended solids by chemically
treating compounds in solution so that they become insoluble
and precipitate.  Turbidity is related to  suspended  solids
but  is  a  function of particle size and not an independent
pollutant.

Having  established  the  three   common   pollutants,   the
characteristic  pollutants  of  individual waste streams are
outlined below.
                             192

-------
Pollutants from Specific Waste Streams

Biochemical Oxygen Demand (BOD)

BOD is a significant pollutant only for sanitary waste water
originating from the use of  sanitary  facilities  by  plant
personnel.

Chemical Oxygen Demand (COD)

COD  is  a  pollutant  usually  attributed  to  the  organic
fraction of industrial waste waters.  Since  steam  electric
powerplants  do  not  have  a  significant volume of organic
wastes, COD is generally  not  a  significant  pollutant  in
powerplant effluents, but may be used as gross indicator for
certain combined wastes.

Oil and Grease

Oil and grease enter  the plant drainage system primarily as
a   result   of  spillage  and  subsequent  washdown  during
housekeeping operations or following natural  precipitation.
Oil  and  grease are also removed from equipment during pre-
operational cleaning.  Oil and grease is normally present in
the following waste streams:

    Chemical cleaning - boiler tubes;
                      - boiler fireside;
                      - air preheater;
                      - miscellaneous small equipment;

    Ash handling
     wastes           - oil fired plants;
                      - coal fired plants;

    Drainage and .misc.
    waste streams     - floor and yard drains;
                      - closed cooling water systems; and
                      - construction activity.

Ammonia

Ammonia is  a  significant  pollutant  in  plants  that  use
ammonia  compounds in their operations.  Ammonia may be used
to control the pH in the boiler feedwater.  It may  also  be
used  for  ion exchange regeneration in condensate polishing
and in boiler cleaning.  An ammonia  derivative,  hydrazine,
is  used  as  an oxygen scavenger, but is used only in small
quantities.  Because of its instability, it is not likely to
be a component of a waste stream.  Ammonia will therefore be
a component of those waste streams which  emanate  from  the
operations during which ammonia is added to the system, such
                             193

-------
as   ion  exchange  wastes,  boiler  blowdown,  boiler  tube
cleaning and closed cooling water systems.

Total Phosphorus

Phosphates are used by  some  powerplants  in  recirculating
systems  to  prevent  scaling on heat transfer surfaces.  To
the extent that they are used, they will be a  component  of
any  blowdown  from  such  systems.  These include primarily
boiler and PWR steam generator blowdown  and  blowdown  from
closed cooling water systems but could also include a number
of  minor  auxiliary  systems.   In  some  cases, phosphorus
compounds are also used in boiler  cleaning  operations  and
would therefore be a possible component of cleaning wastes.

Chlorine Residuals

Many   condenser  cooling  water  systems  use  chlorine  or
hypochlorites to control biological  growth  on  the  inside
surface  of condenser tubes.  The biological growth, if left
uncontrolled, causes excessive  tube  blockages,  poor  heat
transfer,  and  accelerated  system  corrosion—all of which
reduce plant efficiency.  For any cooling tower  system  the
length of time of the chlorine feed period and the number of
chlorine  feed periods per day, week, or month change as the
biological  growth  situation  changes.   In  most   cooling
systems,  the  chlorine  is  added  at or near the condenser
inlet in sufficient quantity to  produce  a  free  available
chlorine  level  of  0.1-0.6  mg/1  in the water leaving the
condenser.  The amounts of chlorine added  to  maintain  the
free  available  chlorine depend upon the amount of chlorine
demand agents and ammonia in the water.

Chlorine and ammonia react to form chloramines.  Chioramines
contribute to the combined residual chlorine of  the  water.
The  combined residual chlorine is less efficient and slower
in providing biological control than is the  free  available
chlorine.   Total  residual  chlorine is the sum of the free
available chlorine and the combined residual chlorine.

Although chlorination is  effective  for  slime  control  in
condenser  tubes  of  cooling  system,  its  application may
result in the discharge of total residual  chlorine  to  the
receiving  water.  The effects of total residual chlorine on
aquatic life are of great concern.

Metals

Various metals may be contained in some of the waste streams
as a result of corrosion and erosion of metal  surfaces  and
                              194

-------
as  soluble  components  of the residues of combustion where
such residues have been handled hydraulically.

Slowdown from  boiler  feedwater  systems  and  from  closed
cooling  water  systems  will  contain  trace amounts of the
metals making up the heat exchanger surfaces with which they
have been in contact.  Treatment of these  waters  generally
minimizes   the  amount  of  corrosion.   However,  cleaning
operations of these systems  are  designed  specifically  to
restore  the  heat transfer surfaces to bare metal.  In this
process significant amounts of metal  and  metal  oxide  are
dissolved  and are conveyed with the waste streams.  The two
most common metals likely to be present in  cleaning  wastes
are iron and copper.

Metals  present  in  wastes  from  fuel storage and from ash
handling operations will depend on the metals present in the
fuel.  Generalization  is  difficult  because  of  the  wide
variation  in  fuel  composition,  but iron and aluminum are
typically present in  significant  quantities  in  ash  from
coal.   Mercury  may  be  present if the coal used contained
mercury.  Vanadium is present in  sufficient  quantities  in
ash  resulting  from  the  burning of some types of residual
fuel oil, notably of Venezuelan origin.

If  chromates  and/or  zinc  compounds  are  used  for   the
treatment  of  closed cooling water systems, chromium and/or
zinc will be significant  pollutants  for  any  blowdown  or
leakage from these systems.

Thesfc  metals  are  likely  to  occur in the following waste
streams:

    1.  Iron

        water treatment      - clarification;
        maintenance cleaning - boiler tubes;
                             - boiler fireside;
                             - air preheater;
        ash handling         - coal fired plants;
                               and coal pile drainage.

    2.  Copper

        boiler and steam generator (PWR) blowdown;
        chemical cleaning - boiler tubes;
                          - air preheater;
                          - boiler fireside
        condenser cooling
         water systems    - once through; and recirculating
                              195

-------
    3.  Mercury

        ash handling      - coal fired plants; and coal
                             pile drainage.

    J».  Vanadium (oil-fired plants only)

        ash handling;
        chemical cleaning - boiler fireside; and
                          - air preheater.

    5.  Chromium and Zinc

        recirculating condenser cooling system; and
         closed cooling water system.

    6.  Aluminum and Zinc

        coal pile drainage;
        ash handling      - coal fired plants;
        water treatment   - clarification;
        chemical cleaning - boiler fireside; and
                          - air preheater.

Phenols

Polychlorinated biphenyls  (PCB's)  are  sometimes  used  as
coolants  in  large transformers.  PCBfs may also be used as
heat transfer fluids and for other  purposes.   In  case  of
leaks  or  spills, these materials could find their way into
the yard drainage system.  Materials showing up  as  phenols
are  also  possible  in  drainage from coal piles, floor and
yard drainage,  ash  handling  streams,  and  cooling  tower
blowdown.

Sulfate

Sulfates  in  powerplant  effluents arise primarily from the
regenerant wastes of ion exchange  processes.   Sulfate  may
occur in ion exchange and evaporator wastes, boiler fireside
and  air  preheater  cleaning,  ash  handling  and coal pile
drainage.

Sulfite

Sulfite is  used  as  an  oxygen  scavenger  in  the  boiler
feedwater  system  in some plants.  Plants using sulfite may
discharge the sulfite with their boiler  blowdown.   Because
                            196

-------
of its high oxygen demand, sulfite in significant quantities
is considered undesirable in a plant discharge.

Sulfite may occur in the following waste streams:

         maintenance cleaning - boiler fireside;
                              - air preheater;
                              - stack;
                              - cooling tower basin;
         ash handling         - oil fired plants;
                              - coal fired plants;

         coal pile drainage; and
         air pollution control
         devices for SO2 removal.

Boron

Oxidizing  agents  such as potassium or sodium borate may be
contained in cleaning mixtures used for  copper  removal  in
the  chemical  cleaning  of boiler and steam generator (PWR)
tubes.

Fluoride

Hydrofluoric acid or fluoride salts  are  added  for  silica
removal  in  the  chemiaaA  cleaning  of  boiler  and  steam
generator (PWR) tubes.

Alkalinity and Acidity

Both alkalinity, and acidity are parameters which are closely
related to the pH of a waste stream.

Total Solids

Total solids is the sum of the total  suspended  solids  and
the total dissolved solids.

Fecal Coliform

Fecal coliform is only significant in sanitary waste.

Total Hardness

Hardness is a constitutent of natural waters, and as such is
not  generally  considered  as a pollutant in effluents from
industrial processes.  Also, hardness is not harmful in  the
concentrations recorded in Section A-V.
                            197

-------
Chloride and Magnesium

Both chloride and magnesium are not practicably treatable at
the  levels recorded, and also are not harmful at the levels
present in the various waste streams.

Bromide

Bromide may result from boiler cleaning operations,  but  is
not  considered harmful at the levels present.  Moreover, it
is not practicably treatable at these levels.

Nitrate and Manganese

Nitrate and manganese are also not harmful  nor  practicably
treatable  at  the  levels  present  in  the  various  waste
streams.

Surfactants

Surfactants are not practicably treatable  at  the  recorded
levels.

Algicides

Very  little  data  was  found  for  algicides (exclusive of
chlorine) although various  algicides  may  be  utilized  in
cooling  water  systems.  Most utilities requiring algicides
utilize chlorine.

Other Potentially Significant Pollutants

The following are potentially significant pollutants,  which
may be present in effluents from steam electric powerplants,
but for which little data are available at this time.

    Cadmium
    Lead
    Nickel
    Selenium

Complete  analyses  of  the fossil fuel used by a particular
plant  can  be  used  as  a  basis  for  determining   which
pollutants,   in  addition  to  those  covered  by  effluent
limitations guidelines  and  standards,  are  likely  to  be
present in effluents in quantities justifying monitoring and
the establishment of effluent limitations.
                            198

-------
Selection of Pollutant Parameters

The U. S. Environmental Protection Agency published (Federal
Register,  Volume  38, No. 199, pp. 28758-28670, October 16,
1973) HO CFR 136 "Guidelines  Establishing  Test  Procedures
for  the  Analysis  of  Pollutants."  Seventy-one  pollutant
parameters were covered.  This list  with  the  addition  of
free available chlorine, polychlorinated biphenyls, chemical
additives,  debris and pH, which were not included, provides
the basis for the selection of pollutant parameters for  the
purpose  of  developing  effluent limitations guidelines and
standards.  All listed parameters are  selected  except  for
these excluded for one or more of the following reasons:

    1.   Not harmful when selected parameters are controlled

    2.   Not present in significant units

    3.   Not controllable

    U.   Control substitutes more harmful pollutant

    5.   Insufficient data available

    6.   Indirectly controlled when selected parameters  are
         controlled.

    7.   Indirectly measured by another parameter

    8.   Radiological pollutants not  within  the  scope  of
         effluent limitations guidelines and standards.

Table  A-VI-3  presents  a  breakdown of the methodology for
selection of parameters for the following waste water stream
(except for sanitary wastes) which comprise the entire waste
water discharged from steam electric powerplants:

    High Volume

         nonrecirculating (once-through)  condenser  cooling
         systems

    Intermediate Volume

         blowdown from recirculating condenser cooling water
         systems

         nonrecirculating ash sluicing systems;

         nonreciruclating service water systems
                             199

-------
                                                                      Table A-VI-3

                                                          SELECTION OP POLLUTANT PARAMETERS*
POLLUTANT PARAMETER

General
Acidity (as CaCO )
Alkalinity (as CaCO3)
Ammonia (as N)
Biochemical oxygen demand (5-day)
Chemical oxvqen demand
Hardness-total
Kjeldahl nitrogen (as N)
Nitrate (as N)
Nitrite (as N)
pH value
Total dissolved (filterable) solids
Total organic carbon
Total phosphorus (as P)
Total solids
Total suspended (nonf ilterable) solids
Total volatile solids
Nutrients, Anions. and Orqanics
Algicides
Benzidine
Bromide
Chloride
Chlorinated organic compounds
Chlorine-free available
Chlorine— total residual
Cyanide-total
Debris
Flouride
Oil and grease
Organic nitrogen (as N)
Ortho-phosphate (as P)
Pesticides
Phenols
Polychlorinated biphenyls
Sulfate (as SO )
Sulfide (as S)
Sulfite (as SO )
Surfactants
Chemical additives (biocide,corr. inhib. )
CLA
High-Volume
1
1
2
2
2
3
2
2
2
2
3
2
2
3
3
2
6
2
2
3
2
•
6 **
2
•
2
2
2
2
2
2
2
3
3
3
2
6**
SS OF WASTE WATER STREAMS
Intermediate- Volume
1
1
2
2
2
4
2
2
2
•
3
2
•
6
•
2
6
2
3
3
5
•
6**
2
2
2
•
2
6
5
2
2
3
3
3
6
6**

Low-Volume
'l
1
2
2
?
4
2
2
2
6
2
6
6
•
2
5
2
3
3
5
2
2
2
2
6
•
2
6
2
2
2
3
3
3
6
6 •

Rainfall Runoff
1
1
2
2
2
4
2
2
2
•
3
2
2
6
•
2
2
5
3
3
5
2
2
2
2
2
•
2
2
5
2
•
3
3
3
2
2
*Keyi • =Selected                                                             5 =Rejected because insufficient  data  available
      1 =Rejected because not harmful when selected parameters are controlled 6 =Rejected because indirectly controlled when selected parameters
      2 =Rejected because not present in significant amounts                       are controlled
      3 =Rejected because not controllable
      4 =Rejected because control substitutes a more harmful pollutant
  Selected where technology is available to achieve no discharge
7 =Rejected because indirectly measured by another parameter
8 =Rejected because radiological pollutants are not within the
     scope of EoP.Ao guidelines and standards

-------
                                                                      Table A-VI-3  (continued)

                                                            SELECTION OF POLLUTANT PARAMETERS *
POLLUTANT PARAMETER CLASS OF WASTE WATER STREAMS

Trace Metals
Aluminum-total
Antimony-total
Arsenic-total
Barium-total
Beryllium-total
Boron-total
Cadmi urn- tota 1
Calcium- total
Chromium- VI
Chromium-total
Cobalt-total
Copper-total
Iron-total
Lead-total
Magnes ium— total
Manganese-total
Mercury-total
Molybdenum-total
Nickel-total
Potassium-total
Selenium-total
Silver-total
Sodium-total
Thallium-total
Tin-total
Titanium-total
Vanadium-total
Zinc-total
Physical and Biological
Coliform bacteria (fecal)
Coliform bacteria (total)
Color
Fecal streptococci
Specific conductance
Turbidity
Radiological
Alpha— counting error
Alpha-total
Beta-counting error
Beta-total
Radium-total
High-Volume

2
2
2
2
2
2
2
1
2
2
2
3
3
2
1
2
2
2
3
1
2
2
1
2
2
2
2
2

2
2
2
2
2
3

8
e
8
8
8
Intermediate- Volume

6
2
2
2
2
3
3
1
6
•
2
6
6
2
1
2
2
2
6
1
2
2
1
2
2
2
2
•

2
2
6
2
7
6

8
8
8
8
8
Low— Volume

6
2
2
2
2
3
2
1
6
6
2
•
•
2
1
2
2
2
6
1
2
2
1
2
2
2
2
6

2
2
6
2
7
6

8
8
8
8
8
Rainfall Runoff

6
2
2
2
2
3
2
1
2
2
2
2
2
2
1
2
2
2
6
1
2
2
1
2
2
2
2
2

2
2 '
6
2
7
6

8
8
8
8
8
*Key • =Selected
     1 =Rejected because not harmful when selected parameters are controlled
     2 =Rejected because not present in significant amounts
     3 =Rejected because not controllable
     4 =Rejected because control substitutes a more harmful  pollutant
5 =Rejected because insufficient data avialable
6 =Rejected because indirectly controlled when selected parameters
     are controlled
7 =Rejected because indirectly measured by another parameter
8 =Rejected because radiological pollutants are not within the
     scope of E.P.A. guidelines and standards

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         nonrecirculating   wet-scrubbing   air    pollution
         control systems

    Low Volume

         blowdown from recirculating ash sluicing systems

         blowdown  from,   recirculating   wet-scrubber   air
         pollution control systems

         boiler blowdown

         equipment cleaning (air preheater, boiler fireside,
         boiler tubes, stack, etc.)

         evaporator blowdown

         flow drains

         intake screen backwash

         recirculating service water systems

         water treatment system

    Rainfall Runoff

         coal pile drainage

         road and yard drains

         construction activities

    Sanitary System

    The selected parameters for the various classes of waste
water streams are shown in Table A-VI-4.

Environmental Sicrnificance of Selected Pollutant Parameters

The environmental significance  of  many  of  the  pollutant
parameters evaluated in this section are discussed in detail
in  "Water Quality Criteria 1972,'• a report of the Committee
on Water  Quality  Criteria,  Environmental  Studies  Board,
National    Academy    of   Sciences/National   Academy   of
Engineering, published in 1972 at the request of and  funded
by  the  U.S.  Environmental  Protection Agency.  The report
addresses the several parameters individually in  the  light
of water quality needs for recreation and aesthetics, public
                           202

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                Table A-VI- 4
        SELECTED POLLUTANT PARAMETERS
 Class of Waste Water Stream
         Parameter
High Volume
Chemical additives
  (biocides)*
Chlorine-free available
Chlorine-total residual*
Debris
Intermediate Volume
Chemical additives
  (corrosion inhibitors)*
Chlorine-free available
Chlorine-total residual*
Chromium-total
Oil and grease
pH value
Total phosphorus (as P)
Total suspended solids
Zinc-total
Low Volume
Copper-total
Iron-total
Oil and grease
pH value
Total suspended solids
Rainfall Runoff
Oil and grease
pH value
Polychlorinated biphenyls
Total suspended solids
 * Note: Selected where technology is available to
         achieve no discharge.
                           203

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water  supplies,  freshwater  and aquatic life and wildlife,
agricultural uses, and industrial water supplies.

Briefly  summarized  below  are   factors   concerning   the
environmental   significance  of  the  pollutant  parameters
selected in this section.

Iron-Total

Iron is the fourth most abundant, by weight, of the elements
that make up the earth1s crust.  It is common in many  rocks
and  is an important component of many soils, especially the
clays where usually it is  a  major  constituent.   Iron  in
water  may  be  present in varying quantities dependent upon
the geology of the area and other chemical components of the
waterway.

The ferrous,  or  bivalent  (Fe  ++),  and  the  ferric,  or
trivalent   (Fe  +++) irons, are the primary forms of concern
in the aquatic environment, although other forms may  be  in
organic  and  inorganic wastewater streams.  The ferrous (Fe
*+) form can persist only in waters void of dissolved oxygen
and originates usually from  ground  waters  or  mines  when
these  are  pumped  or  drained.  For practical purposes the
ferric (Fe ++) form is insoluble.  Iron can exist in natural
organomettallic or  humic  compounds  and  colloidal  forms.
Black  or  brown  swamp waters may contain several parts per
million of iron in the  presence  or  absence  of  dissolved
oxygen, but this iron form has little effect on aquatic life
because it is ccmplexed or relatively inactive chemically or
physiologically.

In  stratified  lakes  with  anaerobic  hypolimnia,  soluble
ferrous iron occurs in the deep  anaerobic  waters.   During
the  autumnal or vernal overturns and with aeration of these
lakes, it  is  oxidized  rapidly  to  the  ferric  ion  that
precipitates to the bottom sediments as a hydroxide, Fe(OH)3
or  with ether anions.  If hydrogen sulfide  (H2S) is present
in anaerobic bottom waters or muds,  ferrous  sulfide  (FeS)
may  be  formed.   Ferrous  sulfide  is a black compound and
results in the production of dark mineral muds.

Prime iron pollution sources  are  industrial  wastes,  mine
drainage  waters,  and  ironbearing  ground  waters.  In the
presence of dissolved oxygen, waters from mine drainage  are
rapidly   precipitated  as  a  hydroxide   (Fe(OH)3).   These
yellowish  or  ochre  precipitates  produce   "yellow   boy"
deposits  found in many streams draining coal mining regions
of  Appalachia.   Occasionally  ferric  oxide    (Fe203)    is
precipitated,   which  forms  red  waters.   Both  of  these
                           204

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precipitates form as gels or floes that may  be  detrimental
when  suspended  in  water to fishes and other aquatic life.
They can settle to  form  flocculant  materials  that  cover
stream    bottoms    thereby    destroying   bottom-dwelling
invertebrates, plants or incubating fish  eggs.   With  time
these  floes  can consolidate to form cement-like materials,
thus consolidating bottom gravels into  pavement-like  areas
that  are  unsuitable  as  spawning  sites for nest building
fishes; particularly this is detrimental to trout and salmon
populations whose eggs are protected in the  interstices  of
gravel  and  incubated  with  oxygen  bearing waters passing
through the gravel.

Iron is an objectionable constituent in water  supplies  for
either domestic dr industrial use.  Iron appreciably affects
the  taste  of beverages and can stain laundered clothes and
plumbing fixtures.  A study by  the  Public  Health  Service
indicates  that the taste of iron may be readily detected at
1.8 mg/1 in spring water and 3.H mg/1 in distilled water.

96 hour LC50 values of 0.32 mg/1 of iron have been  obtained
for mayflies, stoneflies, and caddisflies; all are important
fish  food  organisms.   Iron  has  been found toxic to carp
(Cyprinus carpio) at concentrations of 0.9 mg/1 when the  pH
of  the  waters  was  5.5.   Pile   (Esox  lucius)  and trout
(species not known) died at concentrations of 1-2 mg/1.   In
an  iron  polluted Colorado stream, trout or other fish were
not found until the waters were  diluted  or  the  iron  had
precipitated to effect a concentration of less than 1.0 mg/1
even  though  other water quality constituents measured were
suitable fcr the presence of trout.

Ferric hydroxide floes have been observed to coat the  gills
of  white perch  (Roccus americanus), minnows and silversides
(Menidia sp. ?)  The  smothering  effects  of  settled  iron
precipitates  may  be  particularly detrimental to fish eggs
and bottom-dwelling fish food organisms.  Iron  deposits  in
the Brule River, Michigan and Wisconsin were found to have a
residual  long  term  adverse  effect on fish food organisms
even after the pumping of  iron  bearing  waters  from  deep
shaft  iron mines had ceased.  Settling iron floes have also
been reported to trap and carry diatoms down from waters.

The  effects  of  iron  on  marine  life   have   not   been
investigated   adequately   to  determine  a  water  quality
criterion.  Soluble iron readily  precipitates  in  alkaline
sea  waters.   Fears  have been expressed that these settled
iron floes may have adverse  effects  on  important  benthic
commercial mussel and other shellfish resources.
                            205

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Iron  has  not  been reported to have a direct effect on the
recreational uses of water other than its effects on aquatic
life.   Suspended  iron  precipitates  may  interfere   with
swimming  and  be  aesthetically objectionable.  Deposits of
yellow ochre or reddish iron  oxides  can  be  aesthetically
objectionable.

Iron at exceedingly high concentrations has been reported to
be  toxic  to livestock and interfere with the metabolism of
phosphorus.  In aerated soils, iron in irrigation waters are
not toxic.  Precipitated iron  may  complex  phosphorus  and
molybdenum  making  them  less available as plant nutrients.
In alkaline soils,  iron  may  be  so  insoluble  as  to  be
deficient  as  a  trace  element and result in chlorosis, an
objectionable plant nutrient deficiency disease.

Polychlorinated Biphenyls

Polychlorinated biphenyls (PCB's) are a class  of  compounds
produced  by  the chlorination of biphenyls and are known in
the United States commercially as Aroclors (R).  The  degree
of  chlorination  determines  their  chemical properties and
generally  their  composition  can  be  identified  by   the
numerical  nomenclature,  e.g.,  Aroclor 1242,  Aroclor 1254,
etc.  The first two digits represent the molecular type  and
the  last  two  digits  the  average percentage by weight of
chlorine.  Gas-liquid chromatography with  highly  sensitive
and  selective  detectors  has been employed successfully in
their detection at low levels.  PCB compounds  are  slightly
soluble  in  water;  soluble  in  fats,  oils,   and  organic
solvents,  and  resistant  to  both  heat   and   biological
degradation.    Typically,  the  specific  gravity,  boiling
point, and  melting  point  of  PCB's  increase  with  their
chlorine   content.  PCB's are relatively non-flammable have
useful cooling, insulating, and dielectric  properties,  and
principally   are   used   in  the  electrical  industry  in
capacitors and transformers.

Exposure to PCB is  known  to  cause  skin  lesions  and  to
increase  liver  enzyme  activity  that may have a secondary
effect on reproductive processes.  It is not  clear  whether
the  effects are due to the PCB's or their contaminants, the
chlorinated dibenzofurans,  that  are  very  harmful,  while
chlorinated dibenzofurans are a byproduct of PCB production,
it  is  not  known  whether  they  are  also produced by the
degradation of PCB's.

Analyses of 40 fish, in one program, indicated only one fish
to contain less  than  1  ug/g  PCB  with  the  ten  highest
residues ranging from 19 ug/g to 213 ug/g whole body weight.
                            206

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Studies  of  the  Milwaukee  River  revealed  ambient  water
concentrations of 2.0 to 2.8 ug/1 and residues  in  fish  as
high  as  105 ug/g.  Open water Lake Michigan concentrations
have been reported to be  less  than  0.01  ug/1  with  mean
residues in coho salmon of about 15 ug/g.  The Food and Drug
Administration  guideline for protecting the health of human
consumers of fish is 5 ug/g  in  tissue  residues  of  fish.
Based  on  Lake  Michigan  data,  which  indicate  that at a
concentration of 0.01 ug/1 the fish tissue residues exceed a
level found to be non-hazardous to man, a criterion of 0.001
ug/1 in freshwater is warranted.

Bluegill  sunfish  exposed  to  Aroclors  1248   and   1254,
exhibited  a  bioaccumulation  factor  of  7.1  x  10*.  The
bioaccumulation factor for gizzard shad in the Saginaw River
(Michigan) varied between 0.6 x 10 9 and  1.5  x  10  s  for
Aroclor 1254.  A residue level of 2 ug/g in fish consumed by
commercial  ranch mink has been shown to prevent survival of
offspring.  Reproduction was almost  totally  eliminated  in
ranch  mink  fed a beef diet containing 0.64 ug/g of Aroclor
1254.  This suggests that a mink-food tissue  level  of  not
more than 0.5 ug/g would be required to protect the wildlife
consumer.

Median  PCB  concentrations  in  whole fish of eight species
from Long Island Sound obtained in 1970 were reported to  be
in  the  order  of 1 ug/g, as were comparable concentrations
off the coast of Southern California.   Generally,  residues
in ocean fish have been below 1 ug/g.

Surveys  of Escatnbia Bay  (Florida) have produced data on the
pathways and effects of PCB's in the  estuarine  and  marine
environments.   Although  the  major  PCB source, accidental
leakage from a PCB manufacturing plant has been  terminated,
residues continue to be observed in aquatic organisms of the
bay.   The  sediment reservoir of Aroclor 1254 is thought to
be a continuing source of PCB to biota.  The initial  survey
of  Escambia Bay biota revealed fish, shrimp, and crabs with
levels as high as 12 ug/g.  Higher levels were  detected  in
higher  trophic  levels than shrimp, which could implicate a
chain transfer from sediment to large animals.

From the  Escambia  Bay  data,  which  include  flow-through
bioassays   with   residue   analyses  where  possible,  the
following conclusions were reached:  (1)  all of the Aroclors
tested are acutely toxic for  certain  estuarine  organisms;
(2)   bioassays  lasting  longer  than 96 hours demonstrated
that Aroclor 1254 is toxic to commercial shrimp at less than
1  ug/1;   (3)  fish,  particularly  sheephead  minnows,  are
extremely  sensitive  to  Aroclor  1254  with 0.1 ug/1 being
                             207

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lethal to fry; and (4)  acute toxicity  of  Aroclor  1016  to
estuarine  organisms  is  similar  to  the toxicity of other
Aroclors  but  appears  less  toxic  to  fish  in  long-term
exposures than does Aroclor 1254.

Oysters   were   sensitive   to  Aroclor  1260  with  growth
diminished by 44 percent in 10 ug/1 and by 52 percent in 100
ug/1.  Approximately 10 percent of the pink shrimp  died  in
100  ug/1,  but no apparent effects on pinfish were noted at
100 ug/1.  Aroclor 1254 had no apparent effect  on  juvenile
pinfish  at  100  ug/1  in  48-hour  flow-through tests, but
killed 100 percent of the  pink  shrimp.   At  100  ug/1  of
Aroclor  1254  for  96  hours,  shell  growth of oysters was
inhibited and decreased only 41 percent  at  levels   of  10
ug/1.   The  toxicity of Aroclor 1248 and 1242 to shrimp and
pinfish was similar to that of Aroclor 1254.   Aroclor  1242
was  toxic  to  oysters at 100 ug/1.  Killfish exposed to 25
mg/1 of Aroclor 1221 suffered an 85 percent  mortality.   In
96-hour bioassays, Aroclor 1016 was toxic to an estimated 50
percent of the oysters, brown shrimp, and grass shrimp at 10
ug/1; it was toxic to 18 percent of the pinfish at 100 ug/1.

Young  oysters  exposed to Aroclor 1254 in flowing sea water
for 24 weeks experienced reduction in growth  rates  at  4.0
ug/1, but apparently were not affected by 1.0 ug/1/  Oysters
accumulated   as   much   as  100,000  times  the  testwater
concentration of 1.0 ug/1.  Tissue alterations were noted in
the oysters exposed to 5.0 ug/1.  No  significant  mortality
was observed in oysters exposed continuously to 0.01 ug/1 of
Aroclor 1254 for 56 weeks.

Blue crabs apparently were not affected by a 20 day exposure
to  5.0  ug/1  of  Aroclor  1254.  Fink shrimp exposed under
similar conditions experienced a 72 percent  mortality.   'In
subsequent   flow-through   bioassays,  51  percent  of  the
juvenile shrimp were killed by Aroclor. 1254 in 15  days  and
50 percent of the adult shrimp were killed at 3.0 ug/1 in 35
days.   From  pathological  examinations of the exposed pink
shrimp, it appears that Aroclor 1254 facilitates or enhances
the expression of latent viral infections.  Aroclor 1254 was
lethal to grass shrimp at 4.0 ug/1 in 16 days, to  amphipods
at  10  ug/1  in  30  days, and to juvenile spot at 5.0 ug/1
after 20 to  45  days.   Sheephead  minnows  were  the  most
sensitive  estuarine organisms to Aroclor 1254 with 0.3 ug/1
being lethal to the fy within 2 weeks.  Aroclor 1016 in  two
different  42- day flow-through bioassays caused significant
mortalities of pinfish at 32 ug/1 and 21 ug/1.  Pathological
examination of those exposed to  32  ug/1  revealed  several
liver  and  pancreatic alterations.  Sheephead minnows in 28
day Aroclor 1016 flow-through bioassays were not affected by
                              208

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concentrations of 10 ug/1 or less, but died at  32  and  100
ug/1.   The  bioaccumulation factors for the different flow-
through bioassays  ranged  from .2.5  x  103  for  sheephead
minnows to 1.0 x 10s for oysters.

Based  upon  an accumlation factor of 100,000 in the oyster,
it may be necessary to limit the marine water  concentration
of  PCB's  to  a  maximum  of 0.01 ug/1 to protect the human
consumer.

Evidence is accumlating that  PCB1s  do  not  contribute  to
shell  thinning  of  bird  eggs.  Dietary  PCB's produced no
shell thinning in eggs of Mallard ducks.  PCB's may increase
susceptibility to infectous agents such as  viral  diseases,
and  increase  the  activity  of  liver enzymes that degrade
steroids, including sex hormones.  Laboratory  studies  have
indicated  that  PCB  with  its  derivatives or metabolites,
causes enbryonic death of birds.

Chlorine-Free Available, - Total Residual

Elemental chlorine is a greenish-yellow gas that  is  highly
soluble  in  water.   It reacts readily with mandy inorganic
substances and all animal and  plant tissues.

The denaturing  effect  of  chlorine  on  animal  and  plant
tissues forms the basis for its use as an effective water or
wastewater  disinfectant.  When chlorine dissolves in water,
it hydrolyzes according to the reaction: C12 «• H2O =  HOCl +
H+ + Cl~.  Unless the concentration of the chlorine solution
is above 1,000 mg/1, all chlorine will be  in  the  form  of
HOCl  or  its disassociated ions H+ and OC1-.  The HOCl is a
weak acid and disassociates according to the equation HOCl =
H+ + OC1-.

The ratio between HOCl and OC1 - is a function  of  the  pH,
with  96 percent HOCl remaining at pH 6, 75 percent at pH 7,
22 percent at pH 8 and 3 percent at pH 9.  The  relationship
of  HOCl  and pH  is significant as the undisassociated form
appears to be the bactericidal agent in the use of  chlorine
for disinfection.

Chlorine  is  not  a  natural  constituent  of  'water.  Free
available chlorine  (HOCl and  OCl)  and  combined  available
chlorine   (mono-  and  di-chloramines) appear transiently in
surface or ground waters as  a  result  of  disinfection  of
domestic  sewage  or  from  industrial  processes  that  use
chlorine for bleaching operations or  to  control  organisms
that  grow  in  cooling water systems.  Chlorine in the free
available  form  reacts  readily  with  nitrogenous  organic
                              209

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materials  to form chloramines.  These compounds are harmful
to fish.  Chloramines have been shown to  be  slightly  less
harmful  to  fish  than free chlorine, but their toxicity is
considered  to  be  close  enough  to  free  chlorine   that
differentiation  is  not  warranted.   Since the addition of
chlorine or hypochlorites to  water  containing  nitrogenous
materials rapidly forms chloramines, toxicity in most waters
is related to the chloramine concentration.  The toxicity to
aquatic  life of chlorine will depend upon the concentration
of total residual chlorine, which is the relative amount  of
free   chlcrine   plus   chloramines.   The  persistence  of
chloramines is dependent on  the  availability  of  material
with   a   lower  oxidation-reduction  potential.   In  most
receiving  water,  chloramines  will   combine   with   such
materials within a few days to form other compounds that may
have toxic effects on fish.

In  field  studies  in Maryland and Virginia it was observed
that, downstream from plants discharging chlorinated  sewage
effluents,   the   total   numbers   of  fish  species  were
drastically reduced with the  stream  bottom  clear  of  the
wastewater    organisms    characteristically   present   in
unchlorinated wastewater discharges.  No fish were found  in
water  with  a  chlorine  residual  above  0.37 mg/1 and the
species diversity index reaches zero at  0.25  mg/1.   A  50
percent  reduction in the species diversity index occured at
0.10 mg/1.  Of the 45 species of fish observed in the  study
areas,  the  brook  trout  and  brown  trout  were  the most
sensitive and were not found  at  residual  chlorine  levels
above  about  0.02 mg/1.  In studies of caged fish placed in
waters downstream from chlorinated wastewater discharge,  it
has  been reported that 50 percent of the rainbow trout died
within 96 hours at residual chlorine concentrations of 0.014
to 0.029 mg/1.  Some fish died as far as 0.8 miles (1.3  km)
downstream   from   the   outfall.   Studies  indicate  that
salmonids are  the  most  sensitive  fish  to  chlorine.   A
residual  chlorine concentration of 0.006 mg/1 was lethal to
trout fry in two days.  The 7-day LC50 for rainbow trout was
0.08 mg/1 with an estimated median period of survival of one
year at 0.004 mg/1.  Rainbow trout were  shown  to  avoid  a
concentration  of 0.001 mg/1.  it has been demonstrated that
brook trout had a mean survival time of 9 hours at 0.35 mg/1
18 hours at 0.08 mg/1  and  48  hours  at  0.04  mg/1,  with
mortality  of  67  percent  after 4 days at 0.01 mg/1,  A 50
percent brcwn trout mortality has been observed at 0.02 mg/1
within 10.5 hours and at 0.01 mg/1 within 43.5 hours.

The range of acutely lethal residual chlorine concentrations
is narrow for various species of warm water fish. 96 -  hour
LC50  values  have  been  determined  for the walleye, black
                            210

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bullhead, white sucker, yellow perch, largemouth  bass,   and
fathead  minnow.   The observed concentration range was  0.09
to 0.30 ing/I.

Using fathead minnows in a continuous bioassay technique, it
has been found that an average concentration of 0.16 to  0.21
mg/1 killed all of the test fish and that concentrations  as
low  as  0.07  mg/1  caused  partial  kills.   A  50 percent
mortality has been demonstrated of smallmouth  bass  exposed
to  0.5  mg/1  within  fifteen hours.  The mean 96-hour  LC50
value for golden shiners was 0.19 mg/1.  It has  been  found
for  fathead  minnows and the freshwater crustacean Gammarus
pseudolimnaeus in dilute wastewater that the 96-hour LC50 of
total residual chlorine for Gammarus was 0.22 mg/1 and  that
all  fathead  minnows were dead after 72 hours at 0.15 mg/1.
At concentrations of 0.9 mg/1, all fish survived  for  seven
days,  when  the  first death occurred.  In exposure to  0.05
mg/1 residual chlorine, investigators found reduced survival
of  Gammarus  and  at   0.0034   mg/1   ther   was   reduced
repreduction.   Growth and survival of fathead minnows after
21 weeks were not affected by continuous exposure  to  O.OU3
mg/1  residual  chlorine.   The  highest  level  showing  no
significant effect was 0.016  mg/1.   With  secondary  waste
water  effluent,  reproduction  by  Gammarus  was reduced by
residual concentrations above 0.012 mg/1 residual chlorine.

In marine water, 0.05 mg/1 was the critical  chlorine  level
for  young  Pacific  salmon exposed for 23 days.  The lethal
threshold for chinhook salmon and coho salmon for a  72-hour
exposure  was  noted  to  be  less  than 0.01 mg/1 chlorine.
Studies  on  the  effect  of  residual  chlorine  to  marine
phytoplankton  indicate  that  exposure to 0.10 mg/1 reduced
primary production by 70 percent  while  0.2  mg/1  for  1.5
hours   resulted   in  25  percent  of  primary  production;,
Labortory studies on ten  species  of  marine  phytoplankton
indicate  tht a 50 percent reduction in growth rate occurred
at chlorine concentrations of 0.075 to 0.250 mg/1  during  a
24-hour  exposure period.  Oysters are sensitive to chlorine
concentrations of 0.01 to 0.05 mg/1 and  react  by  reducing
pumping  activity.   At chlorine concentrations of 1.0 mg/1,
effective pumping could not be maintained.

Chromium-Total

Chromium, in its various valence  states,  is  hazardous  to
man.   It  can  produce lung tumors when inhaled and induces
skin  sensitizations.   Large  doses   of   chromates   have
corrosive  effects  on  the  intestinal  tract and can cause
inflammation of the kidneys.  Levels of chromate  ions  that
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have  no  effect  on  man appear to be so low as to prohibit
determination to date.

The toxicity of chromium salts toward  aquatic  life  varies
widely  with  the  species,  temperature, pH, valence of the
chromium,   and   synergistic   or   antagonistic   effects,
especially  that  of hardness.  Fish are relatively tolerant
of chromium salts, but fish focd organisms and  other  lower
forms  of  aquatic  life  are extremely sensitive.  Chromium
also inhibits the growth of algae.

In some  agricultural  crops,  chromium  can  cause  reduced
growth  or  death  of  the  crop.   Adverse  effects  of low
concentrations of chromium on corn, tobacco and sugar  beets
have been documented.

Copper-Total

Copper  salts  occur in natural surface waters only in trace
amounts, up to about  0.05  mg/1,  so  that  their  presence
generally  is the result of pollution.  This is attributable
to the corrosive action of the water  on  copper  and  brass
tubing,  to  industrial effluents, and frequently to the use
of copper compounds for the control of undesirable  plankton
organisms.

Copper  is not considered to be a cumulative systemic poison
for humans, but it can cause  symptoms  of  gastroenteritis,
with  nausea  and  intestinal irritations, at relatively low
dosages.  The limiting factor in domestic water supplies  is
taste.    Threshold   concentrations  for  taste  have  been
generally reported in the range of 1.0-2.0 mg/1  of  copper,
while  as  much  as  5-7.5  mg/1  makes the water completely
unpalatable.

The  toxicity  of  copper  to   aquatic   organisms   varies
significantly,  not only with the species, but also with the
physical  and  chemical  characteristics   of   the   water,
including   temperature,  hardness,  turbidity,  and  carbon
dioxide content.  In hard  water,  the  toxicity  of  copper
salts is reduced by the precipitation of copper carbonate or
other insoluble compounds.  The sulfates of copper and zinc,
and  of  copper  and  cadmium are synergistic in their toxic
effect on fish.

Copper concentrations less than 1 mg/1 have been reported to
be toxic, particularly in soft water, to many kinds of fish,
crustaceans,   mo Husks,    insects,    phytoplankton    and
zooplankton.   Concentrations  of  copper,  for example, are
detrimental to some oysters above 0.1 ppm.  Oysters cultured
                             212

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in sea water containing 0.13-0.5 ppm of copper deposited the
metal in their bodies and became unfit as a food substance.

Oil and Grease

Oil and grease exhibit an oxygen demand.  Oil emulsions  may
adhere  to  the  gills  of fish or coat and destroy algae or
other plankton.  Deposition of oil in the  bottom  sediments
can   serve   to   exhibit   normal  benthic  growths,  thus
interrupting the aquatic food chain.  Soluble and emulsified
material ingested by fish may taint the flavor of  the  fish
flesh.   Water  soluble components may exert toxic action on
fish.  Floating oil may reduce the re-aeration of the  water
surface and in conjunction with emulsified oil may interfere
with  photosynthesis.  Water insoluble components damage the
plumage and costs of  water  animals  and  fowls.   Oil  and
grease   in   a   water  can  result  in  the  formation  of
objectionable surface slicks preventing the  full  aesthetic
enjoyment of the water.

Oil  spills  can damage the surface of boats and can destroy
the aesthetic characteristics of beaches and shorelines.

pH, Acidity and Alkalinity

Acidity and alkalinity are  reciprocal  terms.   Acidity  is
produced   by  substances  that  yield  hydrogen  ions  upon
hydrolysis and alkalinity is  produced  by  substances  that
yield  hydroxyl  ions.  The terms "total acidity11 and "total
alkalinity" are often used to express the buffering capacity
of a solution.  Acidity  in  natural  waters  is  caused  by
carbon dioxide, mineral acids, weakly dissociated acids, and
the  salts  of  strong  acids and weak bases.  Alkalinity is
caused by strong bases and the salts of strong alkalies  and
weak acids.

The term pH is a logarithmic expression of the concentration
of  hydrogen  ions.  At a pH of 7, the hydrogen and hydroxyl
ion concentrations are essentially equal and  the  water  is
neutral.   Lower  pH  values  indicate  acidity while higher
values indicate alkalinity.  The relationship between pH and
acidity or alkalinity is not necessarily linear or direct.

Waters with a pH below 6.0  are  corrosive  to  water  works
structures,   distribution  lines,  and  household  plumbing
fixtures and can thus  add  such  constituents  to  drinking
water as iron, copper, zinc, cadmium and lead.  The hydrogen
ion concentration can affect the "taste" of the water.  At a
low  pH  water  tastes  "sour".   The bactericidal effect of
chlorine  is  weakened  as  the  pH  increases,  and  it  is
                              213

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advantageous  to  keep  the  pH  close  to  7.  This is very
significant for providing safe drinking water.

Extremes  of  pH  or  rapid  pH  changes  can  exert  stress
conditions  or  kill  aquatic  life  outright.   Dead  fish,
associated algal blooms, and  foul  stenches  are  aesthetic
liabilities  of  any  waterway.   Even moderate changes from
"acceptable" criteria limits of pH are deleterious  to  some
species.   The  relative  toxicity  to  aquatic life of many
materials  is  increased  by  changes  in  the   water   pH.
Metalocyanide  complexes  can  increase  a  thousand-fold in
toxicity with a drop of 1.5 pH units.  The  availability  of
many  nutrient  substances  varies  with  the alkalinity and
acidity.  Ammonia is more lethal with a higher pH.

The  lacrimal  fluid  of  the  human  eye  has   a   pH   of
approximately  7.0  and  a deviation of 0.1 pH unit from the
norm  may  result  in  eye  irritation  for   the   swimmer.
Appreciable irritation will cause severe pain.

Phosphorus-Total

During  the  past  30 years, a formidable case has developed
for the belief that increasing  standing  crops  of  aquatic
plant growths, which often interfere with water uses and are
nuisances  to  man,  frequently  are  caused  by  increasing
supplies of phosphorus.  Such phenomena are associated  with
a  condition  of  accelerated  eutrophication  or  aging  of
waters.  It is generally recognized that phosphorus  is  not
the  sole  cause of eutrophication, but there is evidence to
substantiate that it is frequently the key element in all of
the elements required by fresh water plants and is generally
present in the least amount relative to need.  Therefore, an
increase in phosphorus allows use of other, already present,
nutrients  for  plant  growths.    Phosphorus   is   usually
described, for this reasons, as a "limiting factor."

When  a  plant  population  is  stimulated in production and
attains a nuisance status,  a  large  number  of  associated
liabilities  are immediately apparent.  Dense populations of
pond weeds  make  swimming  dangerous.   Boating  and  water
skiing  and  sometimes  fishing may be eliminated because of
the mass of vegetation that serves as an physical impediment
to such activities.  Plant populations have been  associated
with  stunted fish populations and with poor fishing.  Plant
nuisances emit vile stenches, impart  tastes  and  odors  to
water  supplies,  reduce  the  efficiency  of industrial and
municipal water treatment, impair aesthetic  beauty,  reduce
or  restrict resort trade, lower waterfront property values.
                             214

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cause skin rashes to man during water contact, and serve  as
a desired substrate and breeding ground for flies.

Phosphorus  in the elemental form is particularly toxic, and
subject to bioaccumulation in much the same way as  mercury.
Colloidal  elemental  phosphorus  will  poison  marine  fish
(causing skin tissue breakdown  and  discoloration).   Also,
phosphorus   is  capable  of  being  concentrated  and  will
accumulate in organs and  soft  tissues.   Experiments  have
shown  that  marine  fish  will  concentrate phosphorus from
water containing as little as 1 ug/1.

Total Suspended Solids

Suspended  solids  include  both   organic   and   inorganic
materials.  The inorganic components include sand, silt, and
clay.   The  organic  fraction  includes  such  materials as
grease, oil, tar, animal and vegetable fats, various fibers,
sawdust, hair, and various  materials  from  sewers.   These
solids  may settle out rapidly and bottom deposits are often
a mixture  of  both  organic  and  inorganic  solids.   They
adversely  affect  fisheries  by  covering the bottom of the
stream or lake with a blanket of material that destroys  the
fish-food  bottom  fauna  or  the  spawning  ground of fish.
Deposits containing organic  materials  may  deplete  bottom
oxygen   supplies   and  produce  hydrogen  sulfide,  carbon
dioxide, methane, and other noxious gases.

In raw water sources for domestic use,  state  and  regional
agencies  generally specify that suspended solids in streams
shall not be  present  in  sufficient  concentration  to  be
objectionable   or   to   interfere  with  normal  treatment
processes.  Suspended solids in  water  may  interfere  with
many  industrial processes, and cause foaming in boilers, or
encrustations on equipment exposed to water,  especially  as
the  temperature rises.  Suspended solids are undesirable in
water for textile industries;  paper  and  pulp;  beverages;
dairy  products;  laundries;  dyeing;  photography;  cooling
systems, and power plants.  Suspended particles  also  serve
as a transport mechanism for pesticides, and other substances
which are readily sorbed into or onto clay particles.

Solids may be suspended in water for a time, and then settle
to  the  bed of the stream or lake.  These settleable solids
discharged  with  man's  wastes   may   be   inert,   slowly
biodegradable materials, or rapidly decomposable substances.
While  in  suspension,  they  increase  the turbidity of the
water,   reduce   light   penetration   and    impair    the
photosynthetic activity of aquatic plants.
                              215

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Solids  in  suspension  are aesthetically displeasing.   When
they settle to form sludge deposits on the  stream  or  lake
bed, they are often much more damaging to the life in water,
and  they  retain  the  capacity  to  displease  the senses.
Solids, when  transformed  to  sludge  deposits,  may  do  a
variety  of damaging things, including blanketing the stream
or lake bed and thereby destroying  the  living  spaces  for
those  benthic  organisms  that  would  otherwise occupy the
habitat.  When of  an  organic  and  therefore  decomposable
nature,  solids use a portion or all of the dissolved oxygen
available in the area.  Organic materials also  serve  as  a
seemingly  inexhaustible  fcod  source  for  sludgeworms and
associated organisms.

Turbidity is principally a measure of  the  light  absorbing
properties  of suspended solids.  It is frequently used as a
substitute method of quickly estimating the total  suspended
solids when the concentration is relatively low.


Zinc-Total

Occurring  abundantly  in  rocks  and  ores, zinc is readily
refined into a stable pure metal and is used extensively for
galvanizing, in alloys, for electrical purposes, in printing
plates, for dye-manufacture and for  dyeing  processes,  and
for  many other industrial purposes.  Zinc salts are used in
paint   pigments,    cosmetics,    Pharmaceuticals,    dyes,
insecticides,  and  other  products  too  numerous  to  list
herein.  Many of these salts (e.g., zinc chloride  and  zinc
sulfate)  are  highly  soluble  in  water; hence it is to be
expected that zinc might occur in  many  industrial  wastes.
On  the  other  hand,  some zinc salts (zinc carbonate, zinc
oxide, zinc sulfide) are insoluble in water and consequently
it is to be expected that some zinc will precipitate and  be
removed readily in most natural waters.

In  zinc-mining  areas,  zinc  has  been  found in waters in
concentrations as high as 50  mg/1  and  in  effluents  from
metal-plating  works and small-arms ammunition plants it may
occur in significant concentrations.  In  most  surface  and
ground  waters,  it is present only in trace amounts.  There
is some evidence that zinc ions are  adsorbed  strongly  and
permanently on silt, resulting in inactivation of the zinc.

Concentrations of zinc in excess of 5 mg/1 in raw water used
for drinking water supplies cause an undesirable taste which
persists  through  conventional treatment.  Zinc can have an
adverse effect on man and animals at high concentrations.
                             216

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In soft water, concentrations of zinc ranging  from  0.1  to
1.0  mg/1  have been reported to be lethal to fish.  Zinc is
thought to exert  its  toxic  action  by  forming  insoluble
compounds  with  the mucous that covers the gills, by damage
to the gill epithelium, or possibly by acting as an internal
poison.   The  sensitivity  of  fish  to  zinc  varies  with
species, age and condition, as well as with the physical and
chemical characteristics of the water.  Some acclimatization
to  the  presence  of  zinc  is  possible.  It has also been
observed that the effects of zinc poisoning may  not  become
apparent  immediately,  so  that  fish  removed  from  zinc-
contaminated to zinc-free water (after 4-6 hours of exposure
to zinc) may die U8 hours later.  The presence of copper  in
water   may   increase  the  toxicity  of  zinc  to  aquatic
organisms, but the  presence  of  calcium  or  hardness  may
decrease the relative toxicity.

Observed values for the distribution of zinc in ocean waters
vary  widely.   The  major  concern  with  zinc compounds in
marine waters is not one of acute toxicity,  but  rather  of
the  long-term  sub-lethal effects of the metallic compounds
and complexes.   From  an  acute  toxicity  point  of  view,
invertebrate  marine  animals  seem to be the most sensitive
organisms  tested.   The  growth  of  the  sea  urchin,  for
example, has been retarded by as little as 30 ug/1 of zinc.

Zinc  sulfate  has  also  been  found  to  be lethal to many
plants, and it could impair agricultural uses.
                              217

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                           PART A

                      CHEMICAL WASTES

                        SECTION VII

              CONTROL AND TREATMENT TECHNOLOGY
General Methodology

Curry371 presents a general methodology for  metallic  waste
treatment.   Some  of  the  principles  are also applicable,
however, to other types of wastes.   The  following  outline
conveys,  with some modifications, the general principles of
Curry's work:

    I.   Omit flows with  a  pollutant  concentration  lower
         than  the  concentration  in  equilibrium  with the
         precipitate formed

    II.  Reduce the waste water volumes requiring treatment

    III. Minimize the solubility cf the pollutant

         A.   Eliminate   compounds   that   form    soluble
              complexes

         B.   Reduce concentration of interfering ions  that
              increase pollutants solubilities

         C.   Maintain  conditions   that   minimize   total
              solubility

    IV.  Control conditions to increase  the  proportion  of
         the  pollutants  in the ionic form required for its
         precipitation or adsorbent reaction

    V.   Avoid conditions that will form harmful amounts  of
         gases during treatment

    VI.  Select  a  process  that  will  give   the   lowest
         practicable  or  economically achievable amounts of
         pollutants in the effluent, up to and including  no
         discharge of pollutants

    VII. Select a process that produces a sludge that can be
         disposed  of  in  accordance   with   environmental
         considerations.
                          219

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Pollutant-Specific Treatment Technology

Applicable  control  and  treatment  technology  relevant to
specific pollutants is discussed in the J.W.  Patterson,  et
al,  report  "Wastewater  Treatment Technology".208 Based on
the data of that report and  other  sources,  the  following
information   is   given   on  pollutant-specific  treatment
technology.

Aluminum

Precipitates as the hydroxide  at  pH  5.5-7.371,  *62   The
minimum  solubility is at pH 6.0.  Some halides may increase
the solubility of aluminum  by  complexation  reactions  and
thus change the conditions.**«

Ammonia

Ammonia  can  be removed from waste waters by stripping with
steam or  air.   Steam  stripping  systems  are  capable  of
achieving  effluent  ammonia  concentrations of from 5 to 30
mg/1.  Cooling towers could be considered as  air  strippers
of  ammonia  from contaminated waters.  However, the reverse
effect can occur, i.e. air-borne ammonia is absorbed.375

Antimony

Solubility data indicates a potential removal  of  about  90
percent by lime coagulation treatment.18

Arsenic

Treatment  processes  employed involve coagulation at pH 6.0
to produce ferric hydroxide floe to tie up the  arsenic  and
carry  it  from  solution.   This  process  has consistently
yielded arsenic levels of 0.05 mg/1 or less.

Barium

Precipitation as barium sulfate after addition of ferric  or
sodium sulfate at pH 6.0 yields effluent levels of 0.03-0.27
mg/1.

Beryllium

No  information  was  found concerning treatment methods for
the removal  of  beryllium  from  industrial  waste  waters.
However,  precipitation  of  insoluble sulfate, carbonate or
hydroxide may be possible.
                        220

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Boron

No  practicable  treatment  is   reported.    Borate-nitrate
corrosion  inhibition treatment is used in closed-loop house
service water systems.  Boron  from  this  source  could  be
reduced by minimizing the use of boron-containing chemicals.
However,  some  boron  chemicals  could  discharge  from ash
sluicing operations as a result of boron content in raw coal
used for firing.

Cadmium

Cadmium precipitates as the hydroxide at elevated  pH.   Its
solubility  at  pH  10  is  0.1  mg/1.  The presence of iron
hydroxide can enhance removal due to co-precipitation  with,
or  adsorption  on  the iron floe.  Complexing agents in the
waste stream can reduce the effectiveness  of  precipitative
removal.

Calcium

The   lime-soda  process  precipitates  calcium  as  calcium
carbonate.

Chlorine Residuals

An end-of-pipe treatment for reducing chlorine levels is the
addition  of  reducing  agents  such  as  sodium   bisulfite
(NaHS03).   Chlorine  being  an oxidizing agent will oxidize
these chemicals.  Dechlorinaticn  with  sulfur  dioxide  has
been  practiced  for  many years in water treatment 43° and,
more recently, on wastewater.431 Sulfur dioxide  is  favored
for  its  low  cost  and  ease  of  handling.   It is fed by
equipment identical to that used  in  chlorination  systems.
The   reaction   in   dechlorination  is  instantenous,  the
resulting products being chloride  and  sulfate  ions.   The
theoretical  requirements  is 0.9 mg/1 of sulfur dioxide per
mg/1 of residual chlorine  (not  chlorine  dosage).   Actual
practice  indicates the requirement to be nearer 1:1.  It is
equally effective for combined or free residual.418 One mole
of bisulfite is required per mole of chlorine or  1.47  mg/1
per mg/1 of chlorine.  By maintaining a 10% excess of sodium
bisulfite   in   the   discharge  stream,  chlorine  can  be
eliminated.  However, the excess sodium sulfite  creates  an
oxygen  demand,  thus substituting one pollutant problem for
another.
                           221

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Chromium

The most common  method  of  chromium  removal  is  chemical
reduction  of  hexavalent  chromium to the trivalent ion and
subsequent chemical precipitation.  The  standard  reduction
technique  is  to lower the waste stream pH to 3 or below by
addition of sulfuric acid, and to add sulfur dioxide, sodium
bisulfite  (or metabisulfite  or  hydrosulfite),  or  ferrous
sulfate  as  reducing  agent.   Trivalent  chromium  is then
removed by precipitation with lime at pH 8.5-9.5.

The residual of hexavalent chromium after the reduction step
depends on the pH, retention time, and the concentration and
type of reducin.g agent  employed.   The  following  effluent
levels are reported for treatment of industrial wastes:

    metal finishing wastes,
      using sulfure dioxide -------- 1 mg/1
    metal finishing wastes,
      using sulfur dioxide --------  "zero"
    wood preserving wastes,
      using sulfur dioxide --------  0.1 mg/1
    electroplating wastes,
      using sodium bisulfite -------  0.7-1.0 mg/1
    cooling tower blowdown,
      using metabisulfite ------ below 0.5 mg/1
    cooling tower blowdcwn,
      using metabisulfite --------- 0.025-0.05 mg/1
    metal plating wastes,
      using metabisulfite --------- o.l mg/1 or less
    chrome plating wastes,
      using metabisulfite --------- 0.05-0.1 mg/1

Ion   exchange  treatment  of  metal  finishing  wastes  has
successfully met chrome effluent standards equivalent  to  a
hexavalent chromium concentration of 0.023 mg/1.

The   solubility   of   trivalent   chromium  is  less  than
approximately 0.1 mg/1 in  the  pH  range  8-9.5.   Effluent
levels,  after precipitation of industrial wastes with lime,
are reported as follows:

    electroplating wastes,
      using coagulant aid -------------  0.06 mg/1
    metal finishing wastes,
      using settling ------------- below 3 mg/1
    wood preserving wastes,
      using settling ---------------- o.02 mg/1
    metal finishing wastes,
      using an anionic polyelectrolyte ------- 0.75 mg/1
                           222

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Ion  exchange  removal  can  effect  complete   removal   of
trivalent chromium.

The  U.S.  Atomic  Energy  Commission reports total chrornate
effluents of 0.1-0.2 mg/1 after either chemical treatment or
ion exchange.372"373

Cobalt

No information was found concerning  treatment  methods  for
the removal of cobalt from industrial waste waters.

Copper

Effluent  concentrations  of  0.5  mg/1  can be consistently
achieved by precipitation  with  lime  employing  proper  pH
control  and  proper  settler  design  and  operation.   The
maximum solubility of the metal hydroxide is in the range pH
8.5-9.5.  In a powerplant, copper can appear  in  the  waste
water effluent as a result of corrosion of copper-containing
components   of   the  necessary  plant  hydraulic  systems.
Normally, every practicable effort is made,  as  a  part  of
standard design and operating practices, to reduce corrosion
of  plant  components.  However, copper is not used in once-
through  boilers  and,  consequently,  is   not   found   in
corresponding   spent   cleaning   solutions.    Excessively
stringent effluent limitations  on  copper  may  necessitate
complete  redesign  and  alteration of condenser cooling and
other systems.  The following effluent levels of copper  are
reported  for  full-scale  treatment of industrial wastes by
lime precipitation  followed  by  sedimentation  (except  as
noted):

    metal processing wastes --------0.5 mg/1
    metal processing wastes -------- 0.2-2.5 mg/1
    metal processing wastes, using
      sand filtration -- 	 - 	 - 	 - 0.2-0.5 mg/1
    metal fabrication wastes,
      using coagulant -----------2.2 mg/1
    metal finishing wastes ------ avg. 0.2 mg/1
    metal mill wastes ----------- 1-2 mg/1
    wood preserving wastes --------  0.1-O.U mg/1

A   significant   problem   in   achieving  a  low  residual
concentration of copper can result if complexing agents  are
present, especially cyanide and ammonia.
                            223

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Iron

In general, acidic and/or anaerobic conditions are necessary
for  appreciable  concentrations  of  soluble iron to exist.
"Complete11 iron removal with lime  addition,  aeration,  and
settling  followed  by  sand  filtration  has been reported.
Existing technology is capable of soluble iron  removals  to
levels well below 0.3 mg/1.  Failure to achieve these levels
would  be  the  result  of improper pH control.  The minimum
solubility of ferric hydroxide is at pH 7.  In  some  cases,
apparently  soluble  iron  may actually be present as finely
divided  solids  due  to  inefficient  settling  of   ferric
hydroxide.   Polishing  treatment such as rapid sand filters
will remove these solids.  In a powerplant,  iron,  as  with
copper,  can  appear in the waste water effluent as a result
of corrosion to iron-containing components of the  necessary
plant hydraulic systems.  Normally, every practicable effort
is  made,  as  a  part  of  standard  design  and  operating
procedures,  to  reduce  corrosion  of   plant   components.
Excessively  stringent effluent limitations on iron, as with
copper, may necessitate complete redesign and alteration  of
condenser cooling and other systems.

Lead

Precipitation  by  lime and sedimentation has been reported.
Little data is available on effluent lead  after  treatment;
however,   the   extreme   insolubility  of  lead  hydroxide
indicates that good conversion of soluble lead to  insoluble
lead can be achieved, with subsequent removal by settling or
filtration.

Magnesium

The   lime-soda   process   precipitates  magnesium  as  the
hydroxide.

Manganese

Precipitates  upon  lime  addition.   Significant   removals
during water treatment are achieved at pH 9.4 and above.

Molybdenum

No  information  was  found concerning treatment methods for
the removal of  molybdenum  from  industrial  waste  waters.
However,   precipitation  as  chloride  or  sulfide  may  be
possible.
                         224

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Mercury

General treatment methods  exist  which  are  applicable  to
mercury-bearing  waste  streams.   One  of  the most common,
simplest, and most effective methods to remove mercury  from
solution  is precipitation of an insoluble mercury compound.
Sodium sulfide (Na2S) and sodium  hydro-sulfide  (NaHS)   are
effective  in  forming  the  extremely  insoluble HgS.  This
method is not favored, however, when recovery of mercury  is
desired,  since  offensive  and  poisonous  hydrogen sulfide
(H2S) gas is formed in the reduction  process.   By  keeping
the  pH  about  10  the  H2S  problem  can  be avoided while
enhancing   the    production    of    sulfide    ion    for
precipitation.462  Other  methods  include  filtration  with
adsorptive compounds  such  as  activated  carbon,  graphite
powder  and  powdered  zinc,  chemical flocculation, and ion
exchange.

Nickel

Nickel forms insoluble nickel  hydroxide  upon  addition  of
lime.   Little  efficiency is gained above a pH of 10, where
the minimum theoretical solubility is 0.01 mg/1.  Removal by
adsorption  on  an  iron  or  manganese  hydroxide  floe  is
possible.*«2

Oil and Grease

Flotation  is  efficient  in  removing  emulsified  oil  and
requires minimum space.  It can  be  used  without  chemical
addition,   but  demulsifiers  and  coagulants  can  improve
performance  in  some  cases.   Whenever  possible,  primary
separation  facilities should be employed to remove free oil
and solids before  the  water  enters  the  flotation  unit.
Multi-stage  units  are  more  effective  than  single-stage
units..  Partial-recycle units are more effective than  full-
pressure  units.   Oil  removal facilities including single-
cell flotation can achieve effluent oil  and  grease  levels
from  10-20  mg/1,  while multi-stage units can achieve 2-10
mg/1.  Reference 398 gives data  on oil  and  grease  levels
attained  by  a number of petroleum refineries using primary
gravity separation, flotation  (with and without  chemicals),
chemical  flotation, and filtration.  Reference 399 presents
data on oil and grease  levels  achieved  by  dissolved  air
flotation.  Levels ranging from 2-20 mg/1 were indicated.

Total Phosphorus(as P)

Phosphorus  concentrations  of  less  than  0.1  mg/1 can be
routinely obtained using two-stage lime clarification at  pH
11,  followed by multi-media pressure filters.  Single-stage
lime clarification at pH 9-11 with cr without filtration can
                        225

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achieve phosphorus concentrations of 2 mg/1 or less.  Figure
A-VII-1 shows the effect of pH on  phosphorus  concentration
of effluent after filtration.  The average concentration for
a  clarifier  pH  of  9.5,  and prior to filtration was 0.75
mg/1.37* Precipitation using ferric or  aluminum  salts  has
been used.*62

Potassium

No  information  was  found concerning treatment methods for
the removal of potassium from industrial waste waters.

Polychlorinated Biphenyls (PCBs)

PCBs are commonly used as coolants  in  large  transformers.
Special care should be taken to prevent leaks and spills and
to  contain  possible  spills  of  these  fluids in order to
prevent their discharge to water bodies.

Selenium

Under conditions of  moderate  reduction,  selenium  may  be
removed   from   solution  by  reduction  to  the  insoluble
elemental form.*62

Silver

Precipitation with chloride ion can  remove  silver  to  the
mg/1  level.   However,  co-precipitation  with  other metal
hydroxides under alkaline conditions improves silver removal
to less than 0.1 mg/1.

Sodium

No information was found concerning  treatment  methods  for
the removal of sodium from industrial waste waters.

Sulfate

Use  of  lime  (calcium  carbonate)  in  place  of  dolomite
(mixture of calcium carbonate and  magnesium  carbonate)   in
lime   treatment  will  minimize  the  presence  of  soluble
sulfates,  due  to  insolubility  of  calcium  sulfate   and
solubility of magnesium sulfate.

Thallium

No  information  was  found concerning treatment methods for
the  removal  of  thallium  from  industrial  waste  waters.
                          226

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  2.0
  3.5
ca
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a
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o
C£
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CL.

O

a.
  0.5
••  .^r-t
                      00 «•"
                                   e
                                   T*-
                                   *
    B.5
             9.0
   .J ______ ! __ ;
    9.5      10.0

        CLARIFIER pH
                                       10.5
                                                 11.0
11.5
                           Figure  A-VII-1

             Effect of  pH on Phosphorus  Concentration

             of Effluent  from Filters Following
                             374
             Lime Clarifier
                         227

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However,  the  trivalent  hydroxide  is insoluble and may be
removed by lime addition.

Tin

No information was found concerning  treatment  methods  for
the  removal  of tin from industrial waste waters.  However,
precipitation as hydroxide or sulfite may occur.

Titanium

No information was found concerning  treatment  methods  for
the removal of titanium from industrial waste water.

Total Dissolved Solids

Removal of total dissolved solids (TDS) from waste waters is
one of the more difficult and more expensive waste treatment
procedures.   Where  TDS result from heavy metal or hardness
ions, reduction can be achieved  by  chemical  precipitation
methods;  however,  where  dissolved  solids  are present as
sodium, calcium, or potassium compounds, then TDS  reduction
requires   more   specialized  treatment,  such  as  reverse
osmosis, electrodialysis, distillation, and ion exchange.

Total Suspended Solids

Suspended solids removal can be  achieved  by  sedimentation
and   filtration   operations   employing,  in  some  cases,
flocculaticn-coagulation technology to improve  the  clarity
of the effluent or to speed up the process.

Vanadium

No  information  was  found concerning treatment methods for
the  removal  of  vanadium  from  industrial  waste  waters.
However,  precipitation  as  the  insoluble  hydroxides  may
occur.   However,  vanadium  recovery  operations  discussed
elsewhere   in  this  section  may  include  technology  for
preventing vanadium from  dissolving,  thus  increasing  the
amount in the reclaimable solid.

Zinc

Lime  addition for pH adjustment can result in precipitation
of zinc hydroxide.  Operational data  indicate  that  levels
below   1   mg/1  zinc  are  readily  obtainable  with  lime
precipitation.  The use of zinc can be minimized since other
treatment chemicals are available  to  reduce  corrosion  in
closed   cooling-water   cycle.   Zinc  removals  have  been
                         228

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reported for a range of industrial systems  and,   generally,
treatment  is  not  for  zinc  alone.   Lime  addition  with
hydroxide precipitation followed by sedimentation (except as
indicated)  has yielded the following effluent zinc levels:

    plating wastes ------------  0.2-0.5 mg/1
    plating wastes ------------  2 mg/1
    plating wastes, using
      sand filtration -----------0.6 mg/1
    plating wastes ------------  less than 1 mg/1
    fiber manufacturing wastes ------  less than 1 mg/1
    tableware manufacturing wastes,
      using sand filtration -------- 0.02-0.23 mg/1
    fiber manufacturing wastes ------  0.9-1.5 mg/1
    fiber manufacturing wastes ------  1 mg/1
    metal fabrication wastes -------  0.5-1.2 mg/1
    metal fabrication wastes, using
      sand filtration ----------- 0.1-0.5 mg/1

Combined Chemical Treatment

Precipitat ion

The effluent levels of metal  ions  attainable  by  combined
chemical  treatment  depend  upon  the insolubility of metal
hydroxides in the treated water  and  upon  the  ability  to
mechanically   separate  the  hydroxides  from  the  process
stream.  Reference 379 presents data on the solubilities and
other aspects of chemical treatment for the removal of metal
ions from waste waters.   The  theoretical  solubilities  of
copper,  nickel,  chromium,  zinc,  silver,  lead,  cadmium,
tellurium and ferric and ferrous iron as a  function  of  pH
are  shown  in  Figures  A-VII-2,  3.   At  a  pH of 9.5 the
solubility of copper, zinc, chrcmium, nickel and iron is  of
the order of 0.1 mg/1, or less.  Experimental values plotted
in  Figures  A-VII-U,  5  vary somewhat from the theoretical
values.  Nevertheless, the need for fairly close pH  control
in  order to avoid high concentrations of dissolved metal in
the effluent is evident.  A pH of 8.5 to  9.0  is  best  for
minimizing  the solubility of copper, chromium and zinc, but
a pH of 10.0 is optimum for  minimizing  the  solubility  of
nickel  and  iron.   To limit the solubility of all of these
metals in a mixed solution, an intermediate pH  level  would
be selected.

A  further  aspect  related  to  solubility  is the time for
reaction.  Figure A-VII-6 shows the change  in  solubilities
of  zinc,  cadmium,  copper and nickel with time for various
levels of pH.
                         229

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     io cr
    i.o
    O.I
XI

"o
in
    0.01
   OOOI
              7
                                      10
II
12
                          Solution, pH
                    Figure  A-VII-2


         SOLUBILITY OF COPPER,  NICKEL,

         AND ZINC AS A FUNCTION OF pH
                         230

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      0>
      9?  O.I
      .0
      _3

      O
       0.0001
         O.Of
        0.001
Figure A-VII-3     THEORETICAL SOLUBILITIES OF METAL IONS
                    AS A FUNCTION OF pH
                           231

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0.
                                                           Legend

                                                         O Nickel
                                                         D Chromium
                                                         X Zinc
                                                         A Copper
                                                 Note: Values plotted as O.I mg/i
                                                      were reported as zero.The
                                                      O.lmg/jt value is assumed
                                                      to be the detectable limit.
                                 8      9       10      II
                                  Solution , pH
12
13
14
                         Figure A-VII-4

     EXPERIMENTAL VALUES - SOLUBILITY OF METAL IONS AS
     A FUNCTION OF pH
                           379
                                232

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    0.01
                      7      8       9       10
                        pH (After 2-hr Standing)
Figure A-VII-5 EXPERIMENTALLY DETERMINED SOLUBILITIES
                OF METAL IONS AS A FUNCTION OF pH

                     Reference No0  236

                        233

-------
ou
70
60
/
u 20 n
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— pH =
T~\ \ III I
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- pH =
	 pH =
7- \ 1 1 1 1 1
7.5
1 ,
,
8.0
8.5
1 J
* i.e'
o
w 1.2
S;0.8
E0.4
0
pH =
^_ pH =

9,0
9.5
10.-
1 1 1 1 1 1 1
        0  1234  567   8

         Standing  time,  hours


                 ZINC


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1UU
80
60


20'
10
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pH = 8
—
.5
^~ pH = 9.0
L_ I 1 1 1 1 I
.
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—
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,
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— ^_-- • 	 ' ' pH = 10.i
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._ .1 	 1 J I.I 1 .
' .

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                                     Standing time,  hours


                                           CADMIUM
	|	
   04
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   o

   o
   o
   (O
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   e
 16

 14


 12

 10


  8J



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2.0

1.6


1.2

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     0.4

       0
           I  I
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      I   I   I   I
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 8

 4
                                                          = 9.0
                                                          =9.5
                                               I   I  I   I   I   I  „
                                    01234
                                                          678
                                          Standing time, hours

                                                NICKEL
        012345678



         Standing  time,  hours

              COPPER


 Values  for  pH  =  8.0 are_ 0_._2     _  _ 	 _  	  __   _ _   ___


Figure A-VII- 6' CHANGE IN THE  SOLUBILITIES OF ZINC,  CADMIUM, COPPER, AND

                AND NICKEL PRECIPITATES  (PRODUCED WIT!! LIME

                ADDITIONS) AT-  A FUNCTION'  OF  STANDING TIME AMD
                pH VALUE. Reference  No. 236.
                              234

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The theoretical and experimental results do not always agree
well with results obtained in practice.  Concentrations  can
be  obtained  that  are  lower  than  the above experimental
values., often at pH values that are not optimum on the basis
of the above considerations.   Effects  of  co-precipitation
and  adsorption  on  the flocculating agents added to aid in
settling the precipitate play a significant role in reducing
the concentration of the metal ions.  Dissolved solids  made
up  of  noncommon  ions  can  increase the solubility of the
metal hydroxides according to the Debye-Huckel Theory.  In a
treated solution from a typical electroplating plant*  which
contained  230  mg/1  of  sodium  sulfate  and 1,060 mg/1 of
sodium chloride, the concentration of nickel was 1.63  times
its  theoretical'  solubility in pure water.  Therefore, salt
concentrations up to  approximately  1,000  ppm  should  not
increase the solubility more than 100 percent as compared.to
the  solubility  in  pure  water.  However, dissolved solids
concentrations of several thousand ppm could have  a  marked
effect upon the solubility of the hydroxide.

When   solubilizing   complexing  agents  are  present,  the
equilibrium constant of the complexing reaction  has  to  be
taken  into  account  in  determining theoretical solubility
with  the  result  that  the  solubility  of  the  metal  is
generally   increased.    Complexing  agents  such  as  EDTA
(ethylene-diamine-tetraacetic  acid) ,  could  .have   serious
consequences   upon   the   removal   of   metal   ions   by
precipitation.

Superposed on the situation  presented  above  for  chemical
treatment  for  the  removal  of  iron, copper, chromium and
nickel could be requirements  for  removal  of  other  heavy
metals  and  phosphorus.  Phosphorus effluents of 2 mg/1 are
achievable with or without filtration at pH 9-11, therefore,
no problem of phosphorus removal is anticipated at pH values
which are optimum for the removal of iron, copper,  chromium
and  nickel.   Reference  380 presents minimum pH values for
complete (effluent generally 1 mg/1) precipitation of  metal
ions  as  hydroxides as follows: Sn*«(pH 4.2), Fe+3 (pH 4.3),
A1+'(PH 5.2), Pb+2(pH  6.3),  Cu*« (pH  7.2),  Zn+« (pH  8.4),
Ni+2(pH  9.3),  Fe*2(9.5),  Cd+* (pH 9.7)r, Mn+* (pH 10.6).  In
the case of amphoteric metals such  as  aluminum  and  zinc,
resolubilization  will  occur  if  the  solution becomes too
alkaline.     .           .

Alkali Selection

Several alkaline materials are available for use in chemical
treatment, e.g.  lime,  hydrated  lime,  limestone,  caustic
soda,  soda  ash.   The  choice  among  these  may depend on
                          235

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availability,  cost,  desired  effluent  quality,  ease   of
handling, reactivity, or characteristics of sludge produced.
A  comparison  of these materials is given in Table A-VTI-1.
When cost  and  effluent  quality  are  the  most  important
factors, lime, hydrated lime and limestone would be the more
commonly used alkalis.

Lime  is readily available and relatively simple to use.  In
acid (coal)  mine  drainage  applications,  it  consistently
neutralizes  the  acidity  and  removes  the  iron and other
metals present in mine drainage at a reasonable cost, if not
the least cost.  For these reasons, lime is used in most  of
the  estimated  300  plants that treat mine drainage.380 The
relative disadvantages of  lime  are:  an  increase  in  the
hardness  of  the  treated water, problems of scale (gypsum)
formation  on  plant  equipment,  and  the  difficulties  in
dewatering  or  disposal  of  the  sludge  volumes produced.
There are four basic steps in lime treatment.  First,  waste
waters  are  neutralized  by  addition of slurried lime with
vigorous mixing for 1-2 minutes.  Aeration is  provided  for
15-30  minutes  to oxidize ferrous iron to the ferric state.
Solids  separation  is   provided   in   either   mechanical
clarifiers,  or  large earthen settling basins.  The treated
water is discharged and the sludge is disposed of.   Capital
costs  range  from about $40/cu m processed/day for a 40,000
cu m/day process to about $100/cu m/day for a 2,000 cu m/day
process to about $1,000/cu m/day for a 400 cu m/day  process
for  treatment  of acid mine drainage.  Operating costs vary
from 3 to 12 cents per 1,000  cu  m   (11  to  45  cents  per
million  gallons)   per  mg/1 of acidity but are generally in
the  range  4  to  7  cents/1,000  cu  m/mg/1  (15   to   27
cents/million gallons/mg/1) . 38<> sludge disposal costs can be
as much as 50 percent of the total operating costs.

Limestone has several advantages over other alkaline agents.
The  sludge  produced  settles  more  rapidly and occupies a
smaller volume.  The pH of the treatment is not so sensitive
to feed rate.  Limestone is easier to handle than the  other
alkaline  materials.   Disadvantages  center around its slow
reactivity which requires larger detention times and  larger
treatment  vessels.   As  a  result of its disadvantages few
actual operating systems have been installed.

Aeration

The  oxidation  of  ferrous  iron  to  ferric  iron  can  be
accomplished  by  either  diffused  or  mechanical  aeration
equipment.  Capital costs range from about $2,000 for a  100
cu  m  flow/day  process  to about $50,000 for a 10,000 cu m
                         236

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                                      Table A-VII-1
             COMPARISON OF ALKALINE AGENTS FOR CHEMICAL TREATMENT
                                                         380
               Agent
                                               Cost, $/ unit of CaCO   equiv,
ro
to
Limestone, Rock  (calcium carbonate)
Limestone, Dust  (calcium carbonate)
Quick Lime (calcium oxide)
Hydrated Lime  (calcium hydroxide)
Magnesite (magnesium carbonate)
Soda Ash (sodium carbonate, 50%)
Dolomite (calcium-magnesium carbonate)
Ammonium Hydroxide
Caustic Soda  (sodium hydroxide,50%)
 8.82
11.02
14.19
20.40
23.24
42.08
47.70
50.14
67.02

-------
flow/day process.  Operating  costs  will  vary  from  10-20
percent of the total plant operating costs.3a«

Solids Separation

The  first  step  in  separating  the precipitated metals is
settling, which is very slow for gellike zinc hydroxide, but
accelerated  by  co-precipitation  with  the  hydroxides  of
copper  and  chromium.   Coagulation  can  also  be aided by
adding metal ions such as ferric  iron  which  forms  ferric
hydroxide and absorbs some of the other hydroxide, forming a
floe  that  will settle.  Ferric iron has been used for this
purpose in sewage treatment for many years as  has  aluminum
sulfate.    Ferric  chloride  is  frequently  added  to  the
clarifier of  chemical  waste-treatment  plants  in  plating
installations.    Flocculaticn   and  settling  are  further
improved  by  use  of  polyelectrolytes,  which   are   high
molecular weight polymers containing several ionizable ions.
Due to their ionic character they are capable of swelling in
water  and  adsorbing  the  metal hydroxide which they carry
down during settling.

Settling is accomplished in the batch process in  mechanical
clarifier  or  a  stagnant tank, and after a time the sludge
may be emptied through the bottom  and  the  clear  effluent
drawn  off  through  the side or top.  The continuous system
uses a baffled tank such that the stream flows first to  the
bottom  but  rises with a decreasing vertical velocity until
the floe can settle in a practically stagnant fluid.

Although the design of  the  clarifiers  has  been  improved
through  many  years of experience, no settling technique or
clarifier is 100 percent effective;  some  of  the  floe  is
found  in the effluent - typically 10 to 20 mg/1.  This floe
could contain 2 to 10 mg/1 of metal.  Polishing  filters  or
sand   filters   can  be  used  on  the  effluent  following
clarification.  The general effectiveness of such  filtering
has not been ascertained.
Evaporation and Other Processes

Basic  processes,  in addition to evaporation ponds, include
multi-stage  flash   evaporation,   multi-effect   long-tube
(vertical)  evaporation,  and vapor compression evaporation.
The  multi-stage  flash   evaporation   process   has   been
considered  potentially  applicable  to  the  production  of
potable water from acid  mine  drainage.380  Major  problems
which  have  confronted  this  process  are  calcium sulfite
scaling and brine deposit.  The product water at 50 mg/1 TDS
                          238

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is suitable for recycle to almost all water  uses  in  steam
electric powerplants.

Vapor-compression evaporation systems are being offered on a
guaranteed  performance  basis  by  a company specialized in
their applications.  These systems can be  used  to  recover
and recycle most of the water contained in the typical blow-
down  from  recirculating process streams.  A schematic flow
diagram of a typical vapor-compression evaporation system is
shown in Figure A-VII-7.  The system works as follows:

The brine to be treated is initially fed into  a  feed  tank
for  a  5-to-10 minute residence during acid treatment.  The
acidified feed is then pumped through a heat exchanger:   (1)
which  raises  the  temperature  of the incoming flow to the
boiling  point.   After   the   water   passes   through   a
noncondensible  gas  scrubber  (2), it enters the evaporator
sump (3).  Brine from the sump is pumped to the top  of  the
heat-transfer  tubes  (H), where it is released to fall as a
film inside of the tubes.  A portion of this falling film is
vaporized.  In a vapor-compression thermodynamic cycle,  the
vapor  is  then  compressed  (5)  and introduced to the shell
side of the tube bundle.  (6).  The temperature differential
between the vapor and the brine film  causes  the  vapor  to
condense  as  pure water  (7).  The concentraton brine slurry
is continuously  withdrawn   (8)  from  the  sump  for  final
dehydration in a solar pond, mechanical dryer, or separator.
The total energy consumption is in the range of 30 to HO Btu
per pound of feed water.


Membrane  processes are capable of acceptably high levels of
brine  concentration.   However,  flux-rate  reduction  with
increasing  brine  concentration,  and  membrane fouling are
problems  which  have  not  been  satisfactorily   overcome.
Insufficient   information   is   available   to  judge  the
performance, reliability, costs of membrane electrodiaiysis,
ion  exchange,  freezing,  electrochemical   oxidation    (of
ferrous  iron),  ozone  oxidization or any other process for
the treatment of steam electric powerplant waste waters.


Technology Specific to Powerplant Waste Waters  (General)

The control and treatment technology for  the  discharge  of
chemical  wastes  from  a steam electric powerplant involves
one or more combinations of the following techniques:

(1)  Elimination of pollutants by:
     a)  process modifications
                          239

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ro
-p»
o
             CONDENSATE
                                                                                           [    | COMPRESSED VAPOR
                                                                                                     WATER VAPOR
                       [   |  CONDENSATE
                                                                                             STEAM
                                                                                             COMPRESSOR
                                                                                            PRODUCT
                                                                                            WATER
                                                                                            PUMP
                                                                                        CONCENTRATED BRINE
            Figure A-VII-7     Brine Concentrator,  Resources Conservation  Co.
                                                                                          452

-------
     b)   material substitutions
     c)   good housekeeping practices
(2)  Control of waste streams by maximum reuse
     and conservation of water
(3)  Removal of pollutant from waste stream

The following is a summary,exerpted from reference  4<»4,   of
the principal methods of powerplant waste disposal which are
currently available:

    1.   Controlled  Release  to  a  Waterway.    A   common
practice  is  to  neutralize  the acid or alkaline waste and
release it via  the  circulating  water  discharge  so  that
dilution of 5,000 or 10,000: 1 is realized.

    2.   Collection of Spent Solvent in  a  Retention  Basin
for   Neutralization  and  Sedimentation  Before  Controlled
Release.  This method has the advantage at some  sites  that
acidic wastes can be reacted with alkaline wastes so that no
additional  chemicals  are  required for neutralization;  but
the  applicability  of  this  method  is  affected  by  site
characteristics such as availability of space and the nature
of other wastes generated at the site.

    3.   Impoundment on Company  Property.   Some  utilities
particularly in the Southwest impound their waste in lagoons
on  site.   These  lagoons  or  holding  basins are suitably
constructed so as to prevent the escape of the liquid by any
means other than evaporation.   This  method  is  of  course
possible   only   at  locations  where  sufficient  land  is
available and where climate conditions are suitable.

    3.   Off-Site Disposal.  In some cases  chemical  wastes
have  been  trucked  off-site to a commercial waste disposal
firm.  Costs range up to 12 cents per  gallon  depending  on
waste  compositions  and  distance.   Barging to deep sea is
another method which has been used by  utilities  along  the
coast.   This  method  is  costly  and  generally  cannot be
economically justified for volumes  under  200,000  gallons.
In  general, economic and environmental considerations limit
the usefulness of off-site disposal to special situations.

    5.   Solidification  of  Hastes.   Some  utilities  have
experimented  with  solidifying  the  spent  solvents.  This
entails engaging an outside  vendor  who  transports  a  van
equipped   with   solidifying   reagents,  pumps  and  other
paraphernalia; scheduling is important and costs range  from
5  to  17  cents  per gallon.  This method can be used where
solid disposal  is  possible  in  a  landfill  area,  gully,
abandoned  mine,  etc.   Final solid volume is about 5% more
                           241

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than starting volume of the  waste  due  to  the  solidfying
chemicals added.

    6.   Combustion or Incineration of Wastes.   Within  the
last  year or two, one utility has introduced a new means of
disposal of certain spent solvents.  A small number of  jobs
have not been performed by several utilities in which Vertan
675  or  the  ammoniated  citric  acid  from  the  CitroSolv
process, both at pH of 9.2 - 9.5, have been drained from the
boiler and combusted in an adjoining boiler.  The method has
been to spray the spent  solvent  into  the  furnace  of  an
operating  boiler  at  a  rate of 50-100 gallons per minute.
Interestingly, no deleterious  air  pollution  effects  have
been  associated with this procedure.  In fact there appears
to be some reduction in emissions  of  nitrogen  oxides  and
dulfur  dioxide.   It  is  questionable  whether this method
could be used on neutralized hydrochloric acid  or  ammonium
solutions.   There is a distinct possiblity that the halogen
ions could attack the austentite steel alloy  tubes  in  the
superheater and reheater.

In   order  to  select  and  implement  an  efficient  waste
management program, it is necessary to evaluate the  control
and  treatment  techniques corresponding to specific factors
applicable in each case.

In this section alternate control and  treatment  techniques
and  their  limitations are evaluated for different chemical
waste streams.  Advantages and disadvantages are  presented.
Based  on  the  reported  data,  industry-wide practices and
exemplary facilities are indicated.

Chemical wastes can be discussed  in  three  general  groups
(continuous   wastes,  periodic  wastes,  and  wastes  whose
characteristics are unrelated to the powerplant  operations)
even  though,  for  the purposes of guideline development, a
classification  by  volume  would   be   appropriate.    The
continuous  wastes  are  those  directly associated with the
continuous production of electrical  energy.   They  include
condenser cooling water discharge  (for once-through systems)
or  blowdcwn  (for  closed  systems),  water treatment plant
wastes, boiler or PWR steam generator  blowdown,  discharges
from  house  service water systems, laboratory, ash handling
systems, air pollution control devices,  and  floor  drains.
The  periodic wastes are those associated with the regularly
scheduled cleaning of major units of equipment, usually at a
time  of  plant  cr  unit  shutdown.   Those  include  spent
cleaning  solutions  from  the cleaning of the boiler or PWR
steam generator tubes, boiler fireside,  air  preheater  and
condenser  cooling system, and other miscellaneous equipment
                          242

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cleaning  wastes.   The  final  group  of  wastes   includes
drainage  from  coal  piles  of coal fueled plants,  drainage
from roof and yard drains, run-off from on-site construction
and sanitary wastes.  Control and  treatment  of  discharges
from  systems  involving  high-level or low-level rad wastes
are not known to be practicable due to the possible  adverse
affects which might arise from concentrating the radioactive
materials in the treatment operation.

Continuous Waste Streams

Cooling Water Systems

References  357,  387-389,  «»18  and  others are a source of
considerable information en control technology  for  cooling
water systems.

Maintaining condenser tubes or other heat exchange equipment
with  an  inherent new-tube cleanliness is most important to
keep the efficiency and economics  of  the  process  at  its
designed  level.  The cost penalty of tube fouling increases
porportionately as the cleanliness decreases.  If allowed to
continue, an unscheduled outage may be rquired to clean  the
tubes,  thereby  losing  production  and further compounding
additional  costs.   The  objective  is  to   maintain   the
cleanliness  factor  at  an  acceptable level by one or more
methods that can be:

1.  Continuous and complete  chemical  conditioning  of  the
cooling system while operating

2.  Chemical cleaning of the heat  exchanger  tubes  at  the
scheduled outage

3.  Mechanical cleaning of the tubes  while  operating  with
equipment  utilizing  either sponge rubber balls or brushes,
slightly over-sized to pass through the tubes

4.  Mechanical cleaning of the tubes at a scheduled otuage

5.  Mechanical cleaning as in Item 3 but  without  extensive
chemical conditioning as intended in Item 1.

To discuss methods of cleaning condenser systems might imply
that  condenser  tubes become fouled quite often either from
chemical or biological deposits or in combination.  In  some
instances this is true; there are electric generating plants
that  consider  it  necessary  to clean condenser tubes on a
weekly basis.  Others do so less frequently, such  as  semi-
annual ly  or  annually.   Yet  other  plants can operate and
                        243

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maintain the designed cleanliness factor without  having  to
clean tubes but once in 10 to 15 years.  For many plants the
elementary   difference  may  lie  in  the  attitude  toward
maintaining a proper quality program for the cleanliness  of
circulating   water   systems,   whether   once-through   or
recirculating incorporating a cooling tower.

Chemical Conditioning

Chemical Conditioning of Once-Through Systems

At those generating plants  where  once-through  cooling  is
used,  chemical  conditioning  of  the circulating water for
corrosion and scale control is never practiced.   The  costs
would  be  prohibitive considering the large volume of water
to be treated.  Mainly the only chemical needed is a biocide
to minimize fouling of the condenser tubes, tube sheets, and
water boxes by bacterial slime or other growths.   Generally
the  biocide  is  predissolved  chlorine gas, applied one or
more times a day over a  period  of  15  to  30  minutes  to
produce  a residual of about 1 mg/1 or more at the condenser
inlet.  Chlorine is the only biocide that has proved  to  be
effective and most economical at many plants.

Frequency,  dose,  and duration of the chlorination cycle is
variable, depending on water quality and temperature.   Four
30  minute  periods a day is not an unusual program.  Dosage
is  controlled  by  maintaining  a  residual  level  at  the
condenser  outlet  at  a  level  of  about  0.5  mg/1.  Time
interval between application and  sampling  may  be  in  the
range  of  20-30 seconds when chlorine is applied just ahead
of the condensers to 3-5 minutes when it is applied  at  the
intake.

Water quality  has a two-fold effect on this operation.  The
poorer  the  quality,  the  greater the chlorine demand thus
increasing dosage requirements.  The  food  supply  in  poor
quality  water  accelerates  the  growth of organisms in the
condenser   tubes   between   chlorination   programs   thus
increasing  the  duration  of  the chlorination cycle and/or
frequency to maintain  satisfactory  control.   The  popular
definition  of  the term "chlorine demand" is that it is the
defference between dose and residual.  To be of meaning,  it
must  be  properly  .expressed  in terms of type of residual,
temperature, pH, and time  of  contact  between  dosing  and
residual  measurement.   It  is  the time element that is so
frequently overlooked and which  poses  a  problem  in  very
short time-of-contact situations.
                         244

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Consider,  for instance, that demand figures tinder otherwise
identical conditons were  compared  for  30  seconds  vs  30
minutes  in water containing ammonia nitrogen.  Assuming 80%
of the 30 minute demand will  be satisfied in  the  first  5
minutes,  much  of  this  will  occur  in  the reaction with
hypochlorous  acid  before  the  formation  of  the   slower
reacting   chloramines.   When  this  occurs,  the  rate  of
satisfaction of the demand falls off rapidly.   When  demand
results  are based on the addition of preformed chloramines,
the difference is so drastic that  chlorine  demand  figures
require  the  added  dimension of type of available chlorine
being used.  Misunderstood by many is that ammonia does  not
constitute  chlorine  demand  until the ratio of chlorine to
ammonia exceeds approximately 10:1.

Further complicating this issue in the case of short contact
times is that sampling and accurate  residual  determination
may  consume  much  more  time than the actual contact time.
This error probably accounts for many  powerplants  using  a
larger dosage than necessary in their cooling water.

The  preparation  of  environmental  impact  statements  for
operating systems for new power stations led to the study of
existing  plants  for  probable  operating  results.    Some
multiple  units employing once-through cooling water systems
were found to  seldom  discharge  any  appreciable  residual
chlorine   to   the   receiving   water  where  the  station
configuration was similar to that shown  in  Figure  A-VII-8
Procedure provides for chlorination of one unit at a time on
a  program  similar  to that described below.  The discharge
from each unit is diluted by that from the three  not  being,
chlorinated.    The  effect  of  dilution  and  exertion  of
chlorine demand by the  unchlorinated  water  occurs  almost
simultaneously.

Data  from  several power plants are illustrated by Table A-
VII-2  The  data  were  collected  by  trained   technicians
familiar   with  powerplant  chlorination  practices,  using
amperometric titrators.  The scope of the test work did  not
include  complete  analysis  of  the water but, based on the
foregoing comments regarding chlorine dosage,  ammonia,  and
time  of  contact,  the  differences  in water "quality" are
evident.  Stations A and B are nearly idential in layout  to
that  shown  by Figure A-VII-8, but located on two different
rivers.   The  points  of  application  are  close  to   the
condenser  water  boxes in both power plants.  Plant C has a
common discharge canal and several units were running at the
time of the test.  All points of chlorine application are at
the intakes serving the units and one unit is treated  at  a
time.   Plants  D,  E,  and F are included to illustrate the
                         245

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Figure  A-VII-8     Typical  Powerplant Cooling Water
                                 Circuit
S.AMPI.ING POINT
fO.T CONTROL







SAMl'-LifJG POIi.T
FOR MOXItQfllNG.
^^^
~^v










U.MIT N'O. 1

UNI r f-.:o. ?


IJi-IIT .\'O. 3

\J:M! I rJO. 4

/ /
I
/
" "V

/
V
/
\
\

                                                          r\

                                                           V
            HIVER
                             Table  A-VII-2
                              OPERATING DATA
                 TYPICAL POWER_ P.LA-NT_COOLI^ V..vrF.R CHLORINATICN
                      OF E.'< ,' O.'.'C i- -THSCUCiH , CObL L'.'G SYSTEMS
                             ClL\RCH-H?i; 197~3)
                      Reference  418
PUNT
A
B
C
D

E
F
TIME OF
(SECO
Thru Cond.
30
61
SZ
115

44
63
CONTACT
^;DS)
To River
180
174
78
624

225
591
DILU-
TION
RATIO
3:1
3:1
4:1
4:1

1:1
5:1
"2
DOSE
0"g/D
1.52
1.76
2.00
3.80

7.00
7.00
CMLQIUK'i Rl:5ir
Cond. "liiicli
Free
0.6S
O.C5
0.03
0.50

1.20
1.10
Tot.il
0.84
0.82
l.SO
1.60

2.20
2.00
J'JAL (F^A)*
1 Ht:fluf/.t
Free
0.06
0.07
0.00
0.00

0.70
0.00
Total
0.19
0.10
0.20
0.20

1.20
O.OS
CHLORINE T.IC.'.TJ.F.OT
(X/D.iy)| (Mia.)
1
1
3
3

5
1
30
30
20
120
i
30
45
 •Chlorine residuals by amperomctric titrator.
                       246

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differences which can be encountered on the same river  -over
a  distance  of  less than 3 miles.  Plant D is the upstream
plant and Plant F is the farthest downstream.  The points of
chlorine application are at the intakes in all cases and the
plants supervisory and operating personnel have  many  years
of  experience  with  chlorination.  The purpose of Table A-
VII-2 is to illustrate, as accurately  as  possible,  actual
operating  conditions  in power plants where organic growths
in condensers are being successfully controlled, and to show
the effects of dilution and added "chlorine demand"  on  the
total residual chlorine in the plant effluents.

The  data  were  collected in plants having individual units
varying in age from 5 to 30 years, and unit sizes from 60 Mw
to 750 Mw.  After  one  studies  the  data  one  may   reach
conclusions such as (a) Plant D is overchlorinating in terms
of   either   frequency   or   duration;    (b)  Plant  E  is
overchlorinating in terms of residual level  and  frequency.
Extensive  test  work  is  being conducted at both plants to
determine the optimum chlorine treatment required.

It is not unusual to observe two units  in  a  single  power
plant   requiring  different  chlorination  schedules.   The
geometry of \he cooling water system;  size  and  design  of
condensers; physical condition of the tube surfaces; as well
as  water quality have an influence on the chlorine residual
levels and  schedules  of  operation  required  to  maintain
comparable  unit performance.  Obviously, the condition of a
river  can  change  substantially  within  a  few  miles  as
indicated by Plants D, E, and F.

A  conclusion is that substantial savings in chlorine dosage
can be achieved by application as near the  condenser  inlet
as possible while still maintaining control levels necessary
to  maintain  cleanliness.  This in turn results in residual
chlorine consisting to some  major  degree  of  hypochlorous
acid,  a  form  most  easily reduced to chloride by chlorine
demand of water from adjacent units.

Another study was made on the blowdown of  a  cooling  tower
serving a power plant employing intermittent chlorination of
recirculated  water  for  slime  control  of the condensers.
Blowdown was continuous.  Chlorination of the unit served by
this tower is programmed for four times a day.  Residual  in
the  blowdown  for one cycle  (typical of the other three) is
shown in Figure A-VII-9.  Makeup to this tower  is  discharge
from  a cooler using water from another system  in the plant,
also being chlorinated with a similar program but  staggered
from the tower under study.  This accounts  for  the momentary
increase  close  to  the end of the cycle.  This curve shows
                          247

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    080
    070
    0.60
                          ICO   120   KO   160
                            TIME IN MINUTES
                        200  220  2JO  260  280  200
Figure A-VII-9
Concentration of  Residual  Chlorine
in Cooling Tower  Slowdown  Versus Time
418
                    248

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only total residual chlorine.   Other  data  on  this  tower
indicated  that  at  peak values as much as 65% of the total
was  free  available  chlorine,  declining   gradually   and
disappearing  when  the  total  dropped to approximately 0.2
mg/1.

Draley,425 in developing data for  an  equation  to  predict
decay   rate,   plotted   the  residual  values  during  two
chlorination cycles and beyond  in  a  power  plant  with  a
natural  draft  tower.   The  shape  of  the  curves for the
cooling tower basin return was nearly identical to Figure A-
VII-9.  Peak value for one run  was  about  0.3  mg/1  total
residual.   No  free available chlorine was found.  A second
run with a peak value of about 0.5 mg/1 total  yielded  less
than 0.1 mg/1 free available chlorine.

The  similarity  of the shape of the curves is noteworthy in
view of the differences in the syterns.  The data  in  Figure
A-VII-9  represents  a  cooling  water  which  (1)  has some
residual remaining from the previous cycle,  (2)   the  total
value  was  higher,   (3)  sampling was in the tower blowdown
instead of the cold water return, and (U)  the tower  was  of
the  induced  draft  instead  of  natural draft (hyperbolic)
type.

In another study. Nelson32*  in  developing  a  mathematical
model  to  predict residual chlorine levels in cooling tower
blowdown streams, expressed residual  as  negative  chlorine
demand.   When  the  plot  of  the resulting curve is simply
inverted, it closely resembles those mentioned  above.   The
point is that the reliability of predictability seems firmly
established.   The factors involved in the decay rate of the
recirculated cooling water after the chlorination  cycle  is
ended  are:  (1) blowdown; (2) evaporative losses; (3) light
catalyzed  decomposition  of  free  chlorine;  (1)  chlorine
demand  of  the  system;  (5)  cooling  system  volume;   (6)
recirculation rate; (7) chlorine demand of the  makeup;   (8)
atmospheric contamination; and (9) decomposition products of
basin sediment deposits.

Since  all  of  these effects occur simultaneously, it seems
impossible to  segregate  and  identify  them  individually.
Fortunately,  from  the  results  cited  above it also seems
unnecessary.  One of these, evaporate losses, has been cited
as a possible air  pollution  problem.   The  volatitity  of
chloramines  has  long  been  known  to  exceed that of free
available chlorine.  This is particularly true  of  nitrogen
trichloride  and, to a slightly lesser degree, dichloramine.
In  fact,  aeration  is  frequently  used  to  remove  these
compounds  following  ammonia nitrogen oxidation  (breakpoint
                         249

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chlorination).     The     most     predominant     species,
monochloramine,  is  much less subject to loss.  In studying
waste treatment plant effluents, where the residual  usually
consists   of   all  chloramine,  Kothandaraman  and  Lin42*
reported no loss of residual chlorine due to  air  agitation
of  5600  cfm/1000  cu  ft for 30 minutes at residual levels
above 2 mg/1.  Thus it would appear that evaporative  losses
of  combined  chlorine  which could be expected to be nearly
all monochloramine in a cooling  tower  and  subsequent  air
contamination   are   not   factors  of  consequence.   Free
available chlorine is subject to reduction by  sunlight  but
not by volitilization.

Excess total residual chlorine discharge can be minimized by
monitoring  free  available  chlorine  concentrations in the
discharge stream and providing feed-back control on chlorine
addition.  Commercial monitoring and controlling instruments
are available  from  at  least  two  major  suppliers.   The
analyzers  furnished  by  both  of  these  firms  involve an
amperometric analytical method which utilizes two electrodes
to  measure  the  current  generated  by  the  presence   of
chlorine.   One  of these firms advises that the reliability
of this type of analyzer and  control  system  is  generally
concluded  to  be  approximately  0.1  mg/1.   However,  the
analyzer must be calibrated in the field at least  once  per
week  by  using  a  titrator,  and consequently the ultimate
reliability of the system depends upon the conscientiousness
of  the  operating  and/or  maintenance  personnel.    These
analyzers  can  be  used  to  monitor  either total residual
chlorine or free available chlorine by making  a  change  in
the chemical composition of the buffer solution.

As  shown  in  Figure A-VII-10, chlorine can be regulated by
feedback instrumentation.  The chlorine feeder is  activated
manually  or  by  a  timer.   Chlorine  is then added to the
cooling water before it  goes  to  the  condenser.   Cooling
water  leaving the condenser flows to the cooling pond or to
the receiving water body.  Chlorine level in  the  discharge
is  monitored  by  chlorine  analyzer  AC-1.   When chlorine
reaches 0.1 mg/1 the analyzer opens ACS-1 which  shuts  down
the  feeder until it is restarted manually or by timer KS-1.
This type *ot system is not in general use in the industry at
this time,  but  is  common  practice  in  municipal  sewage
treatment  plants.   Intermittent  programs  of  chlorine or
hypochlorite addition can be employed  to  reduce  to  total
chlorine residual discharged.  A further technique to reduce
the   total   residual  chlorine  discharged  is  to  employ
chlorination at periods of low condenser flow  for  a  unit.
If  only  one  unit  at  a  time  at  a multiunit station is
chlorinated, the concentration of total residual chlorine in
                         250

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      RIVER
      WATER
      SUPPLY
                                  AC-1
                        CONDENSER
                          KS-1
            RIVER
            WATER
            RETURN
             CHLORINATOR
-o
     ACS-1
      CHLORINE
      CYLINDER
                            LEGEND:
                                AC-1:
                                ACS1:
                                KS-1:
    CHLORINE ANALYZER
    CHLORINE FEEDER CONTACTS
    CONTROLLER (TIMER OPTIONAL)
    FLOW PATH
    OPTIONAL FLOW PATH
    INSTRUMENT SIGNAL
FIGURE A-VII-10CHLORINE FEED CONTROL ONCE-THRU CONDENSER COOLING SYSTEM
                         251

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the  combined  effluent  from  the   station   is   reduced.
Chlorination  can  further  be  employed at times in harmony
with more favorable receiving water conditions.

Controlled addition of chlorine can also be achieved without
the daily  use  of  monitoring  instruments.   Sampling  and
laboratory  analysis  can  be  employed for a number of days
until a correlation is established between chlorine addition
characteristics (schedule, rate, duration) and the  effluent
total  residual  chlorine concentrations.  Subsequent use of
the  correlation  with  no  effluent  sampling,  except  for
occasional checks, may be satisfactory in many cases.

Figure  A-VII-11  illustrates, in simplified form, a typical
once-through system for a nuclear  or  fossil-fueled  plant.
It  is  impossible  to  cover  the many variations in layout
which are being developed by engineers  to  accommodate  the
rapidly  changing  technology, power plant equipment design,
and  growth  in  unit  size.  However,  regardless  of   the
complexity  of  the system, all of the cooling water must be
chlorinated.

To minize the level of residual chlorine in the effluent, it
is logical to select  points  of  chlorine  appM.cation  and
design  the  control  system  to  take  maximum advantage of
dilution effects in the discharge canal(s).   This  requires
revisions  in  what  has  been considered standard practice.
Referring  to  Figure  A-VII-11,  it  has  become  a  common
practice  in  recent  years  to chlorinate the plant service
water and or auxiliary cooling water as separate systems tor
two reasons which remain  valid:  (1)  Chlorination  of  the
service  water  often  requires  a schedule of treatment and
chlorine dosage level different than  needed  for  the  main
condensers; and (2) modern intake designs and pump locations
make  it very difficult to design and locate a single set of
diffusors to chlorinate all the water entering the plant.

Therefore,  chlorination  of  the  station  service   water,
auxiliary  cooling  water,  and  emergency cooling water (if
any)  remain as separate functons which may be controlled  to
take advantage of dilution in the water return system.

For   the  past  twenty-five  years,  with  few  exceptions,
condenser cooling water has been chlorinated at  the  intake
structure.   Again,  with  few  exceptions, chlorination was
programmed on a unit basis as indicated by the plants listed
on Table A-VII-2 There are several sound  reasons  for  this
practice:   (1)  The chlorine solution piping system is short
and  of  simple  design  for  most  applications;  (2)   The
electrical control system is the least complicated possible.
                        252

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Figure A-VII-11  Typical Power Plant Once-Through
                 Fresh or Salt Water Cooling System-
                 Points of Chlorine Application
                 ( Reference 418)
            253

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often  being limited to one or two program clocks and simple
chlorine feed step rate controls; (3) If marine growths  and
shelled organisms are anticipated as a problem the diffusors
are  located ahead of the bar racks instead of in the screen
wells 428 and the controls remain essentially  the  same  as
indicated  above;  and  (4)  The  chlorination equipment and
chlorine handling system are located near the  water  intake
structure  which  is generally several hundred feet from the
power station proper.

Generally new condensers are served by at least two  cooling
water  flows  and  six  are not uncommon.  Therefore, if the
points of chlorine application are  located  in  the  piping
system just ahead of the inlet water boxes as illustrated on
Figure  A-VII-11 and the chlorine control system designed to
treat the unit flows (four illustrated)  one  at  a  time  in
sequence, the chlorine residual in the treated water will be
diluted  by  a factor of one, three or five depending on the
system design.

The auxiliary cooling systems  are  treated  on  a  separate
program  which  is timed to operated when the main condenser
flows are not being treated.  The ratio of  auxiliary  water
flow to the total main condenser flow is on the order of one
to ten or more and it is unlikely that a measurable chlorine
residual  from  this  source  would be detected in the plant
effluent.

There are existing powerplants which have  been  using  this
type  of  control  for  over  15  years  though the original
designers had no thoughts  regarding  dilution  of  chlorine
residual in the effluents at the time the plants were built.
Experience  with  chlorination  in  these  plants  has  been
excellent.  Based on work done several years ago and  recent
test  data  presented  herein,  there are several advantages
which should fce self-evident:  (1) The short time of  contact
minimizes  both  the chlorine dose required and the level of
the combined chlorine residual in the  water  as  it  passes
through  the  condenser; (2) Since a large percentage of the
total chlorine residual in the condenser during treatment is
free  (HOCl) the duration of  each  treatment  can  also  be
reduced.   However,  duration of treatment and frequency are
both dependent  on  the  rate  of  growth   of  the  fouling
organisms  and  frequency, in particular, may require change
with the season of the year; and (3) The effect of  dilution
on  the  total  chlorine  residual  in the plant effluent is
obvious.

Mechanically  and  electrically,  the  chlorination   system
becomes  more  complicated but with compensations.  The size
                         254

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of the chlorination system in terms of chlorine feed rate is
reduced by a factor of two, four or  six.   This  saving  in
cost  is  probably  offset by the additional solution piping
and controls  which  are  required.   The  chlorine  control
equipment  and handling system may still be located remotely
with respect to  the  power  plant.   The  total  amount  of
chlorine  used  will be reduced to the practical minimum for
the particular plant and units.

There are  three  points  which  should  not  be  overlooked
though,   in  most  cases,  they  would  not  be  considered
disadvantages: (1) Long cooling water  lines  ahead  of  the
condensers  are unprotected in terms of organic fouling: (2)
The intake structure and cooling  water  system  up  to  the
points  of application are subject to fouling by Bryozoa and
shelled organisms if brackish water  or  sea  water  is  the
source  of  cooling  water,  and   (3)  Service  water and/or
auxiliary cooling water must be  treated  in  its  entirety,
usually at the intake, because of the relatively complicated
cooling systems involved.

The  current  trend  in  the  U.S. is away from large, open,
once-through cooling water  system  except  those  involving
man-made  lakes  built  for  the purpose of sea water cooled
projects.  For practical purposes, the  modern  spray  canal
can  also  be  considered  as  an  open  system  in terms of
chlorination though actual experience is limited to very few
installations at this time.  One spray canal  user  reported
during  August, 1971, that  no  detectable chlorine residual
returned to the point of chlorine application.  The blowdown
connection is on the cold water end of the canal  and  ahead
of   the  point  of  chlorine  application.   No  measurable
residual chlorine is in the blowdown water at any time.  The
constants for this particular system are:

Recirculating rate -29 185,000 gpm treated one at  a  time
(2 Program Control)

Chlorine Treatment - 20 minutes once per day - each point

Chlorine Dosage - 2.7 mg/1

Total Chlorine Residual - 0.5 to 1.0 mg/1 at condenser inlet

Points of Application - Ahead of circulating pumps

Dilution Ratio - 1:1

Contact Time in Canal - 5 hours

Makeup Water Flow -  20,000 gpm
                         255

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One  plant,  on  once-through  circulation  with  sea water,
changed to acrolein from chlorine primarily because acrolein
(CH2CHCHO) was more effective in  controlling  grass  growth
that  matted  the  screens  at the intake canal.  After some
months  it  was  noted  that  condenser  tube  fouling   had
increased;  an  inspection  disclosed  that the acrolein was
more effective than anticipated for biological fouling;  the
tubes  and  the tube sheet were free of slimes.  The foulant
in heat transfer was found to  be  a  paper  thin  layer  of
carbonate  scale that previously had been kept under control
by the slight depression of pH when chlorine was used.   The
acrolein  was incapable of reacting with the carbonate.  The
plant  then  changed  back  to  chlorine.    Of   incidental
interest,  acrolein  in  the  amount needed as a biocide has
zero toxicity to fish.  Typical of many others,  this  plant
has  not  had  to  clean  condenser tubes either manually or
chemically after 10 years operation.   The  biocide  quality
control  program  has  been adhered to and has maintained to
desired  cleanliness  factor.   The   related   program   of
reversing flow through the condenser was incorporated in the
original  design  and is routinely utilized to dislodge some
of the potential foulants.

Chemical Conditioning in Recirculating Systems

In an evaporative cooling tower system the dissolved  solids
will  become  increasingly  concentrated above the amount of
dissolved solids in the makeup water to the  system  because
of  evaporative cooling losses.  By blowdown from the system
the concentrated solids are maintained at a prescribed level
to prevent chemical  precipitation  and  scaling.   Chemical
conditioning  is used supplementally to minimize any scaling
or corrosive  tendency.   Shock  treatment  with  a  biocide
completes  the  conditioning program.  Chemical conditioning
with proper  quality  control  will  maintain  the  designed
terminal  temperature  difference  at the condenser for many
years.  Corrosion rates will be less than 1.0 mil per year.

Tables A-VII-3 and  A-VII-U  show  the  average  operational
values  for  two  types  of chemical conditioning of cooling
tower systems that are operated without  on-line  mechanical
tube cleaning equipment.


The  monitoring  of  chlorine  in the blowdown stream can be
achieved in a manner  similar  to  that  described  for  the
once-through system.
                         256

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                      Table A-VII-3
          CHEMICAL CONDITIONING OF COOLING TOWER SYSTEM
          USING  CrO4 -      387
Untreated River Makeup to Tower
     Cooling Tower System
Ca as CaCO3
Mg as CaCOs
HC03 as CaCOs
ClasCI"
S04 as SO4



mg/l
200
66
129
455
60



Ca as CaCO3
MgasCa(X>3
HCOs as Ca(X>3
Cl as CC
804 as 804
CrO4 as Cr
' P04 as P
pH
mg/l
800
264
15
1,820
712
12
4
6.5
Controllable limits in tower system: pH 6.4 to 6.6; total alkalinity 15 to 20 mg/l;
calcium as CaCOs 1000 mg/l max; hexametaphosphate'6 to 10 mg/l; CrC>4
25 to 30 mg/l.
                      Table  A-VII-4
         CHEMICAL CONDITIONING OF COOLING TOWER SYSTEM
         USING ORGANIC PHOSPHATE  387
Untreated Well Water Makeup to Tower

                          mg/l

Ca as CaC03                232

Mg as CaCC>3                40

HCO3asCaCO3             216

SiC>2 as Si02                 28
     Cooling Tower System
Ca as

Mg as

HCO3 as

SiO2 as
mg/l

968

212

196

150
Controllable limits in tower system: pH 8.4 to 8.6; total alkalinity 175 to 225
mg/l; calcium as CaCOs 1000 mg/l max; silica as SiO2 180 mg/l max; organic
phosphate 20 to 30 mg/l.
                      257

-------
Further   potential   methods  of  reducing  or  eliminating
residual chlorine levels in the blowdown are as follows:376

    a)    Installing residual data  feedback  equipment  into
    the chlorine feed system.
    b)    Practicing split stream chlorination (splitting the
    condenser  flow  into   separate   streams   which   are
    chlorinated one at a time) .
    c)    Reducing the chlorine feed period, if possible.
    d)    Reducing the initial residual chlorine level in the
    condenser effluent.
    e)    Increasing the water volume of the  cooling  tower.
    This  alternative  may  not  apply  to  existing cooling
    towers because  it  involves  the  system  design.   The
    alternative  can  apply  to  systems  on the engineering
    drawing  boards.   This  alternative  may   have   other
    advantages—such  as  an  extra supply of water for fire
    protection.
    f)    Cutting off the  blowdown  when  residual  chlorine
    appears in the sump.  The blowdown flow can resume after
    the  residual  is  dissipated by the flashing effect and
    the makeup water chlorine demand.  The  length  of  time
    during  which  the  blowdown  can  be  eliminated  is  a
    function  of  the  system's  upper  limit  on  dissolved
    solids.
    g)    Mixing the blowdown with another stream which has a
    high chlorine demand.

Figure A-VII-12 illustrates  a  typical  recirculated  fresh
water  cooling  system and a few of the ancillary systems or
variations which are often encountered.  The total  residual
chlorine  curve  with respect to time  (decay)  is predictable
for a cooling tower  system.   Location  of  the  points  of
chlorine  application  is  traditionally  in the tower basin
discharge canal or ahead of the  recirculating  pumps  in  a
sump.   The  several  sets  of  data  in the references were
collected  from  tower  systems  intermittently  chlorinated
using  the traditional points of application.  At this time
a recommendation cannot be made that  the  location  of  the
point  of  application be changed since dilution or lowering
of the  chlorine  residual  returning  to  the  tower  would
undoubtedly result in accelerated fouling of the tower fill.

If  the  makeup  water is first used to cool auxiliaries, it
should be chlorinated following the same principles as  used
for  an open system but with the program set so that it does
not coincide with treatment of the recirculating water.

The blowdown should be taken from the tower basin  ahead  of
the point of chlorine application but it has been found that
                          258

-------
                       /  i
                    	'•-->
                      ....y ..._,,
                               "TSi
              v-; <>
         	n
         r	J
                       .„..
                         L

 K-
•-•• i
 \ l_.
                 I  ccx..i.iiVu
RrcM-y;i;i.ATto r :•,':> ~;..A.riT cot'.: .:•-.; v..vi;%r? SYSTEM
   Figure A-VII-1.2
          259

-------
•this  is  not  the  case  for  many  existing  cooling tower
Systems.  If  the  blowdown  is  used  to  sluice  ash,  the
chlorine  residual  is  lost  in the ash pond.  Similarly, a
holding pond could accomplish the same result if the time of
retention is long enough.  At the very least, a holding pond
smooths out the peak levels of residual chlorine and reduces
the  level  to  one  which  can  be  easily  eliminated   by
controlled chemical dechlorination.

If  the  blowdown is returned to the receiving body of water
direct, there are two alternatives: (1)  Close  the  blowdown
valve  during  the  chlorination  cycles  with suitable time
delay   controls   set   to    match    the    time-residual
characteristics  of  the system; and (2)  Controlled chemical
dechlorination of  the  blowdown  in  synchronism  with  the
chlorination   program  controls  and  with  time  delay  as
described above.

Experience indicates that a  successful  chlorination  cycle
for the average fresh water power plant cooling tower system
is  two treatments per day; each treatment approximately ten
minutes longer than the turnover time; and with the chlorine
feed rate set to build up a total residual chlorine level of
0.5 mg/1 in the water returning to the tower at the  end  of
the  chlorination period.  Note that this statement is based
on current experience; not on tests  designed  to  determine
the   minimum  treatment  which  will  produce  the  desired
results; viz., a  clean  system.   For  example,  it  should
follow  that  a  lower residual maintained for a longer time
would give a similar  result,  or  carried  to  the  logical
conclusion,  a  very  low total chlorine residual carried in
the system continuously would be equally effective.

There are several power companies  in  the  U.S.  which  use
continuous  chlorination  of  cooling  tower  systems but at
residual levels on  the  order  of  0.3  to  0.5  mg/1.   No
experiments   have   been   performed   to   determine   the
practicability of variations in the  chlorine  treatment  of
cooling tower systems; largely because no one wishes to risk
the need for removing a large unit from the line to manually
clean both the condenser and the cooling tower.

Experience   with   recirculated   salt   water  systems  is
practically nil but the makeup  water  to  a  cooling  tower
system  should  be  chlorinated  continuously  if  the water
supply is either  brackish  or  salt.   The  total  residual
chlorine  level should be the minimum which can be realiably
controlled, i.e., between 0.1 and 0.2 mg/1.   The  treatment
will  prevent  infection of the recirculated water system by
                           260

-------
Bryozoa and shelled marine organisms such as  barnacles  and
mussels.

Controlling  the usual organic slime growths in once-through
salt or brackish, water-cooled heat exchangers  requres  the
same   chlorine   treatments  as  needed  for  fresh  water.
Variations in residual chlorine level, length, and  duration
of  treatment  are  caused by pollution factors, the same as
for fresh water, and the need to control the accumulation of
more resistant marine growths.

Using the open system, salt water experience as a reference,
it follows that continuous low  level  chlorination  of  the
makeup  water  will  eliminate  the  marine  organisms  as a
problem and certainly reduce  the  bacterial  infection  and
chlorine  demand  added  to  the recirculating water via the
makeup water.  However, it is  doubtful  that  it  would  be
practical  to chlorinate the makeup water heavily enough for
the chlorine residual to be effective in the  condensers  or
on the tower structure.

The  standard intermittent chlorination of the recirculating
water will be the same as described for a fresh water system
but undoubtedly the total amount of chlorine  used  will  be
reduced.  The cooling water is an excellent air scrubber and
algae  as  well  as  "chlorine  demand" removed from the air
remain as fouling sources to be contolled by chlorination of
the recirculating water.

The amounts of pollutants  discharged  in  blowdown  can  be
reduced  by  reducing  the blowdcwn flow.  This reduction in
flow can be achieved by substituting more soluble  ions  for
scale  formers.   Similarly, the use of organic sequestering
agents such as polyolesters and phosphonates can be used  to
reduce   blowdown   flow   rates.  336   These  then  become
pollutants in the blowdown.

Water  treatment  chemicals  are  used  to  control  several
problem  areas.  The use of these chemicals has been greatly
reduced by the substitution  of  plastic  or  plastic-coated
cooling  tower  components.   The plastic shows considerable
resistance  to  microbiological   attack,   corrosion,   and
erosion.   Many  new  installations using cooling towers are
going this  route.   Where  water  treatment  is  necessary,
several  chemicals  are  being  used  to control the various
problem areas associated with the cooling towers.

Of the commonly used biocides, chlorine or  hypochlorite  or
nonoxidizing   organic   compounds  such  as  chlorophenols,
quaternary amines, and organo-metallics  such  as  organotin
                            261

-------
compounds,  organosulfur, and organothiocyanate Table A-V-18
are most frequently employed.  They are all used to  prevent
deterioration   of   tower   wood,  loss  of  heat  transfer
efficiency,  general  fouling  or  plugging   arising   from
microbial growths, and corrosion that results from microbial
attack,   Organotin   must  be  formulated  with  quaternary
ammonium and other complex amines to produce  a  synergistic
effect  and  to  be  dispersible.  Chlorophenols, as soluble
potassium and sodium salts, are more  persistent  than  free
chlorine and remain in systems longer.  Common Chlorophenols
include:     2,4,5-trichlorophenate;   2,4,6-T;   2,3,4,6-T;
tetrachlorophenol; and pentachlorophenol.  Organosulfurs are
noted for low toxicity  to  animals,  yet  effective  action
against  bacteria,  fungi,  and  especially sulfate-reducing
bacteria.  Quarternary  and  complex  amines  are  effective
wetting  agents  and  destroy  microbial  agents by surface-
active  properties;  these  are  the  least  toxic  of   all
antimicrobial  compounds  to animals, although they may form
and so cause anesthetic  problems.   The  organothiocynates,
the  most  modern  of  the nonoxidizing biocides, are widely
effective.  Oils, organic  chemicals,  water  hardness,  and
other  materials  seem  to  cause  little reduction in their
effectiveness,  especially  if  they   are   combined   with
Chlorophenols.   The nonoxidizing biocides are used whenever
the problems are rather severe and where  the  use  of  free
chlorine  is  not  acceptable.   Typical  concentrations for
continuous use are 1 to 25 ppm; higher (200 ppm  or  so)   if
applied  in  periodic  treatments.  Elemental chlorine is an
oxidizing  agent  and  can  cause  rapid  deteroriation   of
wood.10See

The  use of biocides that contain mercury, arsenic, lead, or
boron may be limited by more stringent regulations on  their
release  to  the  environment  than  most  of  the compounds
previously discussed.  These are rarely if  ever  used  now;
however,  a  review  of  label names in Table A-V-18 reveals
that  the  potentially   harmful   materials,   copper   and
thiocyanate  ions, are present in some commercial compounds.
Tin is probably also questionable as  far  as  environmental
harm  is  concerned.   All  of the chemical labels note that
precautions should be used in handling of the  proudct,  and
two  indicate  that  the  product may be harmful or fatal if
absorbed through the skin.   Only  two,  however,  cautioned
against dumping them directly into lakes, streams, or ponds.
Some  of  the  products  containing  2,t,5-T  listed no such
precautions; yet the compound is now  expressely  banned  in
waterways.

Scale  and  corrosion  inhibitors  and  biocides require the
addition of acid or alkali to makeup water to keep the pH at
                           262

-------
an optimum level, usually a range from  5.5  to  7.5.    Silt
controls  polymers may be used if makeup is raw water from a
nearby lake or river.  Lignin-tannin dispersives such  as  1
to   50   ppm   sodium   lignosulfonate   may  be  employed.
Antifoulants  such  as  0.1  to   5   ppm   of   acrylamids,
polyacrylate,  polyethyleneimine,  or  other  high molecular
synethic organic polyelectrolytes may also be used.lOSee

Wood deterioration includes three types of attack; chemical,
biological, and  physical.   Chemical  deterioration,   which
removes  the  lignin, is especially severe with the combined
presence of  high  chlorine  residual  and  high  alkalinity
(chlorine  should  be  less than 1 ppm).  This deterioration
can be checked by maintaining the pH below 8.0.   Biological
attack  on  wood  is  caused  by  cellulolytic  fungi.   The
application  of  chlorinated   phenolic   compounds   in   a
controlled  foam  form has been found to be highly effective
in promoting prolonged protection  of  cooling  tower  wood.
Physical  attack  on  wood  is  caused  by  high-temperature
waters, high solids concentration, and freezing and  thawing
conditions.

Oxidizing biocides effectively kill the organisms, but their
activity  is  short-lived.   (Requires frequent or continuous
feeding).  Chemicals which are  used  include  chlorine  and
calcium and sodium hydrochlorites.  One method is to dose to
a free available chlorine concentration of 0.3 - 0.6 ppm for
a  period  of  four hours daily.  The chlorinated cyanurates
and inocyanurates and other  chlorinated  organic  materials
are  also  used  to introduce chlorine to water.  Persulfate
compounds,  which  are  odorless,  are   also   often   used
(potassium  hydrogen  persulfate).  Ozone, another oxidizing
biocide,  is  undergoing  experiment  for  use  in   various
systems.  It is a very powerful oxidizing agent and is twice
as  potent  as  chlorine for destroying bacteria and organic
matter.  It also oxidizes undesirable metals  such  as  iron
and manganese.  Several nonoxidizing biocides are also being
used.  Some of these compounds include: chlorinated phenolic
compounds  -  chlorinated  and  phenylated phenols and their
sodium  or  potassium  salts;  organotin  -  complex   amine
combinations;   surface-active  agents  such  as  quartenary
ammonium   groups;   organo-sulphur   compounds   such    as
dithocarbamate  salts and the thiuram mono - and disulfides;
rosin amine salts formed by reaction with  carboxylic  acids
and  acidic  phenols  such  as  the salts of acetic acid and
pentachlorophenol; copper  salts  such  as  copper  sulfate;
thiocyanates    such    as    methylene   thiocyanates   and
bisthiocyanate; and acrolein which is highly  flammable  and
may be toxic to warm-blooded animals.
                           263

-------
In  cooling water systems, two types of corrosion inhibitors
can   be   used   -   anodic   and   cathodic.    Chromates,
orthophosphates and nitrite - based products are examples of
anodic  corrosion  inhibitors,  polyphosphate , silicate, and
metal salts which form sparingly soluble hydroxides,  oxides
and  carbonates  (such  as zinc) act as cathodic inhibitors.
Chromates and other heavy metals may be harmful  to  aquatic
organisms.   Phosphates  can  serve as a nutrient to aquatic
life.  Inorganic, nonchromate corrosion  inhibitors  consist
of   various   combinations  of  poly phosphates,  silicates,
borates, f errocyanides, nitrates, and  metal  ions  such  as
zinc    and   copper   (straight   polyphosphate,   zinc
polyphosphate, and ferro cyanide - polyphosphate) .  Work  is
being  done  to  develop  nonpolluting  corrosion inhibiting
components.    Two   such   compounds   are    sodium    and
mercaptobenzothiazole  and derivatives of organo-phosphorus.
Dearborn Chemical Division of W. R. Grace  and  Company  has
developed  a  nonchromate, nonphosphate corrosion inhibitor.
The   synthetic-organic   corrosion   inhibitor   which   is
hydroly tic ally  stable and possibly nontoxic.  This compound
is designed to reduce scaling and fouling on  heat  transfer
surfaces.  It is not as effective as zinc and chromates, but
is  at  least  as effective as other comparative nonchromate
and zinc polyphosphate compounds.

A film-forming sulfophosphated organic  corrosion  inhibitor
is   put   out   by  the  Tretolite  Division  of  Petrolite
Corporation.  Tretolite states that it is effective in  both
fresh  and  high  brine waters and is less toxic to fish and
other aquatic life than metal salts such as  chromate.   Its
toxicity compares to that of methanol, gasoline, and xylene.
It  is  said  that  the  inhibitor also performs well in the
presence of H2S or
Scale deposits are prevented by controlling the hardness and
alkalinity of the water system.  This is  normally  done  by
feeding  an  acid to the water to neutralize the bicarbonate
alkalinity.  An acid which is widely used is sulfuric  acid.
Most cooling tower systems are controlled in the pH range of
six  to  seven.   This  range depends on the balance between
corrosion inhibition and deposit control.  Organic phosphate
compounds such  as  aminimethylenephosphonate  are  used  in
concentrations    up    to    3   ppm.    Phosphonates   and
polyelect roli tes are  used  as  deposit-control  agents.   A
possible  arrangement  for  pH control is shown in Figure A-
VII-13.
                          264

-------
 ro
 en
 in
'^J~
RIVER
WATER
                                                                                  TURBINE
                               \
                                                                      CONDENSER
                                COOLING TOWER
                                                  COOLING
                                                   WATER
                                                 --' PUMP
                                                                                      SLOWDOWN
A                                ACID OR    \
                                LKALI TANK^/
                                                             • \JA
                                           SOLUTION FEEDER
LEGEND:
    AC-1:  PH SENSOR & TRANSMITTER
    E/P-1: ELECTROPNEUMATIC TRANSDUCER
    FC-1:  FLOW CONTROL VALVE
	 :  FLOW PATH
	:  CONTROL SIGNAL (ELECTRICAL)
 //  //  :  CONTROL SIGNAL (PNEUMATIC)
                 FIGURE A-VII-13RECIRCULATING CONDENSER COOLING SYSTEM pH CONTROL OF SLOWDOWN

-------
The following corrosion and scale inhibitary  chemicals  may
be employed at the concentrations given.108ee

1.  Chromate plus zinc                 5 to 30 mg/1 CrOU
                                       1 to 15 mg/1 Zn

2.  Chromate plus zinc plus phosphate  5 to 30 mg/1 CrOU
                                       1 to 15 mg/1 Zn
                                       1 to 5 mg/1 PCW
                                            (inorganic)
                                       1 to 5 mg/1 (organic)

3.  Zinc plus inorganic phosphate      10 to 30 mg/1 PO4
                                       2 to 10 mg/1 Zn

4.  Zinc plus organic phosphate        1 to 10 mg/1 Zn
                                       3 to 15 mg/1 POU
                                            (organic)

5.  Organic phosphate scale inhibitor  1 to 18 mg/1 POU
                                            (organic)

6.  Specific copper corrosion inhibitors 1 to 5 mg/1 sodium
                                       mercaptobenzothiazole
                                       or benzotriazole

Consider   the  problem  of  trying  to  maintain  condenser
cleanliness  in  the  situation  where  the  discharge    is
permitted  of  the  mildly  concentrated and untreated tower
system blowdown to a receiving stream but the plant  is  not
permitted  to  discharge any inhibiting chemicals that might
be used normally  for  scale  or  corrosion  control.    Such
inhibitors might include individual or combined compounds of
zinc,   chromate,   hexametaphosphate,  phosphonate,  polyol
esters, etc.  In essence, the tower  system  would  have  no
chemical  conditioning  except  for  shock  application of a
biocide to control slime and algae and the use of an acid to
adjust alkalinity.

This  method  of   minimum   chemical   treatment   involves
controlling the stability index of the system water, by acid
feed, to a point where it is in a slightly scaling condition
plus  shock chlorination.  The objectives in operation is to
produce a water  with  a  slight  scaling  tendency  thereby
eliminating  the basic requirement of a corrosion inhibitor.
Nor is the scaling tendency to be viewed with alarm  if  the
tower   system  is  equipped  with  on-line  condenser  tube
cleaning equipment such  as  that  supplied  by  Amertap  or
M.A.N. Mild descaling also cart be accomplished by depression
of  the pH in the tower system to 5.0 for about 8 hours once
weekly.  Mild descaling does not increase the  overall  rate
of  corrosion.  In this regard the installation of corrosion
                         266

-------
probes  in  the  system  may  be  required  for   monitoring
corrosion rates either periodically or continuously.


Shock  chlorination of the condenser cooling water for about
20 minutes daily, or one complete cycle, will be adequate to
control the growth of bacterial slimes and algae  under  the
usual conditions.  If not, a second application some 8 hours
later  would  be  indicated.  The free available chlorine in
the water returning to the tower must be limited to  1.0  to
1.5  mg/1  in  order not to delignify the wood components of
the tower.  If the cooling tower is all wood the  components
should  have  been  specified  for  chemical pretreatment to
prevent fungal attack and to withstand any excess alkalinity
in the cooling water.

The manufacturers of on-line  condenser  cleaning  equipment
suggest  that chlorine is not needed when their equipment is
used; the  tubes  supposedly  are  kept  free  of  bacterial
growth.   Chlorine,  or  an  equivalent biocide, however, is
certainly needed to prevent excessive growths on  the  tower
deck  and  tower  fill.   If  the  growths  are  allowed  to
proliferage on  the  decks  the  distribution  orifices  may
become plugged and cause flooding.  Excessive growths on the
fill decrease tower efficiency.

Tables  A-VII-6  and  A-VII-7  shows the average operational
values for a  cooling  tower  system  without  any  chemical
conditioning  other than acid for the control of alkalinity;
and with complete chemical conditioning.  The  condenser  is
provided with on-line mechanical cleaning equipment.

Chemical   Cleaning  of  Condenser  Tubes  During  Scheduled
Outages

Condensers are by far the  largest  heat  exchanger  in  the
condensate-feedwater  cycle.   They  contain  from  5,000 to
50,000 tubes, 7/8 or lw O.D. by 20 to 60  feet  long.   Tube
materials  may  be  stainless  steel or brass alloys such as
admiralty brass, aluminum brass, aluminum bronze,  arsenical
copper,  90/10  or  70/30  cupro-nickel.   The  tubes may be
contained in one housing or shell or because of size may  be
arranged  in  from 2 to 6 shells for very large units.  Each
shell may be considered a condenser in itself.

In function the condenser serves  to  re-liquefy  the  steam
which  exhausts  from  the last row of blades of the turbine
and flows around the tubes.  Cooling water flows through the
tubes extracting heat from the tube  walls  which  interface
with  the  steam.   The  overall  cleanliness  of  the  tube
                        267

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                     Table  A-VII-6
        NO CHEMICAL CONDITIONING OF COOLING TOWER SYSTEM
        EXCEPT FOR ALKALINITY CONTROL. BUT USING ON-LINE
        MECHANICAL CLEANING CONDENSER TUBES 387
Untreated River Makeup to Tower               Cooling Tower System
                     mg/l                               mg/l
Ca as CaC03
Mg as Ca(X>3
HC03 as CaCOa
ci as cr
804 as SO 4
SIO2 as Si02
pH
100
64
148
4
10
6
7.5
Ca as CaCC>3
Mg as CaCOs
HCOs as CaC03
CI as CI'
804 as SO4
Si02 as Si02
PH
500
320
136
18
645
27
8.0
                    Table A-VII-7
        COMPLETE CHEMICAL CONDITIONING OF COOLING TOWER
        SYSTEM AT "ZERO" DISCHARGE WITH SIDESTREAM TREAT-
        MENT OF TOWER WATER AND ON-LINE MECHANICAL CLEANING
        CONDENSER TUBES  387
Untreated River Makeup to Tower               Cooling Tower System
                     mg/l                               mg/l
Ca as Ca(X>3            230              Ca as CaCOs        260
MgasCaCOs            172              Mg as CaCOs       175
HCOsasCaCOs         263              HC03 as CaCOs     300
Na as Na                24              Na as Na          7,740
CI as CI-                12              CI as CT          1.030
SO4asSO4             174              80435804      14.800
SiO2 as SK>2             20              SK)2 as S£>2        20
pH                    7.5              Organic P04         25
                                      pH               8.5
                 268

-------
surfaces is critically important to the  efficiency  of  the
condenser,  to  the  degree of vacuum placed in the turbine,
and hence to the efficiency of the plant.

Chemical cleaning of condenser tubes  is  usually  performed
during  a  scheduled  outage of the unit, unless the fouling
has reached a magnitude  that  warrants  a  separate  outage
beforehand.   The  chemical  cleaning  is relatively simple,
using either the acid foaming technique or the soak  method.
The  condenser  can  be  cleaned  within  12  hours  if  all
preliminary operations have  been  organized.   Of  the  two
methods,  soaking  has  proved  to  be  more  thorough  than
foaming.

The foaming method consists of  a  foam  generator,  with  a
mixing  tank  to produce an acid foam that is then pumped to
specified sections of the water  box.   The  foamed  mixture
flows  by  gravity  through  the condenser tubes and then to
waste.  Since there is no pressure involved, the top rows of
tubes, or a condenser tube that is partially  blocked,  will
receive  hardly  any  foam  and  remain  uncleaned..  It  is
important before cleaning that all of the  tubes  should  be
inspected  and  any  potential  blockage removed.  It is not
uncommon to  find  numerous  tubes  partially  blocked  with
pieces  of  wood,  particularly after icing conditions cause
damage to tower fill.  Wind blown grass and  similar  debris
will  also  cause blockage.  The efficiency of foam cleaning
in a relatively short contact  time  is  attributed  to  the
strength  of  acid  used,  in  this  case  about  15 percent
compared to the usual  5  to  7  percent  acid  in  soaking.
Either inhibited sulfuric acid or mixed organic acids may be
used  when foaming austenitic stainless steel tubes.  At the
strength of 15 percent  it  would  not  be  prudent  to  use
hydrochloric  in  contact  with  this steel.  Neutralization
with an alkali is not needed following the acid foam or soak
cleaning.  The usual practice is to  start  the  circulating
pumps and flush the condenser for about 30 minutes to remove
any  residual  acid.   Then, the water boxes can be reopened
for inspection.

Chemical cleaning by the soak method is merely  filling  the
water  boxes  to  the  top  rows  of  condenser  tubes  with
inhibited acid  plus  0.5  percent  ammonium  bifluoride  at
ambient  temperature.   The  acid  strenght  is  5.0  to 7.5
percent.  Circulation is used when  practical  by  repumping
the  acid  solution  from the condenser to the acid delivery
tank truck and then back to  the  condenser.   Although  the
acid recirculation rate is relatively low, the reaction rate
is  increased by circulating fresh acid over the deposition.
The  choice  of  acid  for  the  soak  method  is  generally
                         269

-------
hydrochloric  because  of  its rapid reaction with carbonate
scale  without  forming  an  insoluble  by-product.    Other
deposits  also are more easily solubilized.  The addition of
ammonium bifluoride intensifies the solubility  of  silicate
and  iron  deposition.   Sulfuric  acid also will react with
calcium carbonate  deposition,  but  produces  an  insoluble
calcium  sulfate  precipitate that may settle out and adhere
to the tubes in quiescent soaking.  Therefore, the choice of
acid is usually hydrochloric  even  if  the  condenser  tube
material  is  austenitic  stainless  steel.  Corrosion tests
show essentially the same rates for stainless with  sulfuric
or hydrochloric under soaking conditions; neither stress nor
crevice  corrosion  has occured with hydrochloric as used at
ambient temperature.

Mechanical Cleaning of Condenser Tubes

On-Line Mechanical Cleaning

Equipment for on-line mechanical cleaning of condenser tubes
is manufactured primarily by the Amertap Corporation and  by
the M.A.N. Corporation of West Germany.  By far, most of the
installations  at  electric  generating plants in the United
States have been supplied by Amertap.  In principle, each of
the two  systems  has  the  same  objectives;  that  is,  to
maintain  condenser  tube  cleanliness continuously while in
operation by mechanical means instead of chemical.

The basic principle of the Amertap system  is  to  circulate
oversize  sponge  rubber  balls  through the condenser tubes
with the cooling water.  These  balls,  after  the  original
charge,  are  injected into the inlet pipe, collected at the
discharge piping in a basket arrangement and  then  repumped
continually to the inlet.  The number of balls in the system
is  approximately  10  percent of the number of tubes in the
condenser.  Amertap estimates that each tube receives a ball
on the average of every 5 minutes with a normal  circulation
time  per  ball of 20 to 30 seconds.  However, any tube that
becomes partially blocked at  the  entrance  or  within  its
length   will   not  become  unblocked  by  the  ball.   The
effectiveness of the  sponge  balls  is  for  removing  soft
chemical  precipitates  or  bacterial slimes before then can
become adherent.  Because the balls  are  porous  a  certain
amount  of  water  flows  through  the balls and loosens the
accumulated deposits retained on the balls.  The  balls  are
also  furnished with an abrasive band, to be used only where
older deposition needs to be removed by the scouring  action
of  the  abrasive.   A  schematic arrangement of the Amertap
system is shown is Figure A-VII-14.
                           270

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   OUTLET WATER
   BOX
COOLING
WATER
OUTLET
      STRAINER
      SECTION
                                                   1
TURBINE EXHAUST
STEAH
                                                                          CONDENSER
                                                                          DOME
                                                   HATCH FOR INSERTING
                                                   OR REMOVING BALLS
 BALL COLLECTING
 BASKET

 BASKET SHUTOFF
 FLAP     ""
                                                                    //pxE
                                               BALL
                                              COLLECTOR
                                 ,INLET MATER
                                  BOX
A. 1
•
1

1

1

1

* 1

1

I
•
r
•^
^
                                                                                            SPONGE RUBBER
                                                                                            BALLS (TYPICAL)
                                      COOLING WATER
                                      INLET
                                        Figure  A-VII-14
             SCHEMATIC  ARRANGEMENT  AMERTAP  TUBE  CLEANING  SYSTEM
                         387

-------
The M.A.N. system for on-line  mechanical  cleaning  uses  a
brush  device  about  50  mm  long sized to pass through the
condenser tubes intermittently.  The M.A.N. system has to be
incorporated in the original design of a condenser in  order
to  provide  additional  tube  length  for  attachment  of a
plastic cage on each end of each  tube  to  hold  the  brush
device.   The plastic cage length is about 75 mm.  To attach
the plastic cage to the tube ends, the tubes have to  extend
10  mm  beyond  the  tube sheet.  Therefore, inlet tube ends
have to be straight instead of flared as would be the  usual
practice to avoid inlet end erosion.  The tube sheets do not
have  to  be  machined  for  flaring with the M.A.N. system.
Provisions for reversing the flow of condenser cooling water
have to be  incorporated  in  the  original  design  of  the
auxiliary  equipment.   To clean the tubes the cooling water
flow is reversed, which forces the brushes through the tubes
to the plastic cage at the opposite end.  Then  the  cooling
water  flow is returned to the normal direction, the brushes
would be forced to their  normal  resting  position  in  the
cages at the outlet ends of the tubes.  Recycling can be set
up  automatically  for  whatever  frequency  of  backwash is
desired.  Twice daily is normal.  The schematic  arrangement
of the reverse flow piping for the M.A.N. system is shown in
Figure A-VII-15.

A  current  Edison Electric Institute survey conducted among
member companies comparing  chlorination  versus  mechanical
cleaning  of condenser tubes may be indicative of the degree
to which mechanical devices for maintaining tube cleanliness
have  been  successful  and  the   degree   to   which   the
supplemental  use  of  chlorine  is required.  As of May 24,
1974,  fourteen   (14)  respondents  had   supplied   answers
covering   two   types  of  in-service  mechanical  cleaning
installations on the condenser cooling water systems for  54
powerplant units.

    1.   Three of the reported units  have  had  the  M.A.N.
         system,  which  is  the  system  that  uses bristle
         brushes; and the other 51 units  had  or  have  the
         Amertap  System,  which  is  the  system  that uses
         sponge balls.

    2.   None of  the  three  M.A.N.  systems  is  still  in
         service.   One  of  these  systems tended to become
         fouled by leaves and twigs - and even a  few  fish.
         On another, severe grooving of tubes was found.

    3.   Of the 51 Amertap  units  reported,  46  units  are
         still in service.
                           272

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                   NORMAL FLOW PIPING


                   BACKWASH  PI OW PIPING
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SECTION OF
CONDENSER BEING
BACKWASHED

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                                Figure A-VII-15    Reverse Plow Piping     387

-------
    4.   Of the 46 Amertap units now in service 25 also  use
         chlorination, and 21 do not use chlorine.

    5.   For the  21  Amertap  Systems  in  service  without
         chlorination the cooling water systems are:

         Acid mine-water, once-through, 9 systems
         Closed cycle cooling towers or ponds, 6 systems
         Brackish water once-through, 2 systems
         Sea water once-through, 2 systems
         Fresh water once-through, 2 systems

    6.   Of the 51 Amertap units  reported by respondents, 7
         reported that they thought good heat transfer could
         be maintained without chlorination and  6  reported
         they think chlorination is necessary.

    7.   For the 46 Amertap units now  in  service,  it  was
         reported  that the primary purpose of the mechnical
         cleaning system was for the control of:

              a.  sediment, sludge or scale, for 41 units
              b.  slime for 5 units

    8.   Of the five  (5)  systems that are reported to be  in
    service  for  the purpose cf controlling slime, only one
    (1)  uses once-through cooling with fresh water, and  the
    other  four   (4)  use once-through cooling with brackish
    water.

    9.   Of these five (5) systems that are reported to be in
    service for the purpose of controlling  slime,  two  (2)
    also  use  chlorination,  and  one of the others has had
    only limited operation.

Mechanical Cleaning During Scheduled Outages

Manual   mechanical   cleaning   of   condenser   tubes   is
accomplished  with  short  bristle brushes, rubber balls, or
scraper devices shot through the tubes individually by water
pressure or  combined  with  air  pressure.   High  pressure
water   lancing   alone  has  been  used.   The  procees  is
laborious, time-comsuming, extremely monotonous,  and  often
uneconomical.

If  the  deposition in the tubes is loose, or in thin curls,
after the tubes become dry, the brushes or balls will  do  a
fairly  satisfactory  job.   Brushes  or  balls  are used by
plants that need to clean tubes  at  repeated  intervals  to
maintain  cleanliness.  When the desposition is adherent the
                         274

-------
short metal scraper-type devices  will  be  more  effective;
they are shot through the tubes with water and air pressure.
The  overall shooting time will be longer with scrapers than
with brushes.  Regardless of the device used it  is  a  good
idea  to  keep  an  inventory of the number before and after
cleaning.  The mechanical cleaning time will range  from  50
tubes  to  300  tubes  per  man-hour  depending  on  whether
scrapers or brushes are used and  on  the  attitude  of  the
crew.

As  a  rule,  mechanical  cleaning  is  practiced  at  small
generating plants where the labor may be  readily  available
and  economical.   It  may  also  be  a  plant where quality
control for the cooling system is  continuously  disregarded
by  the  operating  personnel,  requiring that the condenser
tubes be mechanically cleaned  fairly  regularly.   In  this
case,  plant  labor  would  be used instead of using outside
services  for  chemical   cleaning   which   would   require
management appropriation of capital.

Economics of Condenser Cleanliness

Comparative  capital  costs  of  the  Amertap system and the
M.A.N. system are shown in Table A-VII-8  As  noted  on  the
table,  the  costs  shown are additional costs to those that
would be required for  conventional  chemical  conditioning.
The  costs  are for a 675 Mw generating unit to be installed
in 1979 which will be equipped with  an  open  recirculating
cooling system using mechanical draft cooling towers.

Table A-VII-9 shows comparative costs of operation and total
annual  costs  for  the  same  675  Mw generating unit.  The
demand and energy costs reflect increased circulating  water
pumping  costs for the mechanical systems due to friction of
the plastic cages of the M.A.N. system, and of the strainers
of the Amertap system.  For the  Amertap  system  they  also
reflect   the   cost  of  operating  the  small  pumps  that
recirculate the balls.  The  annual  fixed  charge  rate  is
assumed to be 15.0 percent.

As   tube  cleanliness  decreases,  the  condenser  pressure
increases which causes the turbine heat rate to increase and
generating cpability to  decrease.   Figure  A-VII-16  shows
tube  cleanliness  factor plotted against the annual cost of
increased fuel and reduced capability for the  same  675  Mw
unit.   The unit is assumed to operate at an annual capacity
factor of 86.5 percent, fuel is evaluated at a price  of  45
cents  per million Btu, and generating capacity is evaluated
at an annual cost of $20.80 per kw.  The  costs  plotted  in
Figure  A-VII-16  are  additional  costs  as the cleanliness
                         275

-------
                           Taole  A-VII-8
                     COMPARATIVE CAPITAL COSTS* OF CONDENSER
                     CLEANING SYSTEMS   387
                                                                                      Table  A-VII-9

                                                                                   COMPARATIVE ANNUAL COSTS*    387
ro
^i
en
M.A.N System, Baskets and Brushes
Amertap System
Tubing
Tube Sheet Machining
Backwash Piping and Valves
Miscellaneous Piping and Valves
Controls
Mechanical Construction
Electrical Construction
General Construction
     Subtotal
Indirect Costs at 16 Percent
Comparative  Capital Costs*
Amertap
System
$
-
160,000
Base
Base
Base
10,000
35,000
34,000
22,000
8.000
269,000
43.000
312,000
M.A.N.
System
$
72,000

1,000
(37,000)
107,000
Base
6,000
12,000
3,000
Base
164,000
26,000
190,000
Annual Costs of Operation*
     Manual Brush Cleaning of Tubes
     Chemicals
     M.A.N. System Brushes
     Amertap  Balls
     Demand and Energy Costs

     Comparative Costs of Operation

Total Annual Costs*
     Fixed Charges
     Costs of Operation
     Comparative Total Annual Costs
     Differential Total Annual Costs
Conventional
Chemical
Treatment
$
5,000
23,000
-
-
Base
28,000
Base
28,000
28,000
Base
Amertap
System
$
-
20,000
-
19,000
6,500
45,500
46,800
45,500
92,300
64,300
M.A.N.
System
$
-
20,000
16,000
-
12,100
48,100
28,500
48.100
76,600
48,600
            'Costs shown are increases or (decreases) from capital costs of a conventional  'Costs are for a 675 MW generating unit to be installed in 1979, operating with an open
            chemical cleaning system. Costs are for a 675 MW generating unit to be       recirculating cooling system using mechanical draft cooling towers. Annual fixed charge
            installed in 1979, operating with an open recirculating cooling system using    rate is 15.0 percent.
            mechanical draft cooling towers.

-------
           GENERATING UNIT  - 675 HW
           FUEL COST - $ 0.45 PER I06 BTU
           CAPACITY COST -  $21.80/KW/YEAR
           ANNUAL CAPACITY  FACTOR -86.5*
         70          80

     CLEANLINESS FACTOR IN PERCENT
         Figure A-VII-16
TUBE  CLEANLINESS VERSUS  COST  OF REDUCED
GENERATING EFFICIENCY  387

   277

-------
factor  decreases  from  100  percent  (which  reflects  the
cleanliness of new clean tubes).

Costs  of  operation shown in Table A-VII-9 are based on all
cleaning systems maintaining the same degree of cleanliness.
It is expected that the Amertap  system  can  maintain  tube
cleanliness  at  about 95 percent, if placed in service when
the condenser tubes are new, and that the M.A.N. system  can
maintain  tube  cleanliness at about 90 percent.  The reason
that the M.A.N. system would not be  able  to  maintain  the
cleanliness  level as high as the Amertap system is that the
M.A.N. system operates  intermittently,  while  the  Amertap
system is a continuous cleaning system.

The  comparative  annual costs shown in Table A-VII-9 and on
Figure A-VII-16 can be used to determine whether  or  not  a
mechanical  cleaning system such as the M.A.N. system or the
Amertap system can be economically justified.  For  the  675
Mw  unit,  neither a M.A.N. system with a cleanliness factor
of 90 percent nor an Amertap system with a cleanilness of 95
percent could be justified  unless  the  cleanliness  factor
with  conventional  chemical  conditioning  is  less than 80
percent.  This conclusion applies only to the  case  studied
since  it is dependent on such parameters as generator size,
capacity factor, and the fuel cost.  However, it serves as a
general  indication  of  the  amount   of   improvement   in
cleanliness factor that must be achieved in order to justify
an on-line mechanial cleaning system.

Design for Corrosion Protection

The   use  of  corrosion  resistant  materials  is  standard
practice in the  electric  utility  industry.   Unlike  most
other  industries,  power plants are -built for service lives
of thirty years or more.  Thus, corrosion  prevention  is  a
necessary  consideration  in  power  plant  cooling systems.
Although corrosion  resistant  materials  are  more  costly,
their  use  is  justified by less maintenance, improved heat
transfer, and reduced water treatment costs,  corrosion  and
scale  inhibiting  chemical  usage can be minimized in large
cooling  water  systems  through  the  proper  selection  of
construction  materials  and  protective coatings.  In fact,
there  are  a  few  power  plants  where  the  existence  of
corrosion  resistant  materials  plus  the  use  of  on-line
condenser tube cleaning equipment has  eliminated  the  need
for  chlorine  and  other  biocides, thus allowing operation
without any chemical treatment.

In addition, corrosion resistant  materials  generally  help
prevent  water pollution.  By minimizing corrosion and scale
                         278

-------
inhibiting chemical usage, the anrounts of harmful  materials
such  as zinc and chromate discharged into lakes and streams
are reduced.  Corrosion products  in  blowdown  streams  can
also be maintained at low levels.

Corrosion Resistant Materials in Condensers

The  use of corrosion resistant materials in steam condenser
tubes is standard practice.  A wide variety of materials are
in use or are available including  admiralty,  304  and  316
stainless steel and copper-nickel alloys.

Cold   water  boxes  are  normally  made  of  carbon  steel.
Occasionally, phenolic or epoxy coatings are applied.

Corrosion Resistant Materials in Cooling Towers

Although  redwood  or  Douglas  fir  are  still  the  normal
structural elements used in mechanical draft cooling towers,
concrete  towers  are  now  being built.  All the hyperbolic
natural draft cooling towers built in the United  States  to
date  have  been  of concrete construction.  Concrete towers
should last longer, are structurally superior  to  wood  and
can  save  utility companies on fire insurance preminums.  A
cooling tower manufacturing recently mentioned that a client
could save $100,000/year  on  insurance  premiums  by  using
concrete induced-draft cooling towers instead of wood.

Type  2  concrete  is  normally used for cooling towers, but
where waters containing 1,000 ppm or  more  of  sulfate  ion
(SO£—)  are  encountered such as in the West and Southwest,
Type 5 must be specified.

The use of wood in the internals of large cooling towers  is
also diminishing.  Plastics such as polyvinyl chloride  (PVC)
are  now  being  used  for  splash-type  tower  fill,  drift
eliminators, and fill hangers.  Film-type fill  is  normally
made  from  asbestos  concrete board  (ACB).  Air louvers and
some drift eliminators are also made of ACB.   When  ACB  is
used  in a tower, it is important to maintain cooling system
pH at more than 6.0 to avoid deterioration.

Hardware used in  cooling  tower  construction  is  normally
stainless steel, although hot dipped galvanized steel, naval
brass, copper alloys and silicon-bronze can also be used.

Stacks  in  mechanical  draft towers are generally made from
fiberglass reinforced plastic  (FRP).
                       279

-------
Redwood stave piping is being  used  less  frequently  since
redwood  is becoming more scarce.  Risers and headers, which
are large pipes located at the cooling towers, are  made  of
concrete  or  redwood  staves,  and less frequently of vinyl
painted carbon steel.  Where brackish or salt water is  used
for  tower  makeup,  316  stainless  steel and coated carbon
steel are commonly specified for piping systems.

Concrete and stainless steel cost 2-3 times more than carbon
steel.   Cost  differences  between  stainless   steel   and
prestressed  reinforced  concrete will depend on differences
in material grade, freight charges and installation costs.

Most power companies do not make detailed  cost  comparisons
between  piping  materials,  but one Ohio utility determined
that for a new power  plant,  concrete  recirculation  lines
would cost about $300,000 more than coated carbon steel.


Spray  cooling apparatus is normally constructed with 301 or
316 stainless steel.  Cathodic protection devices have  been
installed en some floating spray aerator-coolers.

Resistant Pretreatments and Coatings

Redwood  and  Douglas  fir  construction  materials  used in
mechanical draft cooling towers are always pressure  treated
with   either  acid  copper  chromate  or  chromated  copper
arsenate to prevent fungus  attack.   Tower  suppliers  have
indicated  that  this  pretreatment  is  effective  and that
leaching of the treatment chemical does not occur after  the
initial few weeks of tower operation.

Since  chemical  pretreatment  of  cooling tower lumber is a
necessary process, its costs has not been separated from the
total purchased cost of tower systems.

Carbon steel pipe and hardware  are  sometimes  coated  with
epoxy,  phenolic, or vinyl paints to reduce corrosion rates.
Steel piping is occassionally given a  coal  tar  bitumastic
coating  on  the  inside  to  prevent corrosion.  Bitumastic
coatings may also be applied to  the  outside  of  pipes  to
prevent  leakage  and  corrosions.   These coatings normally
cost $20 - $UO/ft of pipe length.

Saltwater Cooling Towers

Reference 390, a  state  of  the  art  report  on  saltwater
cooling   towers,   addresses,  as  a  major  topic,  design
consideration related to the corrosive action of salt  water
                          280

-------
on  cooling system equipment.  The incremental deterioration
due to corrosion effects of  salt  water  being  used  in  a
cooling  tower  is  of  the  same  nature  as those expected
elsewhere in the plant where this water is being circulated.
With  well-designed   and   constructed   components   where
coatings,  lubricants  and when possible inert materials are
used, most of the problem associated with the  use  of  salt
water can be reduced to make the average life the components
equivalent to those exposed to fresh water.

Table  A-VII-10 gives recommended construction materials for
cooling towers operating with salt water.   Chemicals  added
to  reduce  chemical  and  biological  attack  in  saltwater
cooling  towers  include  the  following:   sulfuric   acid,
chromate,  zinc  compounds,  organic non-chromates including
polyphosphates,  silicates,  ferrocyanides,  nitrates,   and
metal    ions    (e.g.,   straight   polyphosphates,   zinc-
polyphosphates,      ferrocyanide-polyphosphates,      zinc-
ferrocyanide-polyphosphates),  organics  (starch derivations,
lignosulfonates, tannins, glucosates, glyceride  derivations
and many proprietary formulations), chlorine and bromine.

Reference 390 lists 20 saltwater cooling towers in operation
as  of  February,  1973,  and  <* proposed towers.  Of the 15
towers associated with electric generating  station  10  are
mechanical  draft,  4  are  natural draft, and 2 are wet-dry
mechanical draft.  Circulating water flow rates for  the  15
towers range from 4,900 gpm to 578,000 gpm per tower.

Cooling Tower Blowdown Treatment

A  system for the chemical treatment of residual chlorine in
cooling tower blowdown is currently  being  installed  in  a
nuclear  plant  employing cooling towers, which is currently
under construction.  Whenever residual chlorine  is  present
in  the  combined wastes flowing from the discharge channel,
sodium bisulfite will be added in the last  chamber  of  the
dilution   structure   in   sufficient   quantity  to  react
completely with the chlorine.   The  addition  of  bisulfite
will  be controlled automatically, using a chlorine analyzer
in the discharge stream with a proposed sensitivity of about
0.01 ppm residual chlorine.

Specific  methods  exist  for  treating   other   individual
contaminants  that  may  occur in fclowdown wastes.  Table A-
VII-11 lists typical levels of  concentration  of  corrosion
inhibitors used in recirculating cooling water systems, with
these  same  concentrations  existing  in  the blowdown from
these systems.
                         281

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                                       Table  A-VII-10
                  RECOMMENDED CONSTRUCTION MATERIALS FOR COOLING TOWERS
                                 OPERATING WITH SALT WATER
                                  Reference 390
Component
              Asbestos
               Cement
                      Plastics
                      (Including
            Coating   reinforced
 Concrete   Paint or  fiberglass
No. 2 or 5*  Epoxy    and PVC)
Stainless
 Steel
Silicon
Bronze
Pressure-
Treated
 Wood
Structure
 framework       x

Water distri-
 bution system    x

Fill             x
Drift eliminators x

Louvers          x

Fan stack

Fans

Gear housing

Drive shaft
Coupling

Motor and gear
 support

Bolting for
 mechanical
  support

Joint connectors

Anchor castings

Bolts, nuts,
 washers & nails
                          x

                          X

                          X

                          X

                          X
                         X**

                         X**
                                     X

                                     X

                                     X
                                     X

                                     X
                                                 X

                                                 X
    * Used by cooling tower manufacturers

   **Uaed successfully when tower is in continuous operation.
                                 282

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                  Table A-VII-11

          Waste Disposal Characteristics
    of Typical Cooling Tower Inhibitor Systems
Inhibitor
 System
Organic only
Concentration in
 recirculating
     water
Chromate only
Zinc
Chromate
Chromate
Phosphate
Zinc
Phosphate
Zinc
Phosphate
Phosphate
Organic
200-500
8-35
17-65
10-15
30-45
8-35
15-60
8-35
15-60
15-60
3-10
as
as
as
as
as
as
as
as
as
as
as
Cr04
Zn
Cr04
Cr04
P°4
.Zn
P04
Zn
P°4
P°4
organic
100-200 as organic
 10 est. as BOD
100 est. as COD
 50 est. as CCl
 extract
  5 est. as MBAS
Organic
Biocide
 30 as chl'or9phenol
  5 as sulfone
  1 as thiocyanate
                     283

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There are four methods  which  can  be  used  to  treat  the
blowdown  wastes  containing chromate as the only inhibitor.
One basic method that has worked in the past  and  has  been
proven  effective  is  called  the  reduction  method.  This
process consists of adjusting the pH of the  blowdown  water
containing the chromium to approximately 2 with the addition
of  acid,  usually sulfuric acid, and then the addition of a
reducing   agent,   either   sulfur   dioxide   or    sodium
metabisulfite,   which  releases  sulfur  dioxide  into  the
solution to reduce the hexavalent chromium to the  trivalent
state.  Then the addition of caustic or lime to raise the pH
to  approximately  8.5  and form insoluble chromic hydroxide
precipitate.  A treatment system using the reduction  method
is  shown  in  Figure A-VII-17.  The treated water from this
system is anticipated to  contain  less  than  0.05  ppm  of
chromium.   ion exchange methods have also been reported for
chromate  recovery  from  blowdown   wastes.*33-436    These
methods  require  a  prefiltration  step to remove suspended
solids from the blowdown wastes and  also  require  a  close
control  on  the inlet pH and salt concentration for maximum
recovery.  The advantage of the ion exchange methods is that
the recovered chromate can be reused.   Another  method  for
chromate  removal  is  the  ANDCO proprietary process.  This
patented process is an electrochemical method (Figure A-VTI-
18) and is claimed to reduce chromate concentration to  less
than  0.05  ppm.   Finally,  a vapor-compression evaporation
system is also commercially available to recover  and  reuse
water  from  blowdown  wastes.   The concentrated brine from
this system can be sent to a spray-dryer for the final  salt
recovery.

All the methods mentioned above are also applicable for zinc
removal  from  blowdown  wastes.   Thus  it  is  possible to
coprecipitate zinc as an  insoluble  hydroxide  by  chemical
precipitation.

Similarly,  it  is  possible to use an acid regenerated zinc
cation exchange process so effect a reduction in  volume  so
that  the  concentrated  solution  can  be  "hauled  away or
rendered harmless by precipitation11*3*.  The  ANDCO  process
is also claimed to reduce zinc from blowdown wastes.

Phosphate  can  also  be  removed by chemical precipitation.
Addition of alum is  required  for  higher  efficiency.   An
adsorption  process that apparently is applicable to crudely
filtered or undiltered blowdown containing phosphate,  only,
has been reported in the literature.

Depending  upon  the  make-up  water  quality  and the plant
specifics,   it   is   possible   to   investigate   various.
                          284

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r\j
CD
01
                                              BX-OWDOVS/tO PUMPS
                                  R.EDUCT\OK1

                                    TA.VJK.
A.CID WMX.

     K>



      VACUUVA FILTER,





        COWV.
                                                     II
         Figure  A-VII-17       Cooling Tower Slowdown  Chromate Reduction System
                                                                                      457

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   POWER
   SOURCE
              -©
        © © ©
                                          SLUDGE
AM  AMMETER

VM  VOLTMETER

Fl  FLOW INDICATOR

TI  TEMPERATURE INDICATOR


PI  PRESSURE INDICATOR
           MTENTJ .SSIM .NO «.*.!» «>
 TYPICAL PROCESS FLOW DIAGRAM
ANDCO CHROMATE REMOVAL SYSTEM

  cinclco<&
  andco environmental processes, inc.
               buffalo, new york
                    Made under U.S. and foreign patents and patents pending.
                    Figure A-VII-18

           Typical  Process Flow  Diagram
           Chromate Removal  System  453
         286

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alternatives  methods  to  select  the  most  practical  and
economic method to minimize  blowdown  flow.   The  Southern
California  Edison  company  has achieved a 31X reduction in
the  cooling  tower  blowdown  at  the  Etiwanda  generating
station by modifying the treatment technique.4*0  Similarly,
the  company  has  included facilities in a new plant design
for cold lime-soda  as  makeup  softening  to  achieve  zero
blowdown  operation  (Figure  A-VII-19).   This  will reduce
total pondage requirements  from  240  acres  to  3U  acres.
(Pondage  is  required  for softening sludge disposal, other
plant liquid wastes and for periods of  softening  equipment
outages   when   blowdown   from   cooling  towers  will  be
necessary) .

Reference  UU5  analyzed  four  basic  approaches  for   the
concentration  of  cooling tower blowdown to a dry or almost
dry, solid as follows:

    Evaporation, in a conventional multi-effect  evaporator-
    crystallizer,  to  a  slurry from which mother liquor is
    finally removed by a centrifuge, yielding damp crystals.

    Preliminary distillation in a  multi-stage  flash  (MSF)
    plant,  followed  by an evaporator-crystallizer somewhat
    smaller than in the first approach.

    Passage of the tower blowdown through a cation exhanger,
    plus reverse osmosis (R.O.), followed by an  evaporator-
    crystallizer of larger size than in the second approach.

    Identical  with the third approach but with an MSF plant
    after the R.O. unit, resulting in  a  small  evaporator-
    crystallizer of only one effect.

In  each of the cases involving MSF, two types of MSF plants
were studied: (1) a high-capital cost plant, very  efficient
in  energy  utilization,  and  (2) a less efficient but less
costly plant.

The various combinations of processes are shown in Figure A-
VII-20.

Water Treatment Wastes

Clarification, Softening and Filtration

The waste streams from these operations are  sludges,  whose
composition will vary depending on the raw water quality and
the  method  of treatment.  Sludges from plain sedimentation
are essentially silty in character.  If alum is  used  as   a
                        287

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ro
oo
CO
                                        C.O C.O »;,C%4l,fci
                                         P  P  t    P  P  P
                                                                                            cotL stuter
                                                                                           CLAeirLOlCULATOg.
                                                                                                                        TB tiona.   440

-------
ro
00
                     COOIINC TOWU t
                        IDENIICAl foil All CASES.
                        PRODUCES INSOLUBLE SOLIDS
                        (OR DISPOSAL
                                                          CONCENTIATION
                              IWOUTKHI • CITSTAUIZATIOR
                               TWO POSSIILE PROCESSES AVAILABLE.
witn sotws
TO ttsrosu
THREE POSSIBLE ALTERNATIVES. PLUS DIRECT
FEED TO EVAPORATOR • CRVSTALLIZER.
              Figure  A-VII-20    Possible Combinations of Concentration and Evaporation-
                                     Crystallization Processes for Complete Treatment  of
                                     Cooling Tower  Slowdown

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coagulant,  the  sludges  will  contain  aluminum  hydroxide
together with whatever organic or  inorganic  colloids  have
been  coagulated  by  the alum.  Sludges from lime softening
contain  primarily  calcium  and  magnesium  carbonates  and
hydroxides.  Sludges from filter backwash operations reflect
the  processes  that  preceded the filter and differ only to
the extent that filter  backwash  is  generally  a  periodic
operation, whereas sludges from setting basins are withdrawn
more or less continuously.

Sludges  will generally contain between 0.5 and 5.0% of sus-
pended solids.  Accepted treatment techniques in  the  water
and  wastewater  treatment industry consist of hydraulically
thickening these sludges to about 10 to 15% solids  content.
Following  thickening,  the sludges can be further dewatered
by   land   disposal,   centrification,    filtration,    or
incineration.   Figure  A-VII-21 shows three clarifier waste
systems.   The  supernatent  from   sludge   thickening   is
generally returned to the original solids separation unit.

Ion Exchange Wastes

Ion  exchange resin beds must be regenerated periodically in
order to  maintain  their  exchange  capacity.   For  cation
resins,  the  most  common regenerant is sulfuric acid.  For
anion resins, the common regenerant is sodium hydroxide, al-
though ammonium hydroxide is used  in  some  plants.   Since
powerplant practice is to use excess amounts of regenerants,
the waste streams contain primarily sulfuric acid and sodium
hydroxide,  together  with  the  ions removed from the water
during the exhaustion cycle.  The waste stream also includes
rinse water, that is water passed through the resin beds  to
remove  all  traces  of  regenerant.  Typical practice is to
regenerate  ion  exchange   units   whenever   a   specified
exhaustion  has been reached while the units are in service.
Figure A-VII-22 shows a simplified flow system.

Waste regenerants and rinses from both the cation and  anion
resins  are  normally collected in a neutralization tank and
the pH is then adjusted to within the range of 6.0 to 9.0 on
a batch basis by the addition of  sulfuric  acid  or  sodium
hydroxide as required.  If any precipitates are formed after
neutralization,  they  are  separated  from  the  liquid  by
settling  or  by  filtration.   Figure  A-VII-23   shows   a
neutralization pond.

The  neutralized  wastes  are  high in TDS and would require
further treatment before they could be used for other  water
uses  requiring  low  TDS water.  However, they are suitable
for use as makeup for closed condenser  cooling  systems  or
                       290

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                      CLEAR WATER OVERFLOW TO RECYCLE
   RAW
   WATER  ,
            CLARIFIER
                                    WASH
               '',   *
FI.LTE'R
SYSTEM
                            n
      WATER TO
      PROCESS
             "
                      SLUDGE
THICK-
ENER
                       SLUDGE
                                                           MECHANICAL
                                                           DEWATERING
                            OVERFLOW TO RECYCLE
      RAW
      WATER
               CLARIFIER
WMj>n
I

i f
FILTER
SYSTEM
i

WATER T(
, PROCESS
                      SLUDGE DISCHARGE
                                                              MOIST SOLIDS
                                                               DISPOSAL
                                         SLUDGE SETTLING
                                              POND
                       OVERFLOW TO RECYCLE
 RAW
WATER
          CLARIFIER
                      WATER TO PROCESS
                 SLUDGE DISCHARGE
                                    SLUDGE SETTLING
                                         POND
                               MECHANICAL
                             SOLIDS REMOVAL
                                                    MECHANICAL SOLIDS
                                                         REMOVER
         FIGURE A-VII-21CLARIFICATION WASTE TREATMENT PROCESSES
                           291

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  AC ID ADJUSTMENT
CAUSTIC ADJUSTMENT
ION EXCHANGE WASTE
                                RECIRCULATE
DISCHARGE
                    NEUTRALIZATION
                         TANK
   FIGURE A-VII-22 ION EXCHANGE WASTE TREATMENT PROCESS
                         292

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NEUTRALIZATION POND
     Figure A-VII-23
         293

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for such uses as ash sluicing or gas scrubbing, which do not
require high quality sources of supply.  It may be desirable
for  some  uses in the powerplant to use ion exchange wastes
without  neutralization.   Closed  cooling   water   systems
generally  require some acid treatment to reduce the buildup
of alkalinity and air pollution control devices may  require
an  alkaline  source of water.  Ion exchange waste therefore
can often form an economical source of  low  grade  acid  or
caustic for other uses in the plant.

Substantial reductions in the volume of demineralizer wastes
can  be  achieved  by  the  use  of systems which substitute
reverse osmosis (RO) or electrodialysis  combined  with  ion
exchange  (IE)  for  systems  using ion exchange alone.  One
study shows that RO plus IE systems are less costly than  IE
systems  alone  for  total  dissolved  solids of 500 mg/1 as
CaCO.3 in the natural water available.  The study is based on
100,000 gallons/day product capacity, no labor costs, and  a
waste disposal cost of $5/1000 gallons.383 A 250. gpm product
capacity  RO system has been recently installed at plant no.
5405.  The available water total dissolved solids  level  is
750  mg/1  as  CaCO.3.   The system is designed to reduce the
dissolved solids level of  pretreated  river  water  to  the
range  for  which  the conventional resin-bed deionizers are
designed.38*

Evaporator Slowdown

In those  plants  still  utilizing  evaporators  to  produce
boiler  feedwater  makeup,  the blcwdcwn from the evaporator
contains  the  salts  of  the  original  water   supply   in
concentrated  form,  but  generally  still  in  the solution
phase.   Treatment  is  similar  to  the  treatment  of  ion
exchange  wastes by adjusting the pH to the neutral range of
6.0 to 9.0 with  sulfuric  acid  or  sodium  hydroxide.   If
precipitates  are  formed  during  neutralization, these are
removed by sedimentation and filtration.

As for ion exchange wastes, the  most  desirable  method  of
disposal  is  by reuse within the plant for applications not
requiring low TDS sources of supply.

Boiler or PWR steam Generator Slowdown

Since the quality of the boiler feedwater must be maintained
at very high levels of purity, the blcwdown from these units
is generally of high quality also.  Boiler  blowdown  seldom
exceeds 100 mg/1 TDS and in most cases is as low as 20 mg/1.
For  most  plants,  the  quality  of  the boiler blowdown is
better than the quality of the raw water supply, whether  it
                          294

-------
be  from  a natural source or a municipal water system.   The
most desirable reuse of  boiler  blowdown  is  therefore  as
makeup to the demineralization system.

Boiler blowdown is usually slightly alkaline, but because of
the   low   TDS   level,   the   pH  changes  very  readily.
Neutralization is generally not necessary  for  any  of   the
forms of reuse previously discussed in this section.

Periodic Wastes

Maintenance Cleaning Wastes

All heat transfer surfaces require periodic cleaning and the
usual method of cleaning boiler tube internals is to contact
these  surfaces  with  solutions  containing chemicals which
will dissolve any scale or other deposits on these surfaces.
Cleaning operations utilizing water include cleaning of   the
fire  side  of  boiler tubes, the air preheater, the cooling
water side of the condenser, and  other  miscellaneous  heat
exchange equipment.

Modern  steam  generators  do not permit inspection of areas
most likely to be in distress due to internal deposits,   nor
can they be cleaned mechanically.  Hence, the only practical
and  generally  accepted  method  of cleaning is by chemical
means.377

Boiler cleaning wastes pose special  problems  of  disposal.
In  order  to  be effective, the chemicals used for cleaning
must form soluble compounds with the scale and  deposits  on
the  surfaces to be cleaned.  Since scale is evidence of the
precipitation  of  an  insoluble  compound,   the   cleaning
solution  must  somehow  change  that  solubility.  The most
common means of accomplishing this objective is by  extremes
of  pH  and  strong  oxidation  potential.   Where acids are
utilized as cleaning agent, there is the additional  problem
of metals being dissolved into the cleaning solution.

Cleaning   of   heat   transfer  surfaces  is  a  relatively
infrequent operation.  The rate of deposition determines the
frequency.  However, no.general agreement exists as  to  how
to determine when the point has been reached which calls for
cleaning.    Most   operators  clean  on  a  time  schedule,
frequently established by trial and error.   A  majority  of
those  that  do  not  clean  on  a time schedule remove tube
sections to gauge the amount of deposition.377  Boilers  are
usually  cleaned  not  more than once per year.  Some of the
auxiliary units may  be  cleaned  twice  a  year.   Cleaning
operations are scheduled in advance in order to minimize the
                          295

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effect  of  the outage on the ability of the utility to meet
the demands for electric power.

Powerplants use essentially two types of cleaning solutions.
One type is an  acid  solution,  usuallly  hot  hydrochloric
acid,  used  to  clean  the  water side of the boiler tubes.
Hydrochloric  acid  cleaning  is  the  cheapest   and   most
effective  of  the  cleaning  methods, but requires a larger
volume of water and  takes  longer  than  methods  employing
other chemicals.  Citric and phosphoric acids are also used,
primarily   because  they  involve  less  outage  time  than
hydrochloric  acid.   Fireside  cleaning  of   boilers   and
cleaning  of  air  preheaters is accomplished using alkaline
solutions, primarily containing soda ash.

Many utilities discharge their cleaning  wastes  with  once-
through   condenser  cooling  water,  relying  on  the  high
dilution ratio to minimize adverse effects of the discharge.
some utilities collect spent cleaning solutions  in  storage
basins  or ash ponds and adjust the pH to the neutral range.
This causes the precipitation of some of  the  less  soluble
compounds.   The  supernatent is discharged to the receiving
water and the solids are removed from the  basin  when  this
becomes  necessary.  This technique is followed at plant no.
2525, which neutralizes its cleaning wastes before discharge
to a large settling pond.   Plant  no,  3601  also  collects
cleaning  wastes in a storage basin, applies lime or caustic
for neutralization, and then discharges the supernatent.

Current control and treatment technology for cleaning wastes
involves segregation of the  waste,  chemical  treatment  to
bring  the  pH into the neutral range, and separation of any
precipitates resulting from the neutralization.


Ash Handling Wastes

Most of the coal-fired plants use ash ponds.  The data  from
existing ash settling ponds was reviewed in Part A Section V
of  this  report.   Of  the plants for which useful data was
obtained, 28% have a negative or zero net discharge of total
suspended solids from the ash pond.   For  example.  Federal
discharge permit applications for four of these stations are
given  in  Table  A-VII-12.  The data of one of these, plant
no. 0107, were verified by analyses of samples taken at  the
site  by  EPA personnel.  These data are summarized in Table
A-VII-13.

Sedimentation lagoons are commonly used  at  steam  electric
powerplants,  however,  some plants employ configured tanks.
                          296

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                                     Table  A-VII-12
                                ASH  POND PERFORMANCE


                      Source: Federal discharge permit applications
Plant No.

0104
0105
0106
0107
Concentration
Plant Intake
31
35
10
13
Total Suspended Solids, mg/1
Effluent
22
6
3
10
ro
10

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                                          Table  A-VII-13



                SUMMARY OF E.P.A.  DATA VERIFYING ASH POND PERFORMANCE,  PLANT NO0 0107
Location
Intake
Inlet to Ash Pond
• from fly ash
• from bottom ash
Ash Pond Discharge
TSS
mg/1
22

76,440
4,110
14
pH
6.3

4.4
5.6
4.3
Aluminum*
mg/1
0.7

1100
56
6.0
Chromium*
mg/1
<0.04

1.3
0.1
< 0.04
Copper*
mg/1
< 0.04

501
0,3
0.1
Iron*
mg/1
0.5

2500
112
0.6
Mercury*
mg/1
<0.04

0.1
< 0.04
< 0.1
Zinc*
mg/1
<0.05

2.8
0.1
0.1
ro
10
oo
      * Note: Total

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Tanks can be used where  space  limitations  are  important.
Tanks  constructed  for solids removal usually have built-in
facilities for continuous or  intermittent  sludge  removal.
Designs  based  on  maximum flow anticipated can provide the
best performance.  Equalization can be provided to  regulate
flow.   The  retention  time  required  is  related  to  the
particle characteristics.  Plant No. 3905 employs a settling
basin 250,000 sq ft  x  5  ft  deep  to  provide  a  minimum
retention  time  of  24 hours for a waste stream of normally
1,800 gpm (3,300 gpm maximum).  The ash pond is 600 acres in
area and will contain 6,700 acre ft.  coal used at the plant
is pulverized to a size passing 80  percent  through  a  200
mesh  screen.   Approximately  80  percent  of  the  ash  is
discharged as fly ash.  No cooling water  is  discharged  to
the  ash  pond.  The distance from inlet to outfall is about
one mile.  The narrow water  stream  in  the  pond  meanders
through  the  settled ash piles.  The reported flow is about
500 gpm.

Nine out of the ten fossil-fueled steam electric powerpiants
operated by the Tennessee Valley Authority use ash ponds for
both fly ash and bottom ash, as  well  as  for  other  plant
wastes  such as from boiler cleaning.  Effluent samples from
these ponds have been  taken  quarterly  over  a  period  of
several  years.   Analyses  were  performed  and reported on
numerous parameters including total solids, total  dissolved
solids  and turbidity.  Total suspended solids values can be
inferred as the difference between total  solids  and  total
dissolved solids.  A total of 1297 effluent suspended solids
sample  values  were  tabulated for 10 plants in the system.
Of tnis total, 1,151 values  were  less  than  100  mg/1,  4
samples  were  exactly 100 mg/1 and only 146 values exceeded
100 mg/1.  On a percentage basis, values equal to,  or  less
than,  100  mg/1  represented approximately 89% of the total
number of values reported.  The 951 value for the  total  of
the  1,297  samples was 165 mg/1.  Table A-VII-14 summarizes
the data from the 10 plants in the system.

An  analysis  of  the  data  indicates  that  the   effluent
suspended  solids  values  reported  for Plant No. 2119 were
generally higher than the results reported for the  other  9
powerplants  in  the  system.   of  the  total number of 146
samples which were equal to, or exceeded 100 mg/1, 106  were
reported by plant No. 2119.  Consequently, it was decided to
analyze  the  data, omitting the results from this plant, to
determine the percentage of values exceeding  100  mg/1  and
the 95X value for the other 9 plants.  This analysis yielded
                            299

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    Table A-VII-14
  ASH POND EFFLUENT, TOTAL
   SUSPENDED i'OLID'J, MG/L
Plant No.
and Ash
Pond
2119-P1
4701
4704
4704
4703
4705,-North
0111
2119-P1
4701
2119-P1 -
4702
4705-South
6, 4702
2119-P1
2119-P2
2120
4706, 0111
& 0112
2119-P2
2119-P2
2119-P2
Flow
Rate
in GPM
1,500
1,700
3,000
3,300
4,000
4,500
5,000
6,000
6,500
7,000
7,200
7,500
9,000
12,000
13,000
14,000
15,000
20,000
25,000
Suspended
Solids for
95ti of
Samples ng/1
899 or lower
65 or lower
39 or lower
36 or lower
38 or lower
71 or lower
86 or lower
195 or lower
87 or lower
184 or lower
222 or lower
56 or lower
309 or lower
305 or lower
22 or lower
61 or lower.
205 or lower
72 or lower
205 or lower
No. of
Samples
Considered
48
45
41
48
31
37
36
41
45
12
47
41
47
41
49
47
47
12
48
Median
Value
in r,'.q/l
128
41
14
13
10
15
31
62
42
106
57
13
64
70
16
15
53
22
51
Aver;u;e Value
of 95% of
Samples
176
23
16
14
14 '
20
40
72
42
109
66
16
167
88
21
19
76
30
74
360

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the following results:

     A.  Total number of samples = 985
     B.  2 values = 100 mg/1
     C.  38 values > 100 mg/1
     D.  Percentage of values > 100 mg/1 = 3.96% to
           U.06% of the total of 985 samples
     E.  95% value = 93 mg/1

It  was  generally  concluded that this analysis may be more
representative of the entire system, since the results  from
plant No. 2119 appear to be atypical of the data provided by
the other 9 plants.

Data  on  ash  pond  overflow  for  38  plants obtained from
discharge permit  applications,  plant  visits,  a  regional
office survey, and other sources indicate that 50 percent of
the  ash ponds are achieving effluent total suspended solids
levels of 30 mg/1.  For this same sample, 50 percent of  the
ash  ponds  are  achieving less than 15 mg/1 total suspended
solids after allowances are made  in  the  data  to  exclude
total  suspended  solids  in the make-up water.  On this net
basis, 30 mg/1 is being achieved by approximately 75 percent
of the ash ponds in the  sample.

The Henderson, Kentucky, Municipal Powerplant No. 1  uses  a
tube  settler  to  achieve  over 99 percent removal of total
suspended solids from fly ash and bottom ash  sluice  water.
Some details on this systems are presented in Reference U51.
Land was not available for constructing conventional removal
facilities  (an  effective surface area of 3,000 square feet
would have been required to provide  adequate  treatment  at
1,200 gpm).  See Figure A-VII-24.

Tube    settlers,  manufactured  under  several  proprietary
names, consist of numerous plastic tubes about one  inch  in
depth and 24 inches long, mounted in modules and placed in a
basin.   The  tubes,  as  manufactured,  are installed in an
inclined position  and  each  tube  acts  as  an  individual
settling^  device.   With  a length of travel of one inch the
settleable particles can be removed at a  much  faster  rate
than  in  conventional  settling arrangements.  The angle of
incline allows the sludge to slide  downward  to  the  basin
scrapers.   Thus, the tubes are self-cleaning when operating
under design conditions.

Preliminary testing indicated that a hydraulic loading  rate
of 1.75 gpm per sq ft would produce a good quality effluent.
Consequently  this method of ash removal was recommended for
the project.  In the final design, a hydraulic loading  rate
of  1.6  gpm  per sq ft was used.  Accordingly, an effective
surface area of 750 square feet was required.  Modules  made
by Permutit Co., Division of Sybron Corp. were selected.


                        301

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                   LJ
                                 3-<•"""•'
* ,/
A !"?'„. "' R*I.IH1<
I;'..1,..'..,.? \
	 r 	 'A

/i




*
[
                                                    I..-.J
                                        .. .-..^__,
                               """~"""';~'">^FT'?g'"7/:^".'""'J
                                                    J
Figure A-VII-24    Tube Settler for  Ash Sluice Water
                     at Henderson, Kentucky Municipal
                     Power Plant No. 1
                   302

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Two  basins were designed, each capable of treating one-half
the design flow.  However, all piping and launders  of  each
basin  were  designed  to  carry the entire flow in case one
basin is out of service.  Each basin has an influent  baffle
which  serves two purposes: distributing the flow across the
basin and trapping all floatable particles.  The settled ash
is removed with  mechanical  sludge  scrapers  furnished  by
Envirex,  Inc.,  a  Kexnord Co.  The scraper travels up a 30
degree inclined plane at the effluent end of each basin.  As
the sludge is moved up the incline, it continues to  dewater
until  it  discharges  into  a  sludge  storage  area.   Any
drainage from the ash storage area is  pumped  back  to  the
basin  influent.   Although  the  sludge is quite wet, it is
easily handled with a high-loader.  Ultimate ash disposal is
by haul to a landfill as before.

After  the  settling  basins  were  placed   in   operation,
composite  samples  were  collected during several cycles of
operation to determine the efficiency  of  the  new  system.
The  results  of  the sampling program are shown in Table A-
VII-15 and reflect the performance of the new  basins  only.
The  turbidity  and  suspended  solids concentrations of the
river during the sampling program were 64 JTU  and  U2  mg/1
respectively.

Maintenance  requirements for the system have averaged about
16 manhours per week.  The normal duties of the  maintenance
personnel include hauling of the removed fly ash, preventive
maintenance  and  general  clean-up  of the facilities.  The
power requirements include two 2-hp scraper drives  and  one
1/4-hp sump pump.  The total construction cost was $179,000.

pH  adjustment  has  been  discussed earlier for other waste
streams.   Some  plants  provide  pH  control  on  ash  pond
effluent.   In pH adjustment, addition of chemicals (such as
lime) to the pond should be carried out such  that  adequate
mixing  and  settling  is provided in the pond.  This can be
achieved by separating the pond  in  two  areas  by  use  of
overflow weirs.
In  most  of  the  existing  plants, a combined once-through
sluicing system is used to transport both the  fly  ash  and
the  bottom ash.  Specific data was obtained for five plants
which utilize recirculating ash sluicing  systems.   In  all
the  cases,  blowdown of the system is practiced to minimize
deposition of  dissolved  solids  as  well  as  to  minimize
corrosive effects on the distribution pipes.
                         303

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                                      Table A-VII-15

                 Performance of Tube Settlers for Ash Sluice Water
                           (Results of Composite Sampling)
454
to
Sample Number
1
2
3
4
Average
Turbidity, JTU
Influent
1300
360
750
750
790
Effluent
2.1
6.2
19
10
9.5
Total Suspended Solids, mg/1
Influent
7910
1175
2815
5200
4275
Effluent
4
4
26
18
13
% Removal
99.9
99.7
99.1
99.7
99.7

-------
At  plant  No.  3626  the  fly  ash  is  handled  dry  by  a
pressurized  collection  system,  and  the  bottom  ash   is
collected  hydraulically.   Once per shift the bottom ash is
sluiced from the furnace bcttom for settling.  Water for the
next  sluice  is  recycled  from   the   effluent   of   the
sedimentation  unit.   The  settled  solids are periodically
drained for disposal.  The system is designed  for  complete
recycle,  with  blowdown  achieved  by water retained in the
settled solids.   The  recycle  stream  concentrations  have
equilibrated  and the system has operated successfully for a
number of years.  The  total  makeup  to  the  recirculating
system has been reported as 230 gpd/Mw.  A similar system in
operation  at  plant  no.  3630 was installed as a retrofit.
Bottom ash from the combustion of pulverized coal  at  plant
no. 3630 is trucked from the plant site by a purchaser.  The
make-up water rate is about 20 gpd/Mw.


Figure  A-VII-25  shows  the  flew diagram for the system at
plant No. 3630.  The blowdown flow has been reported as  198
gpd/Mw.   Figure  A-VII-26  shows  the  flow diagram for the
recirculating system at plant No. 5305.  The  blowdown  flow
is 165 gpd/Mw.  The recirculating systems at plant Nos. 5305
and  3626  are  shown  in  Figures  A-VII-27  and  A-VII-28,
respectively.

In two plants within the companies represented on  the  UWAG
Chemical  Cost  Task Group which have recycling ash sluicing
systems, blowdown flows of 600 gpd/Mw  and  960  gpd/Mw  are
used.

Utilizing  the  data  from these five plants  (20,165,230,600
and  960  gpd/Mw),  the  three  lowest   values   of   which
conservatively  include  water lost in evaporation and water
removed with the ash solids,  the  average  blowdown  for  a
recirculating  ash  system  is  about  400 gpd/Mw.  If it is
assumed  that  5000  gpd/Mw  is   the   recirculating   flow
requirement  for  handling  bottom ash, the average blowdown
flow of approximately 400 gpd/Mw represents an  8X  blowdown
flow.   Three of the plants are achieving a blowdown flow of
less than 250 gpm/Mw  which  would  represent,  based  on  a
recirculating flow requirement of 5000 gpd/Mw, a 555 blowdown
flow.

Most oil fired plants use dry ash handling, although closed-
looped  wet systems are also in use.  At plant No. 2512, the
fly ash sluicing system was designed to be a closed  system.
The  ash  collected by the precipitators is sluiced from the
hoppers to two concrete ponds.  Suspended solids settle  out
in  the  ponds  and a relatively clear liquor is returned to
                          305

-------
    Recycle
   2470 gpm
(4450 GPD/Mw)
                    ASH HANDLING
                       SYSTEM
c
              Evaporation  Loss
                    45 gpm
2425 gpm
                    SETTLING POND
                                       Make-up
                                         56 gpm
                                  Ash Sludge for Disposal
                                     (^20% moisture)
                                       gpm water loss
                                     ( 19.8 GPD/Mw)
                    Figure A-VII-25
                    FLOW DIAGRAM
     RECIRCULATING BOTTOM ASH SYSTEM AT PLANT NO* 3630
                   306

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Cooling Tower
Slowdown as
Make-up
(160 gpm)
ASH HANDLING
   SYSTEM
Evaporation Loss
 (assumed zero)
      1960 gpm
    (2000
                Recycle
                1800 gpm
                       ASH
                   SEDIMENTATION
                      SYSTEM
                                    Ash Sludge for Disposal
                                        160 gpm water loss
                                         (/v/165 GPD/Mw)
                     Figure A-VII-26
                     FLOW DIAGRAM •
    RECIRCULATING BOTTOM ASH  SYSTEM AT PLANT NO.  5305
                     307

-------

ASH SEDIMENTATION SYSTEM
      PLANT NO. 5305
     Figure A-VII-27
          308

-------
                                                                        OVER-
                                                                        FLOW
 1.  ASH HOPPER             ^'
 2.  SLIDE GATE
 3.  ASH SUMP WITH CLINKER GRINDER
 4.  ASH PUMP
 5.  ASH PUMP DISCHARGE TO HYDROBIN
 6.  HYDROBIN - THIS IS WHERE ASH IS SEPARATED FROM WATER.
 7.  UNLOADING OF ASHES INTO TRUCK
 8.  HYDROBIN OVERFLOW TROUGH
 9.  UPPER DECANT LINE
10.  LOWER DECANT LINE
11.  HYDROBIN DRAIN
12.  SURGE TANK
13.  LET DOWN LINE - THE REGULATING VALVE IS NOT IN USE. THIS IS NOW A HAND
    OPERATION TO LET WATER INTO LOWER COMPARTMENT OF SURGE TANK.
14.  HOUSE SERVICE SUPPLY LINE - NOT NORMAL MAKEUP.
15.  LINE FROM SURGE TANK TO ASH SUMPS
16.  HOUSE SERVICE SUPPLY LINE - AT PRESENT DATE IS SOURCE OF MAKEUP - HAND OPERATION
17.  REGULATING VALVE TO ASH SUMP
18.  HOUSE SERVICE SUPPLY LINE - NO LONGER IN USE.
19.  HOPPER WASH DOWN LINE - A MEANS OF PUTTING WATER INTO ASH HOPPERS
    FROM MAIN CYCLE.
20.  ASH HOPPER OVERFLOW
21.  BOILER SEAL  TROUGH - WATER OVERFLOWS FROM HERE TO ASH HOPPER THUS ANOTHER
    SOURCE OF MAKEUP WATER.
22.  BOILER FEED PUMP HYDRAULIC COUPLING COOLING WATER
23.  DRAIN BACK LINE - DRAINS ASH PUMP DISCHARGE LINE.
24.  OVERFLOW TROUGH - DISCHARGES INTO CIRCULATING WATER DISCHARGE.
                FIGURE A-VII-28ASH HANDLING SYSTEM (PLANT NO. 3626)
                                 309

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the precipitators to sluice additional ash to the ponds on a
continuous basis.  Due to excessive rainfall and leakage  of
pump  sealing  water,  the  system  requires  a  blowdown of
approximately  132.5  cu  m  (35,000  gal)   per  week.   The
blowdown  is treated in another clarification pond where the
solids are allowed to settle.  The effluent from  this  pond
goes  to  a  neutralizing  tank  for  pH  adjustment, and is
settled prior to discharge.  The system is shown  on  Figure
A-VII-29.

The  settled  solids  are intermittently dug out and sold to
reclaiming companies for vanadium recovery.  The cost of the
ash handling system is estimated at $461,000.

The above plant is presently investigating a  vacuum  filter
system  for  continuous  withdrawal and treatment of settled
solids, to replace the intermittent  withdrawal  system  now
used.

At  plant No. 1209 fly ash from the mechanical collectors is
recirculated to  the  boilers  for  reburning.   Accumulated
bottom  ash  is  periodically removed during maintenance and
sold for the vanadium content.   The utility  representatives
indicate  that  other plants in their system utilize similar
ash handling techniques.

Plant No. 3621 employs the  same  type  of  dry  bottom  ash
handling and reinjection of fly ash as mentioned above.  The
oil  burned  is  Bunker  "C"  -  Venezuela  oil, with an ash
content of 0.1X, a sulphur content of  3X,  and  a  vanadium
content  of 300-400 ppm,  A magnesium oxide fuel additive is
used and it is estimated that bottom ash is 3016, and fly ash
is 70X,  of  the  total  ash  and  additives  residue.   The
following  factors  influenced  the  utility's choice of ash
handling system:   in  a  wet  ash  handling  system  it  is
estimated that 74.6% of the oil ash is soluble in water, and
30-40%  of this ash remains in solution upon settling unless
the detention time is very great - hence  a  large  settling
area  requirement;  oil  ash sluice is expected to be acidic
(pH  3.5-  4)  and  may  cause  corrosion  and   maintenance
problems; the dry bottom ash collection system would allow a
credit  for the sale of this ash for its vanadium content of
about $ 0.001 per g  ($0.50 per Ib).

Plant nos. 5509 and 5511 employ completely recirculating wet
fly ash handling systems.  Dry bottom ash systems are in use
a£ a few plants.
                          310

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                          CHEMICAL CLEANING WASTES
                                   1. BOILER TUBES
                                   2. BOILER FIRESIDE
                                   3. ASH POND
                 WASTE TO DISCHARGE  -
                        FLUME           OVERFLOW
                                 WASTE
                             NEUTRALIZING
                                 TANK
 WASTE
  SUMP
2,500 GAL
       WASTE POND
       350,000 GAL.
       (CONCRETE)
                                                          FLOATING SUCTION
      WASTE POND PUMP
    TAKES CLEAR LIQUOR
FROM POND TO NEUTRALIZATION
  TANK PRIOR TO DISCHARGE
                       ACID  CAUSTIC
                  NEUTRALIZATION PUMPS
          FIGURE A-VII-29ASH HANDLING SYSTEM OIL FUEL PLANT (PLANT NO. 2512)

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Coal Pile Runoff

In areas where water evaporation rates are higher than  pre-
cipitation  rates, it is possible to direct coal pile runoff
to a storage pond.  These ponds  may  be  provided  with  an
impervious  liner  to  avoid  leakage that may contaminate a
ground water aquifer.  Since the amount of runoff depends on
rainfall, for an average annual rainfall of 100 cm  (40")  a
flow  rate of 100,000 cubic meter (26.4 million gallons)  per
year could be expected for a  one  hundred  thousand  square
meter  (25 acres) storage pile.  However, a precipitation of
5 cm (2") in one hour is also possible resulting in 5000  cu
m   (1.32   million   gallons)   runoff.   Inasmuch  as  the
evaporation of water is dependent on  the  surface  area  of
pond,  large  pond  areas  will be required for these runoff
flows.   Furthermore, a leaping weir or similar device can be
used  to  retain  the  potentially  significantly  polluting
portions  of  storm  rainfall  and  to  divert the remaining
relatively nonpolluting portions of the storm.

Storage ponds for  retention  and  treatment  of  coal  pile
runoff should be designed for local weather conditions.  The
design  basis  of  the  pond should be complete retention of
runoff resulting from a  storm  which  occurs  once  in  ten
years.    Piping  and/or open channels used for collection of
runoff from the coal pile should be designed to  bypass  all
flow  which  exceeds  the  design basis of the storage pond.
Weirs,  baffles and regulators such as utilized  in  combined
municipal  sewer  systems  may  be employed to bypass excess
flow and avoid overloading of the storage pond.


The runoff flows are also critically dependent upon the coal
pile area in a plant.  For example, the area required for  a
90  day coal supply and for other storage functions, such as
alkali  for  electrostatic  precipitators,  etc.,  has  been
estimated  to  be  0.02  acres per Mw of generating capacity
(Ref:  "Considerations  Affecting  Steam  Power  Plant  Site
Selection",  Report  by  the  Energy Policy Staff, Office of
Science and Technology, US GPO No.  0-325-261  1968).   Data
were  compiled  for  coal pile area encountered in 10 plants
comprising one particluar utility system.  The average  coal
pile  area was approximately 0.02 acres per Mw of generating
capacity with the full range extending from 0.004  to  0.035
acres/Mw.

Coal  pile  drainage  with  pH from 6 to 9 and low dissolved
solids can be pumped to an ash pond along with  other  waste
streams, depending upon available area of the pond.

Runoff from coal pile with high acid and sulfate content can
be neutralized by lime, limestone or soda ash.  Any of these
                            312

-------
chemicals  used  for  the  neutralization  process  involves
essentially the same unit operation.  A typical sequence  of
unit  operation  is  (a) holding (b) adding the neutralizing
agent and mixing (c)  sludge  settling  and  disposal.   The
major difference between soda ash neutralization and lime or
limestone  neutralization  is that soda ash produces a water
low in hardness and calcium,  but  high  in  sodium.   Other
chemical   parameters   are  comparable  between  the  three
neutralizing agent.  Figure A-VII-30 presents  the  chemical
cost for these three chemicals.

Limestone  handling  is  easier than that of lime because of
its low reactivity.  Limestone reaction is not  very  sensi-
tive  quantitatively:  i.e.  small changes in limestone feed
rate or runoff quality do not cause large changes in product
water quality so that the accuracy of limestone feeding need
not be controlled with  the  precision  required  for  lime.
Unlike  lime,  accidental  over treatment is not a pollution
problem with limestone because of its low solubility.

A major disadvantage  in  limestone  neutralization  can  be
attributed  to  the  slow oxidation rate of ferrous iron and
consequently lower rate of settling.  The rate  of  settling
can  be increased by the addition of coagulant aids.  Figure
A-VII-31 and Figure A-VII-32 present a comparison  of  lime,
limestone  and  soda  ash  reactivities  and  settling rates
respectively.  For a coal  pile  runoff  containing  ferrous
iron   (FesoU)   and   free   acid   (H2SOU),   the  overall
neutralization  reaction  using  limestone  (CaCO3_)  can  be
represented in the following simplified manner:

3CaC03 + 2FeSO4 + H2SO4 + 0.5 O2 * 2H2O = 3CaSOU «• 2Fe  (OH) 3
                                          + 3C02

A  method  of collecting and neutralizing coal pile drainage
is to excavate a channel around the coal pile  large  enough
to  have  a  10  minute  detention  time.  The bottom of the
channel should contain a limestone bed for neutralizing  the
acid content of the runoff.  The channel should be sloped so
as  to  have the runoff drain to a sump from where it can be
pumped or gravity fed to a holding pond prior to discharge.

Insoluble   material   or   precipitated    products    from
neutralization   can   be   separated  by  sedimentation  or
filtration.  The removal of solids by sedimentation has been
described earlier.  Figure A-VII-33  shows  a, typical  coal
pile,  with  a runoff collection ditch around the perimeter.
Plant no. 3630 has a  retrofit  system  for  collecting  and
filtering  coal  pile  drainage.   The  coal  pile trench is
designed to handle a 15-hour, once-in-36-years rainfall  (3.9
                          313

-------
    1.2



    1.1



    1.0




    0.9
W
C
O

3   0.8
id
O

§   0.7
o
to-


•H
-P
(0
O
u
rt
u

e
0)
   0-5
   0.4
   0.3
   o.i


     o
                                       6    7    8     9    10

                                       ACIDITY  IN  1000 mg/1
                                                                11   12
13   14  15    16   17
                                    COST OF NEUTRALIZATION CHEMICALS

                                          (From Reference 313)

                                             FIGURE  A-VI.I-30

-------
en
          pH  10 -
          pH   8
                                                     -,V---;rN
           TT   f
          pH   6
          c
         pH   4 -
          pH
                                                                     O SODA ASH


                                                                     A LIME


                                                                     H LIMESTONE
                0 GRAMS 0.2


                0       2.0
0.8


8.0
1.0   (LIME, SODA ASH)


10.0  (LIMESTONE)
                         GRAMS ADDED TO ONE LITER  OF  RUNOFF (From Reference  313)


                             (INITIAL HOT ACIDITY = 619  nig/1)



                 COMPARISON OF LIME, LIMESTONE, AND SODA ASH REACTIVITIES



                               FIGURE A-VII-31

-------
                                                O LIME
                                                A LIMESTONE
                                                DSODA ASH
                                    INITIAL HOT ACIDITY 586  mg/1
                                 J_
j_
30 min.  60 min. 4 hrs.  8 hrs.   12 hrs.  16  hrs.  20 hrs.  24 hrs,
                         TIME

              COMPARISON OF SETTLING  RATE (From Reference  313)
                    FIGURE A-VII-32

-------
                •
  COAL PILE
PLANT NO. 5305
Figure A-VII-33
      317

-------
inches) .   The  inflow  to  the  coal  pile   is   gradually
transferred  to a collecting basin, which also receives yard
and building  drains.   The  maximum  flow  to  the  100  ft
diameter  filtering pond is 2,400 gpm.  The filter medium is
a 4 ft deep layer of 0.4 mm sand.  The loading is 3.5 gpm/sq
ft and is designed to achieve 35 mg/1 total suspended solids
in  the  effluent.   A  design  for  lower  effluent   total
suspended solids would involve a deeper bed, a better filter
media,  or  a  larger  bed  area.   This filter has achieved
effluent total suspended solids levels of 15  mg/1  or  less
over  approximately  75 percent of the storm events to date.
The trench and  collecting  basin  construction  costs  were
about $750,000 and the filtering pond about $150,000.

Floor and Yard Drains

Floor  drains  from  a  coal-fired generating station can be
collected and pumped directly on to the coal  pile  so  that
the  oil  present  in the drainage stream is absorbed by the
coal and burned with it.  The water will serve  the  purpose
of  keeping  the pile wet in order to avoid spontaneous com-
bustion.  Floor drains from plants using a fuel  mixture  or
fuel  other  than coal, can be neutralized (if necessary)  by
lime or acid to bring the pH between 6 and 9.0.  Oil will be
removed by passing the stream through an air flotation  unit
or  an  oil-water  separator (Figures A-VTI-34, 35).  If the
drains contain high levels of TSS, sedimentation  techniques
described  earlier  can be used.  An air flotation unit used
for floor and yard  drains  is  shown  in  Figure  A-VII-36.
Contaminated  stormwater runoff can be treated in a similiar
manner.  Stormwater collected in oil storage tank basins  is
generally  held  for  controlled  discharge  to an oil-water
separator (Figures A-VII-37, 38).

API - type oil - water separators are being  used  at  plant
nos.  3626,  5105, 1209, and 3702 to reduce oil content down
to 15-20. mg/1.  A dissolved air flotation unit  is  used  at
plant  no.  0610.   Certain  preventative  measures  can  be
applied to prevent spillage of oil and the entrance  of  oil
into the plant drainage system.  For example, plant No. 1201
employs inflatable "stoppers" in the entrance to plant floor
drains  to  trap  spilled  oil and so that it may be removed
before entering the floor drain system.

Air Pollution Control Devices

The nonrecovery alkali scrubbing process  is  a  closed-loop
type, and the process employs recycle lime scrubbing liquor.
The  process  requires  a  make-up  water for saturating the
boiler gases.  Consequently, the liquid effluent  associated
                          318

-------
       _. SKIMMINGS
       \   HOPPER

            MOTOR &
COMPRESSED
    AIR
Vat/

CLEAN WATER
DISCHARGE J^-> i
OIL/,"* J-
SKIMMEDOIL / c c<
DISCHARGE | / ;^
o .1
WATER
SLUDGE , """""" l
*« r ROTATING
=-> I SKIMMER BLADE r-A
1 ^DCPVr*l C /^ 	
net/ T oi_c
1 1 WATER x

k'^1?**.^.^-" L. ' ^y * » x
j •,," ^ ? • •• — ^-^ . l
-1 - •-. ; , H,-*,.r*y!, „<$!,
s\ o RECYCLE
•'A PUMP ^^-
.°.PL_. 	 L_ ^^T • mi
L, ^ao^; ^ IN
±^--~~^ ^ RISING AIR
<^"^ BUBBLES WITH
I ATTACHED OIL
ERATION TANK
*""*VAERATED RECYCLE
WATER
j
.- FLASH VALVE
-- (RELEASES
. ' BUBBLES)
Y WATER
FLUENT
ROTATING \ ^-Dl^y,ScER '
SCRAPER ARM J CONE
FIGURE A-VII-34 CYLINDRICAL AIR FLOTATION UNIT
OIL COLLECTING -r
PIPE
DISTRIBUTION '
BOX 1
WEIR—, BAFFL
j
INLET ^ ri'll A
r^" 0U; » =
\n v^.1 __
r
^ - (

"1-U R^J^ - ~~ c c
7 ':.l I -*• i;"
//~^ /' / /.// 77~/7~/7/X/7/~^ / r^rr-Tx. /'•-*/!""' /"7~r/ —
[
INLET PRIMARY
CHANNEL CHAMBER
^£l X^z^/ 1

rLICjHT CLEANER
SLUDGE SECONDARY
SUMPS CHAMBER
OIL COLLECTING
PIPE
r BAFFLE
pWEIR
\S^ YA OUTLET
JzzJ
OUTLET
CHANNEL
FIGURE A-VII-35 TYPICAL A. P. I. OIL-WATER SEPARATOR
                    31S

-------
OIL SEPARATOR AND AIR FLOATATION UNIT
           PLANT NO. 0610
          Figure A-VII-36
                320

-------
INTERCEPTOR
    BAY

    PLATE
  ASSEMBLY "
                 GRATING
                      OUTLET CHANNEL
                                    r- POLYURETHANE FOAM
                         SKIM PIPE
                                               INLET CHANNEL
                 SLUDGE
               COMPARTMENT
                                                  BAFFLE
 SAND
STORAGE
       FIGURE A-VII-37 CORRUGATED PLATE TYPE OIL WATER SEPARATOR
                              321

-------
       OIL/WATER MIXTURE IN
                                         VENT
WATER
   DRAIN
OIL
                 FIGURE A-VM-38 OIL WATER SEPARATOR
                               322

-------
with  the sludge removal step should be kept to a minimum to
minimize make-up water requirements.  This can  be  achieved
by  providing  adequately sized ponds and adding flocculants
for  efficient  settling.   Use  of  mechanical   filtration
equipment  will further dewater the sludge and thus minimize
liquid  effluent  discharge.   Oxidation  of  the   scrubber
discharge  effluent  will  ensure  that sulfite level in the
sludge is minimal.  Lime/limestone addition is necessary  to
eliminate  acidity.   If  the  process employs a pond in the
scrubber liquor recycle loop, the pond should  be  lined  to
minimize ground seepage.

Sanitary Wastes

Sanitary  wastes  can  be  discharged  to municipal sewerage
systems where possible.  In  rural  areas,  packaged  sewage
treatment  plants are commonly used for treating this waste.
Most of these plants are based on the  biological  principle
of  aerobic decomposition of the organic wastes and are able
to reduce the raw sewage concentrations of BOD-5 and TSS  to
meet   effluent   standards   applicable  to  publicly-owned
treatment works.

Other Wastes

Intake screen backwash can be  collected,  viable  organisms
returned  to  the waterway, and the collected debris removed
before discharging the effluent  to  the  receiving  waters.
Collected  debris  can be disposed of in a landfill or other
solid waste disposal facility.

For  other  miscellaneous  wastes,  such   as   those   from
laboratory  and sampling activities, etc., pH adjustment and
TSS removal is similar  to  that  followed  in  other  waste
streams.   Technology  for  the  control  of  pollution from
construction  activities  is  'treated   comprehensively   in
Reference 382.

Oil  spillage  from  transformers  can  be absorbed in slag-
filled pits under and around the transformers.   Curbing  of
the pits prevents flooding by surface water and floating off
the oil.

Waste  water from the primary coolant loop of nuclear plants
may contain boron; however, no treatment is known for  boron
removal.   As  explained in Part A Section V, nuclear plants
follow a radioactive waste management system.  Any treatment
or  recycle  concept  applied  to   remove   non-radioactive
pollutants  from  these  wastes  would  have to consider the
radioactive components of this waste.
                          323

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Various Waste Streams - Concentration and Recycle

Vapor-compression evaporation systems can be used to recover
and recycle water from  various  waste  streams  encountered
normally  in  a  steam  electric  generating  plant.   These
streams include boiler  blowdown,  demineralizer  blow-down,
ash  sluicing water blowdown, coal pile runoff, SO^ scrubber
blowdown, treated sewage effluent, boiler cleaning waste and
cooling tower blowdown.  Two case  histories  in  which  the
vapor-compression  evaporation  systems (brine concentrator)
have been installed in steam electric generating plants  are
described below.
Case  I  (See  Figure  A-VII-39  and  Table  A-VII-16) is an
application of the brine concentrator  that  was  placed  in
operation   on   June   14,  1974.   This  application  will
ultimately employ several brine concentrators to  completely
eliminate  wastewater  blowdown  from the ash sluice system.
The ash sluice  water  is  provided  by  the  cooling  tower
blowdown  where  it  is  recycled  to  the boiler and ash is
sluiced to the ash separator.  The supernatant from the  ash
separator  is  recycled to the ash sluice water storage tank
for reuse.  The blowdown from the ash sluice  water  storage
tank  is  processed  in  the  brine  concentrator  where the
concentration of total solids is increased to  over  100,000
ppm.  It is contemplated that as additional generating units
are  placed  on  line, additional brine concentrtors will be
installed so that eventually the only feed to the pond  will
be the waste from the brine concentrators.
Case  II   (See  Figure  A-VII-40  and  Table A-VII-17)  is an
application of the brine concentrator  that  was  placed  in
operation   on   June  28,  1974.   This  installation  will
eventually be  used  to  process  a  blowdown  from  various
generating   plant   waste   streams.   However,  the  brine
concentrator is currently being utilized to concentrate only
cooling tower blowdown.  The blowdown will  be  concentrated
approximately  40  times  such  that  the feed of 156 gpm is
reduced to 3.7 gpm of concentrate.   At  this  installation,
the  client  anticipates  a  wide variation in the feedwater
chemistry to the brine concentrator.  On the chemistry  data
sheet  are  shown  the maximum TDS design conditions and the
normal value TDS conditions.

Evaporation ponds are in use at a number of  steam  electric
powerplants  to  reduce waste streams to dryness.  Plant No.
4883 uses  101,000  sq  ft  of  lined  evaporation  pond  to
evaporate a maximum flow of 43,000 gal/day of waste water to
                          324

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                                         TCV.'Ef! EVAPWnP'l   TraEP. ni'T .'•

                                             2 GP"      UIIIL'AC!: LI S3
OJ
ro
tn
                                      cnpLi;:; ;(".jci<   *
                                     ::AKE'JP «iri r,p:;
                                                            COOLING TOWER
            Figure A-VII-39  Vapor-Compression Evaporation System  (Case I)
                                System commissioned  on June 14,  1974
                                                                                       452

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                                               Table A-VII-16


                                   RCC BRINE CONCENTRATOR SYSTEM CHEMISTRY (Case  I)
452
COMPONENT
CALCIUM (As Ca^)
MAGNESIUM (As Mg^)
SODIUM (As Na+)
BICARBONATE (As HCOg" )
SULFATE (As S04= )
CHLORIDE (As C1")
SILICA (As Si02)
*30 CONCENTRATION FACTORS
TDS (PPM)
SS (PPM)
FLOW RATE (GPM)
PH
CONCENTRATOR
FEED (TDS)
529 PPM
276
55
488
2,002
62
55

3,467
-
156
8.0-8.5
CONCENTRATOR
WASTE BRINE (TDS)*
520 PPM
7,800
2,850
-
36,528
1,800
250

49,748
54,862
5.2
7.0-7.6
PRODUCT
WATER








< 10
-
148
6.0-7.0
co
ro
on

-------
POWER PLANT
CONDENSER
                                       RCC BRINE
     PRODUCT
     WATER
     1So   PPM   CONCENTRATOR}*-
     152.3 GPM  V  SYSTEM
     10 PPM        CF = 40
                                                             EVAPORATION
                                                            4 LOSSES
                                                            I
COOLING
 TOWER
COOLING TOWER
  MAKEUP
                                                             COOLING TOWER
                                                             SLOWDOWN
                                                             156 GPM
                                                             5,000 - 8.000 PPM
                                            3.7 GPM
                                            94,300 - 165,600 TDS  PPM
                                            103,400 - 139,500 SS  PPM
                                     EVAPORATION
                                         POND
               Figure A-VII-.40 Vapor-Compression Evaporation  System
                                 ( Case  II)
                                  327

-------
                                               Table A-VII- 17


                                       RCC BRINE CONCENTRATOR SYSTEM CHEMISTRY (Case  II)   452
COMPONENT
CALCIUM (As Cd**)
MAGNESIUM (As Mg"*"*")
SODIUM (As Na+)
BICARBONATE (As HCOj")
SULFATE (As S04=)
CHLORIDE (As Cl")
SILICA (As S102)
*40 CONCENTRATION FACTORS
TDS (PPM
SS (PPM)
FLOW RATE (GPM)
PH
CONCEN'
FEED
NORMAL
748 PPM
166
496
360
2,964
172
110

5,016
-
156
8.0
FRATOR
(TDS)
HIGH
1,000 PPM
149
1,182
360
4,963
199
134

7,987
-
156
8.0
CONCENTRATOR
WASTE BRINE (TDS)*
NORMAL
720 PPM
6,640
19,840
-
60,000
6,880
250

94,330
103,430
3.7
7.0-7.6
HIGH
480 PPM
5,960
47,280
-
103,680
7,960
250

165,610
139,470
3.7
7.0-7.6
PRODUCT
WATER








< 10
-
152.3
6.0-7.0
CO
ro
oo

-------
dryness.   Configured  systems  are being installed at three
steam electric powerplants (plant nos. 0413, 3517 and 4907).
The configured systems use brine concentrators which recycle
the distillate to the demineralizer system or to the cooling
tower.  All process  156  gpm  of  cooling  tower  blowdown.
However, water treatment wastes, etc., are combined with the
recirculation   cooling  water.   The  plants  involved  are
designed to  achieve  no  discharge  of  pollutants  through
recycle of waste water streams.  Therefore, the concentrated
brine  ultimately  contains  all plant wastes.  The costs of
the units are approximately $2-4/kw  with  about  18  months
required  for  installation.  The application of evaporative
brine concentrators to  low-volume  waste  stream  effluents
after chemical treatment is not known to have been achieved.
Therefore,  some technical risks may be involved in applying
this  technology  directly  to  lew-volume  waste  water  of
powerplants.

Sludge Disposal

The  major  solid  wastes from powerplants can be classified
into three categories:

     1.  Fuel related wastes (ash) - flyash, bottom ash and
         boiler slag
     2.  Scrubber sludges - from non-regenerable (throwaway)
         flue gas desulfurization systems
     3.  Chemical sludges - from water and effluent treatment
         systems

Of the three wastes, partial utilization  of  ash  has  been
commonly  practiced.   Tables A-VII-18 and A-VII-19 indicate
ash collection and utilization data   (Ref.  33).   Estimated
1976 ash production is also shown in Table A-VII-18.  It can
be  seen  that  the largest usage has been, and continues to
be, as fill material for  roads,  construction  sites,  etc.
However,  new  commercial  processes are being developed and
the trend seems to be to increase ash utilization for  other
applications.    Some   recent   developments   which  offer
potential  high-tonnage  ash  utilization  are  as  follows:
(Ref. 33).

1.   A  material  composed  of  lime,  flyash and sulfate or
sulfite sludges was used  to  pave  some  access  roads  and
parking  areas  at Dulles International Airport  (Washington,
D.C.) for  the  Transpo  *72  exhibition.   2.   Two  cement
companies  announced  new  plants and programs to market for
general construction purposes  a  portland  pozzolan  cement
that  is  a  blend of portland cement and flyash.  3.  A new
project in northern West Virginia will use 250,000  tons  of
                             329

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                 Table A-VII-18
       Ash Collection and Utilization, 1971  (Tons)
                                                              33
                                      Fly Ash     Bottom Ash
Ash uses:
   1. Mixed with raw material before
     forming cement clinker                104,222          —
   2. Mixed with cement clinker or mixed
     with pozzolan cement                  16,536          —
   3. Partial replacement of cement in:
      a. Concrete products                 177,166
      b. Structural concrete                185.467
      c. Dams and other mass concrete        71,411
   4. Lightweight aggregate                 178,895
   5. Fill material for roads, construction
     sites, etc.                    ,        363.385
   6. Stabilizer  for road bases, parking
     areas, etc.                            36,939
   7. Filler in asphalt mix                  147,655
   8. Miscellaneous                        98.802

            Subtotal                   1,380.478

Ash removed from plant site lat no cost
   to utility, but not covered in
   categories listed above, see Table II
   below)                             1,872.728        542.895
 ilies. which account lor 60% of Hie bituminous coal
 and 80% ol the ash-producing oil that is consumed
 in the U.S.
            Boiler Slag
               91.975
               76.563
35.377
   13,942

 533,682     2.628.885

    7,880       49,564
    2,833       81,700
 475.417      428,026

1.069,131     3.356.713
              381.775
Total ash utilized
Ash removed to disposal areas (at
company expense)
Total ash collected, 1971 *
Estimated 1976 ash production
•These ash production ligu'es .ve lor eiecincai uln-
3,253.206
24.497.848
27,751,054
36.994.436
1,612,026
8,446.941
10.058367
117.411,603
3.738.488
1,232.298
4,970,786
2,517.703
                        Table  A-VII-19
      Known Uses for Ash Removed From Plant at  No Cost to
                            Utility   (Tons)   33'
 Cement manufacture
 Mine-fire control
 Anti-skid winter roads
 Building blocks and fill material
 Experimental soil conditioner
 Misc. fill material
 Airport pavement
 Soil stabilization
 Fertilizer tiller
 Rubber filler
 Vanadium recovery
 Oust control
 Asphaltic wear-course aggregate
            Total
                                       Fly Ash     Bottom Ash     Boiler Slag
51,697
129,258
82,948

25
477,918
16,200
5,035
1,321
296
200



38,940
178.323
14,741

34.760




200
11.284



166.131
229,393








2.130
                                        764,898
                                                       278,248
               397,654
                         330

-------
bottom ash and boiler slag as aggregate for a new portion of
West  Virginia1s  Route  2.   Besides  conserving  dwindling
supplies of local natural aggregates, this  use  of  ash  is
expected  to  save  $500,000 in material costs,  4.  Ontario
Hydro commenced operation of its flyash processing plant  at
Mississauga, Ontario, to make pozzolan, aggregate, magnetite
and  carbon  products.  Also, International Brick and Tyle's
flyash  brick  plant  near  Edmonton,  Alta.,  has   started
production; it is designed to initially provide 6.25 million
units  annually  to the face-brick and paving-tile market in
western Canada.  The process being used was developed by the
Coal Research Bureau  of  West  Virginia  University.   This
process  will also be used in Czechoslovakia in a plant that
will  consume  about  100,000  tons/year  of   flyash.    5.
Specifications for "lime-flyash-aggregate" base material are
anticipated   to   become   part  to  the  Federal  Aviation
Administration1s construction guidelines.   Newark  and  JFK
Airports  have already utilized this type of material in the
construction of runways for new, heavier aircraft.   Similar
pavements   are   being   designed  for  airports  at  other
locations.

Besides these commercial applications, extensive research is
being conducted to utilize ash in agriculture as fertilizer,
in brick manufacturing, for land and water reclamation,  and
for fire control purposes.

The  traditional  ash  disposal methods - namely ponding and
landfill - are expected to remain  in  widespread  practice.
These  methods  have  been described in the literature (Ref.
417).

Dewatering and fixation aspects related to the  disposal  of
scrubber  sludges  from non-regenerable  (throwaway) flue gas
desulfurization  systems  have   been   described   in   the
literature  (Ref. 117).

Chemical sludges resulting from water and effluent treatment
systems  in  a  powerplant  can  be  disposed in landfill or
ponding operations.  Table A-V-20 indicates typical chemical
wastes originated in a coal-fired powerplant.  Based on this
tabulation, it is possible to estimate the annual volume  of
sludges resulting from the treatment of these waste streams.
For  example,  for a 1,000 Mw coal-fired powerplant chemical
sludges  will   require   an   additional   land   area   of
approximately  2-7X for pondage.  This is based on the waste
characterization shown in Table  A-V-20  and  the  following
assumptions:
                             331

-------
1.   A  1,000  Mw  coal-fired  powerplant  requires  an  ash
disposal area of 120 acres piled to an average depth  of  25
feet  over  a  35  year  plant  life and assuming an average
capacity factor of 50% (Ref. 370).  2,   Chemical  treatment
results  in  a precipitate of twice the weight of pollutant.
3.  Suspended solids  removal  system  is  designed  for  an
outlet  concentration  of  30  mg/1.  4.  Chemical treatment
removes all of the chemical pollutant parameters  listed  in
Table  A-V-20  completely  and  the weight of precipitate is
twice the weight of the  pollutant  parameter.   This  is  a
conservative  assumption.   For  example,  if  the  ash pond
overflow is treated only for these suspended solids  removal
(and  no  pH  adjustments  is  required)  then  sulfate  and
hardness will not be precipitated.  Consequently, the  1,000
Mw  plant  will  require  an  additional land area of 251 for
pondage based on these considerations.


Clarifier underflow  (sludge)  contains  typically  1  to  2
percent  solids  and  can  be  carried to a lagoon.  Run-off
through porous soil to  ground-water  can  be  objectionable
since   precipitated  metal  hydroxides  tend  to  get  into
adjacent  streams  or  lakes.   Impervious  lagoons  require
evaporation into the atmosphere; however, the average annual
rainfall in many locations balances atmospheric evaporation.
Additionally,  heavy  rainfalls  can  fill  and overflow the
lagoon.  Lagooning can be avoided by dewatering  the  sludge
to a semi-dry or dry condition.

Several devices are available for dewatering sludge.  Rotary
vacuum  filters  will  concentrate  sludge containing t to 8
percent solids to  20  to  25  percent  solids.   Since  the
effluent  concentration  of  solids is generally less than 4
percent, a thickening tank is generally employed between the
clarifier and the filter.  The filtrate  will  contain  more
than  the  allowed  amount  of  suspended  solids, and must,
therefore, be sent back to the clarifier.

Centrifuges will also thicken sludges to the above range  of
consistency  and  have  the  advantage  of  using less floor
space.  The effluent contains at least  10 percent solids and
is returned to the clarifier.

Pressure filters may be used.  In contrast to rotary filters
and centrifuges, pressure filters will  produce  a  filtrate
with  less than 3 mg/1 of suspended solids.  The filter cake
contains approximately 20 to 25  percent  solids.   Pressure
filters  are  usually designed for a filtration rate of 2.0t
to  2.<*4  liters/min/sq  m   (0.05  to  0.06  gpm/sq  ft)  of
clarifier sludge.
                          332

-------
Solids contents from 25 to 35 percent in filter cakes can be
achieved with semi-continuous tank filters rated at 10.19 to
13.4U  liters/min/sq  m (0.25 to 0.33 gpm/sq ft) surface.  A
solids content of less than 3 mg/1 is normally accepted  for
direct  effluent discharge.  The units require minimum floor
space.

Plate and frame presses produce filter cakes with UO  to  50
percent  dry  solids  and  a  filtrate with less than 5 mg/1
total suspended solids.  Because automation of these presses
is difficult, labor costs tend to be  high.   The  operating
costs are partially off-set by low capital equipment costs.

Automated  tank-type  pressure  filters  produce  a cake the
solids content of which can reach  as  high  as  60  percent
while  the filtrate may have up to 5 mg/1 of total suspended
solids.   The  filtration   rate   is   approximately   2.0U
liters/min/sq  m  (0.05  gpm/sq  ft)  filter  surface  area.
Pressure filters can also be used directly  for  neutralized
wastes  containing  from 300 to 500 mg/1 suspended solids at
design rates of a.88 to 6.52 liters/min/sq m (0.12  to  0.16
gpm/sq  ft)   and  still maintain a low solids content in the
filtrate.  Filter cakes can easily  be  collected  in  solid
waste containers and hauled tc land fills.

Several   companies   have  developed  proprietary  chemical
fixation processes which are being used to solidify  sludges
prior  to  land  disposal.   In  contrast to filtration, the
amount of dried sludge to be hauled  is  increased.   Claims
are  that  the process produces insoluble metal ions so that
in leaching tests only a fraction of a part per  million  is
found  in solution.  However, much information is lacking on
the long term behavior of the "fixed" product, and potential
leachate problems which might arise.  The leachate test data
and historical information to date indicate that the process
has been successfully applied in the disposal of  polyvalent
metal  ions  and  it  apparently  does  have  advantages  in
producing easier to handle materials and in eliminating free
water.  Utilization of the chemical fixation process is felt
to be  an  improvement  over  many  of  the  environmentally
unacceptable   disposal  methods  now  in  common  usage  by
industry.  Nevertheless, chemically fixed wastes  should  be
regarded  as  easier-to-handle equivalents of the raw wastes
and the  same  precautions  and  requirements  required  for
proper landfilling of raw waste sludges should be applied.

Powerplant Wastewater Treatment Systems

Previous  sections  of this report have discussed the signi-
ficant parameters of chemical pollution present  in  various
                           333

-------
waste  streams  and  the  control  and  treatment technology
available to reduce these parameters to  acceptable  limits.
It  would  generally  not  be practicable for powerplants to
provide separate treatment facilities for each of the  waste
streams  described.   However,  segregation and treatment of
boiler cleaning waste water and ion exchange water treatment
waste water is practiced in a relatively few  stations,  but
is  potentially  practicable  for  all stations.  Oily waste
waters are segregated from nonoily  waste  streams  at  some
stations   and   the  oil  and  grease  removed  by  gravity
separators and flotation units.  Combined treatment of waste
water streams is practiced in numerous plants.  However,  in
most  cases  treatment  is  accomplished only to extent that
self-neutralization, coprecipitation and sedimentation occur
because of the joining and  detention  of  the  waste  water
streams.   Chemicals  are added during combined treatment at
some plants for pH control.  Most of these  stations  employ
lagcons,  or ash ponds, while a few plants employ configured
settling tanks.  It would be generally practicable, from the
standpoint cf costs versus effluent reduction benefits,  for
powerplants  to  treat  separately  certain low-volume waste
streams,  certain  intermediate-volume  waste  streams,  the
high-volume  waste  streams,  and the waste stream caused by
rainfall runoff.

A major problem in providing a central treatment facility is
the variability of the flow  characteristics  of  the  waste
streams generated in a powerplant.  As previously indicated,
some  of the flows are either continuous or daily batch dis-
charges, while others only occur a few times  per  year  and
others  depend  on meteorological conditions.  The provision
of adequate storage to retain the maximum anticipated single
batch discharge is therefore a critical aspect of the design
of a centralized treatment facility.  For purposes  of  this
report  it  has  been conservatively assumed that sufficient
storage  would  be  provided  to  store  all  of  the  batch
discharges as if they would occur simultaneously and deliver
them to the treatment units at an essentially uniform rate.

A  small,  highly efficient central treatment facility would
be primarily designed  to  handle  low  volume  wastes  with
relatively  high  concentrations  of heavy metals, suspended
solids,  acidity,  or  alkalinity,  etc.   The  addition  of
intermediate-volume  wastes  such  as cooling tower blowdown
and nonrecirculating ash sluice water to this facility would
require a significantly more costly investment and would not
with the same practices be able to affect as high  a  degree
of  effluent  reduction  (pounds) due to the dilution factors
involved.  The capital investment required for inclusion  of
cooling  tower  blowdown  in  the  central  facility  may be
                          334

-------
significant.  The benefit derived from including this stream
in terms of suspended solids removal  is  questionable  when
compared to the added cost involved.  Cooling tower blowdown
and  nonrecirculating ash sluice water was not considered in
development of the  model  treatment  facility  because  the
characteristics  of  these  streams are not necessarily com-
patible  with  the  treatment  objectives  of  the   central
facility.

Cooling  tower  blowdown generally can be characterized by a
relatively high concentration of the total dissolved  solids
present  in  the  water  source  and  a  somewhat lower con-
centration of the suspended  sclids  present  in  the  water
source.   In  addition,  tower  blowdown  generally contains
small concentrations of chlorine and  other  additives  from
the  closed  cooling  system.   The  objective  of directing
cooling tower blowdown to a central treatment facility would
most  likely  be  for  the  removal  of  suspended   solids.
However,  in  general  treatment  for  removal  of suspended
solids prior to the use of water as make  up  to  a  cooling
tower would be practiced if the suspended solids level is at
all  significant.   In  any event, some concentration of the
suspended solids level  will  occur  in  the  tower  due  to
evaporation and, in some cases, due to contact with airborne
particulates.  However, the cooling tower basin also acts as
a settling basin to some degree, so that suspended solids in
many  cases  will settle out in the cooling tower basin.  In
any case, the objective of  suspended  solids  removal  from
these intermediate-volume waste streams can best be achieved
by  the  commonly  employed  practice of using sedimentation
lagoons.

In some cases in both fossil-fueled  (plant  no.  2119)  and
nuclear  plants  (plant  no. 3905) cooling tower blowdown is
combined with low volume wastes in the  sedimentation  pond.
Better  results can be obtained by segregation of these low-
volume and intermediate-volume waste streams.  In plant  no.
3905  the  pond  is  designed  for 24 hours detention and is
divided by a dike to provide settled solids accumulation  in
the  forepond  to facilitate removal, and further to prevent
short-channeling of waste water  flows.   Segregation  could
have been provided at an incremental cost for the additional
piping required.

Where  sufficient  land  is  not available for effective ash
ponds and/or where no discharge of heavy metals, etc., would
be  required,  closed-loop  recirculating  systems  can   be
employed   which   require   much   less   available   land.
Recirculating ash sluicing systems of this type are  capable
of  achieving  significant  removals  of pollutants up to no
                            33b

-------
discharge of ash in waste water effluents.   An  example  of
such  a  system is the upgraded waste treatment facility now
operating at plant No. 3630.  In this system, bottom ash  is
sluiced from the ash hoppers and collected in the hydrobins.
The  sluicing water is recirculated back to the hoppers thus
making a closed loop system.


Wastewater Management

Because of the varied uses that  are  made  of  water  in  a
powerplant  and the wide range of water quality required for
those uses, powerplants present  unusual  opportunities  for
wastewater  management  and  water reuse.  The highest water
quality requirements are for the  bciler  feedwater  supply.
Makeup   to   this  system  must  be  demineralized  to  TDS
concentrations of the order  of  50  mg/1  for  intermediate
pressure plants and 2 mg/1 for high pressure plants.  Boiler
blowdown  is  generally  of  higher purity than the original
source of supply, and can be recycled for any other  use  in
the  plant,  including  makeup  to  the  demineralizers.  In
plants using closed cooling water systems, the blowdown from
the cooling system is of the same chemical  quality  as  the
water  circulating  in the condenser cooling system.  Limits
on the water quality in that system is governed by the  need
to  remain  below concentrations at which scale forms in the
condenser.  However, if calcium is the  limiting  component,
the  introduction of a softening step in the blowdown stream
would restore the waste to a  quality  suitable  for  reuse.
Even  without  softening,  the  blowdown  from the condenser
cooling water system is  suitable  for  makeup  to  the  ash
sluicing  system, or for plants using alkaline scrubbers for
control of sulfur dioxide in stack gases, as makeup to  that
system.    Plants  located  adjacent  to  mines  (mine-mouth
plants) often have additional requirements for  low  quality
water for ore processing at the mine.

With these cascading water uses it is frequently possible to
devise  water  management  systems  in  which  there  is  no
effluent as such from the powerplant.   These  plants  still
have  significant  overall water requirements, but the water
is used consumptively for evaporation and drift  in  cooling
towers,  for sulfur dioxide removal, or for ash handling and
ore preparation.  Figures A-VII-U1, 42 show  flow  diagrams,
taken  from  Reference  378, for a typical 600 Mw coal-fired
plant, with and without waste water management to achieve no
discharge of pollutants.  An equalization basin  is  usually
provided for temporary large waste discharges such as result
from  cleaning  operations,  but  even  these  wastes can be
reintroduced into the  system  at  a  later  time.    Several
                           336

-------
                                                                                 EVAPORATION & DRIFT LOSS
 ALUM
                                                                                                                                        DISCHARGE
                                    BOILER SLOWDOWN
                                                         20 GPM
Figure A-VII- 41  Sewage and Waste Water Disposal for  a  Typical Coal-Fired Unit, 600 Mw
                                                                                             378

-------
                                                                                    EVAPORATION & DRIFT LOSS


                                                                                               0-0
4,980 GPM
HAW WATER ^
7.400 GPM *

SURGE
POND

k~
1
t
	 ALUM DISPERSANTS
1 —.LIME CORROSION IN
Y * CHIOHINF —
SOFTENER
AND
CLARIFIER
7,250 GPM

HIBITORS -,
1
rwi
r
1 |
BACKWASH FMTFB
WET /
COOLING /
TOWER /
/
r 	 '•
   r
                                                                              SURFACE
                                                                              CONDENSERS
                                                                        -M     )—— ^-TO CONDENSATE TANK
                                                                          vqv
                                                                                                                 SLOWDOWN
                                                                                                                  2.ISO GPM
                                              EVAPORATOR > BOILER SLOWDOWN  220 GPM
Figure A-VII-42     Recycle of  Sewage and Waste Water for a Typical  Coal-Fired Unit,  600 MH
                                                                                                 378

-------
plants visited during this study were using water management
schemes  of  this  type  without  economic penalties.   Water
management may be the most economical mode for  operating  a
powerplant  in  a  water  short area.  There can be no doubt
that the concept of no discharge of pollutants  is  feasible
for  many  steam  electric  pcwerplants.  A number of  plants
within the industry currently practice recycle and reuse  in
varying  degrees and in a number of different ways.  Several
plants constructed within the last few years  were  designed
for minimal or no discharge.  See Figure A-VII-43.

Plant  No.  3206  was intended to be a no discharge facility
and is achieving that goal although some operating  problems
have  been encountered.  The plant receives slurried coal by
pipeline and  after  dewatering  reuses  the  water  in  its
service system.  Makeup to the cooling towers is softened to
obtain   16-17  concentrations  in  the  system  and  therby
minimize blowdown.  Ash sluicing water is also recycled  and
blowdown  from this system along with other blowdown streams
are sent to evaporation ponds for final disposal.

Plant No. 5305 is  a  mine-mouth  facility  which  also  was
designed  to  produce no discharge other than that resulting
from coal pile drainage and the  effluent  from  the  sewage
treatment   plant.    Discharges   from   plant  operations,
including cooling tower blowdown,  water  treatment  wastes,
boiler blowdown, floor drains and blowdown from a closed ash
sluicing  system  are  collected  in effluent storage ponds.
Makeup to the ash sluicing operation  is  taken  from  these
ponds,  but the major portion of the water is transported to
the mine and  coal  preparation  plant.   The  plant  is  an
excellent   example  of  cascading  water  reuse  to  usages
requiring successively lower water quality.  A large  amount
of  the  water  withdrawn  from  the  river  is lost through
evaporation in the cooling towers.  The remainder is  either
ultimately  tied up with filter cake at'the coal preparation
plant or disposed of with wet ash.  Both the filter cake and
the ash are returned to the mine for use as fill.

Plant No.  0801  utilizes  a  series  of  ponds  to  achieve
intermittent  controlled  discharge  for  use in irrigation.
The ponds provide the water required for condenser  cooling,
boiler  feed,  flue  gas  scrubbing  and  ash sluicing.  Ash
sluice,  boiler  blowdown  and  scrubber  wash   water   are
discharged to two alternately used ash  ponds.  Overflew from
these  ponds and condenser cooling water are discharged to a
series of three ponds or lakes.  The third in the series  of
ponds   serves   as  the  water  source,  thus  providing  a
completely closed system.
                             339

-------
CO
-e»
CD
                                                                                   HOPPER JETTING NOZZLES
                EVAPORATION



                      RIVER
                                            Figure A-VII-43


                              RECYCLE  WATER SYSTEM,  PLANT  NO.  2750
254

-------
Several  generating  stations  are   utilizing   closed-loop
recirculating  systems for ash sluicing operations.  Systems
of this type are capable of achieving effluent reductions up
to no  discharge  of  pollutants  in  wastewater  effluents.
Examples  of  such  systems include plants 3630 (a retrofit)
and 3626.   Both  of  these  installations  collect  sluiced
bottom  ash  in hydrobins, and recirculate the water back to
the ash hoppers  for  sluicing.   This  type  of  system  is
particularly  suited  to plants where sufficient land is not
available for effective ash  ponds.   Plant  No.  4846  also
utilizes  a  closed-loop ash sluicing system, but employs an
ash pond with discharge from the pond being pumped  back  to
the plant.

Plant  No.  3630  has  a  retrofit  system  for achieving no
discharge of pollutants from  bottom  ash . sluicing,  boiler
cleaning wastes, floor drainage, boiler blowdown, evaporator
blowdown,   and  demineralizer  wastes.   This  is  achieved
through the re-use of neutralized demineralizer waste water,
boiler cleaning effluents, floor drainage, boiler  blowdown,
and  evaporation  blowdown  in  the  ash sluicing operation.
Ultimate blowdown is achieved through the  moisture  content
(15-20  percent)  of the bottom ash discharged to trucks for
off-site use.  Fly ash, handled dry, is also trucked to off-
site uses.  The plant capacity is 600 Mw and operates in the
base-load mode.  The bottom ash recycle and handling  system
occupies  a  space  approximately 200 ft square.  The entire
system  cost   about   $2   million   including   equipment,
foundations,  re-piping, pumps, and instrumentation and took
approximately two years to  install  including  engineering,
purchasing,  delivery,  and  installation.   The  same plant
retrofit a system for  collecting  and  filtering  coal-pile
drainage  and  road  and  building  drainage.  The coal pile
trench is designed to handle drainage  from  a  Monce-in-30-
years"  rainfall (3.9 inches).  The filtering pond is 100 ft
in diameter and the filter bed is sand.  Trash from the  bar
screens  of the intake is buried on-site.  The demineralizer
neutralization  system  cost  about  $80,000,   the   boiler
cleaning  effluent  tanks  about  $100,000,  re-piping about
$250,000,  and  the  intake  screen  washing  system   about
$35,000.

Other  plants  employ  various  recycle and reuse techniques
depending upon their  water  needs,  environmental  effects,
plant  layout,  etc.   Plants  2119 and 4217 utilize cooling
tower blowdown as makeup to the ash sluicing system.   Plant
No.  3713  discharges  treated  chemical wastes from the ash
pond into the intake to the condenser cooling water  stream.
Plant  No.  4216 utilizes a closed-loop wet scrubbing device
for air pollution control, and plant 2512  sluices  fly  ash
                             341

-------
from  an electrostatic precipitator to a pond and reuses the
water in the sluicing system.

A number of plants, including Nos. 2512,  2525,  3601A,  and
4217  utilize central treatment facilities or ponds to treat
chemical type wastes to  acceptable  levels  for  discharge.
The effluents produced could be reused, but the availability
of  an  adequate,  cheap  water  supply  has  not  made this
necessary in these instances.

Recycling in nuclear plants and plants with no ash  sluicing
will  depend primarily upon treatment of cooling tower blow-
down and re-use of the blowdown as make  up  to  the  tower.
The  wastes resulting from water treatment could be recycled
to the influent of the water treatment plant.  Blowdown from
these  internal  recycling  schemes  would  be  treated   by
desalination  techniques  to  remove total dissolved solids,
and as a result, water produced by this treatment could also
be recycled.  In plants where a water surplus  would  occur,
the  intent  would  be complete treatment for removal of all
pollutants and discharge of clean  water  to  the  receiving
stream.   This  interpretation of "no discharge" is meant to
be no discharge of pollutants, rather than no  discharge  of
any  liquid  stream.   Generally, however, it is anticipated
that even nuclear plants and plants  with  no  ash  sluicing
would  not have a water surplus, but would require makeup to
the various internal recycling schemes.

In any case the degree  of  practicability  of  recycle  and
re-use  systems  would  be  favored in cases where; a) Tower
construction is corrosion resistant to water  high  in  TDS,
sulfates and chlorides,  b) Piping systems and equipment are
lined  or  resistant  to  corrosion.   c)   Condenser leakage
affecting feedwater quality for sustained power operation is
minimized  or  compensated  for.   d)  Sludge  handling  and
disposal  facilities  are adequately designed and available.
e) Designs for tower operation at a high number of cycles of
concentration could be feasible if windage and drift  losses
are  minimized to eliminate heavy carryover of solids to the
surrounding areas.

The extent to which wastewater management can  be  practiced
depends  on  the chemical constituents of the original water
supply.  Table A-V-2 , adapted from an unpublished paper  by
G.R.  Nelson, shows the typical raw water characteristics of
a water supply for powerplant water systems,  A water supply
falling within the range of concentrations shown on Table A-
V-2 could probably be used for a once-through cooling system
without treatment.  However, if this source of  supply  were
used  for  recirculating cooling, certain constituents might
                            342

-------
limit the number of cycles of concentration possible without
precipitation and resultant loss of heat transfer  capacity.
Since  the  number of cycles of concentration determines the
quantity of circulating water that can be maintained with  a
given  quantity  of  makeup,  it  is  generally desirable to
achieve the largest number of cycles possible for any  given
raw  water  analysis.   The  factors  limiting the number of
cycles are shown in Table A-V-1.

If the number of cycles  of  concentration  limited  by  the
hardness  of the water supply, the plant has several options
to increase the number of cycles and thereby reduce both the
makeup and discharge water quantitites.  These include:

1.  Makeup water  treatment  programs  (makeup  programs)
where  all  or  a  portion of the makeup is treated prior to
entering  the  system.   The  treatment  results  in  a  net
reduction in the makeup and discharge water quantities.

2.   Recirculating  water  treatment programs (recirculating
programs) where all or a portion of the recirculating  water
is  treated  and  recycled  back to the cooling system.  The
treatment results in a  net  reduction  in  the  makeup  and
discharge water quantitities.

3.   Slowdown water treatment programs (blowdown programs)  -
where all or a  portion  of  the  blowdown  is  treated  and
recycled  back to the cooling system.  Again, the net result
is a reduction in the makeup and discharge water quantities.

In summary, the concept of recyle or re-use is  not  new  to
the steam electric powerplant industry.  Many plants utilize
a  variety  of  recycle schemes to satisfy particular needs,
and these systems have the potential for  broad  application
in the industry to meet effluent limitations guidelines.

Effluent Reduction Benefits of Waste Water Treatment
to Remove Chemical Pollutants

The use of a conventional ash pond at a 1,000 megawatt coal-
fired  plant  (capacity factor = 0.6) typically achieves the
removal of over 1,200,000 Ib/day of total suspended  solids,
with  an overflow of 1,<*00 Ib/day of total suspended solids.
This is based on  1970  data  for  the  Bull  Run  plant  of
T.V.A.Z7»  and  an assumed 11% of ash solids in coal.  It is
estimated that about 70-75 percent of  the  U.S.  coal-fired
generating capacity uses ash ponds, as indicated by the data
sample  summarized in Table A-VII-20.  For a pulverized coal
burner about 15% of the ash generated is fly ash.   However,
the  overflow  discharge  of  total  suspended  solids  from
                           343

-------
                  Table A-VII-20

              Extent of Present Use of
             Chemical Waste Disposal Methods
              in Coal-Fired Powerplants   467
                       (1973)
 Method of
  Disposal
Number of Plants,
Generating Capacity
  of Plants, %
Ash Ponds

Direct to
  Receiving Waters

Sewers
     61

     24


     15
       72

       26
                    344

-------
combined ash ponds would most likely  be  mainly  the  fines
from  fly ash, which are the most difficult to remove in ash
ponds.  Therefore, the use of dry fly ash sluicing in  place
of ash ponds would remove an increment of about 1,400 Ib/day
of total suspended solids that would otherwise be discharged
from  the  ash  pond.   In  addition  to  removal  of  total
suspended solids the dry  fly  ash  system  would  have  the
further  benefit  of  removing  aluminum,  chromium, copper,
iron, manganese, mercury, nickel, selenium, zinc, and  other
pollutant parameters that might otherwise be discharged.

Recognizing   that   the  removal  of  suspended  solids  by
sedimentation is limited by the effluent concentrations that
are achievable, reduction in pond overflow discharge (at the
same effluent concentration) would proportionally reduce the
discharge of suspended solids  in  the  overflow  discharge.
Recirculating  bottom  ash sluicing systems, by reducing the
waste water discharge from sedimentation facilities such  as
ash  ponds,  therby  result  in  the reduction of bottom ash
total suspended solids in the  discharge.   In  some  cases,
where  both  bottom  ash and fly ash are settled in the same
ash pond and water is recirculated for bottom ash  sluicing,
further   clarification  treatment  of  the  final  combined
overflow from the pond to achieve effluent limitations based
as a model on separate ash ponds, would result in  suspended
solids  removals  comparable  to  these attained by separate
recirculating bottom ash systems.

Chemical treatment of metal equipment cleaning waste  waters
would  result  in  significant removals of copper, iron, and
other metals.  Average concentrations of copper and iron  in
boiler  tube  cleaning  waste  water,  where these data were
available and where chemical treatment would  be  needed  to
achieve  effluent  concentrations  of 1 mg/1 each for copper
and iron were as follows: 206 mg/1  copper  and  1,286  mg/1
iron.   Chemical  treatment  to  achieve  the above effluent
limitations would remove virtually of the copper and iron in
the untreated boiler tube cleaning  waste  water,  in  these
cases.

In  It  cases  where  data  on  cooling  tower blowdown were
available, chemical treatment for chromium, phosphorus,  and
zinc  removal  would not be required in all but 2 cases.  In
one case, a zinc concentration of 3 mg/1 was reported and  a
phosphorus   (as  P) concentration of 17.7 mg/1 was reported.
This is reflective of the  general  adequacy  of  simple  pH
adjustment  rather  than  the use of corrosion inhibitors to
control corrosion rate below 3  mils  per  year.   Generally
corrosion  inhibitors would be needed only for cooling tower
service   with   high   chloride   concentrations   in   the
                            345

-------
recirculating   water.389,***.    In  cases  where  chemical
addition of chromium, phosphorus, or zinc would be  employed
for  corrosion inhibition, typical maximum concentrations in
cooling tower blowdown would be as follows:

         30 mg/1 CrOU
         15 mg/1 Zn
         30 mg/1 PO4

Substantial reduction in the discharge  of  these  pollutant
parameters   would  be  obtained  in  cases  where  effluent
treatment were needed.

Effluent reduction benefits of the control of free available
chlorine and total residual chlorine in cooling water  would
be significant due to the large volume of cooling water used
by  this  industry, about HQ trillion gallons per year which
is roughly 10 percent of the total flow  of  water  in  U.S.
rivers  and  streams  per  year,  **3  and  because  of  the
widespread use of chlorine addition to cooling water (24,642
tons in 1970233) used by this industry.

Summary

Table  A-VII-21  provides  a  summary  of  the  control  and
treatment  technology  for  the  various waste streams.  The
table includes the effluent reduction achievable  with  each
alternative,  the  usage  in  the  steam electric powerplant
industry and  approximately  capital  and  operating  costs.
Table  A-VII-22  summarizes  flow  data for chemical wastes,
indicating the  range  of  values  from  reported  data  and
typical flows or volumes for each chemical waste stream.

The   costs  of  the  application  of  various  control  and
treatment technologies in relation to the effluent reduction
benefits to be achieved are  given  in  Table  A-VII-23  for
large  volume waste streams. Table A-VII-2U for intermediate
volume waste streams. Table A-VII-25 for  low  volume  waste
streams, and Table A-VII-26 for rainfall waste streams.
                        346

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                               TABLE M-VII-21
                               CHEMICAL WASTES
                        CONTROL & TREATMENT TECHNOLOGY
Control and/or
Treatment
Pollutant Parameter Technology
Common:

pH Neutralization
with chemicals
Dissolved Solids 1.
2.
3.
Suspended Solids 1.
2.
3.
Specific:
Phosphate 1 .
(Slowdown, Chemical
Cleaning, Floor &
Yard Drains, Plant
Laboratory s Sampling)
2.
Iron 1 .
Chemical Cleaning
Coal Ash Handling,
Coal Pile Drainage) 2.
Copper 1.
(Once-through
Condenser Cooling)
Copper 1 .
(Slowdown, Chemical
Cleaning)
2.
3.
Mercury 1.
(Coal Ash Handling
s Coal Pile Drainage)
2.
3.
Vanadium !•
(Chemical Cleaning)
2.
Vanadium 1.
(Oil Ash Handling)
2.
Concentration and
evaporation
Reverse Osmosis
Distillation
Sedimentation
Chemical Coagulation
and Precipitation
Filtration
Chemical coagulation
and Precipitation
Deep Well Disposal
Oxidation, chemical
coagulation &
precipitation
Deep Well Disposal
Replace condenser
tubes with stain-
less steel or
Titanium.
Chemical Coagulation
and Precipitation
Ion Exchange
Deep Well Disposal
Reduction & Precip-
itation
Ion Exchange
Adsorption
H S Treatment & .
Precipitation ^ •
Ion Exchange /
Convert to Dry
Collection
Total Recycle with
Slowdown s Pre-
Effluent
Reduction
Achievable
Neutral pH
Complete Removal
50-95*
60-90%
90-95%
95-99%
95%

Industry Costs
Usage Capital Operating
Common 510-20,000 (tanks, • $3-30,000 (Chemicals,
feeder, etc.) labor, etc.)
Not generally $250,000-51,660,000 $150,000-$450,000
in use - De- from Table A-VIII-5 ; from Table A-VIII-6;
salinization costs are signifir costs are significantly
technology cantly less in areas less in areas where
where evaporation evaporation ponds are
ponds are feasible, feasible.
Not in use - SO-SO C/1000 gal.
Desalinization total cost.
technology.
Not in use - 80-150 C/1000 gal.
Desalinization total cost.
technology.
Extensive $1000-S20,000 1-20C/1000 gallons
Mw
based on 500 gpd /Mw
Moderate 5 10, 000-$ 35 ,000 1-20C/1000 gallons
Mw
based on 500 gpd /Mw
Not generally $7 ,000-$30,000 1-20C/1000 gallons
practiced-water Mw
treatment based on 500 gpd / Mw
technology.
Not generally $io,000-$35 ,000 1-200/1000 gallons
practiced-water j.;w
treatment ^sea on 500 gpd /f;w
technology.
Ultimate Disposal Not practiced Costs extremely variable-dependent
primarily on geologic conditions.
removal to
0.1 mg/1

Elimination of
discharge .
Removal to
0.1 mg/1
Removal to
0.1 mg/1

Removal to
0.3 mg/1
Removal to
0.1 mg/1
Removal to
50 Mg/1
Removal of low
concentrations
difficult to
achieve
Ultimate
Disposal
Complete recycle
of liquid
Limited usage $150-4, OOOxlOJ 10-lOOc/lOOO gal.

Done in several Prohibitively No incremental
plants where tubes expensive-would operating cost.
have erroded or not be done except
corroded-not done where retubing is
for environmental required for process
reasons. reasons.
Limited usage $100-$9, 000/1000 10-350C/1000 gal.
gpd capacity
Not Practiced $400-$1200/1000 31-81C/1000 gal.
gpd capacity
s escri e a ove
Limited usage $700/1000 gpd 7«-27*/1000 gal.
Not practiced $18,000-$22,000/ $1/1000 gal.
1000 gpd
Not practiced $5000-$50,000/ $0.50-$2/lb.
1000 gpd mercury removed
Not practiced Cost Data Not Available
Not practiced Cost Data Not Available
Practiced in Cost Data Not Available
several plants
Not generally Cost Data Not Available
practiced
cipitation
                        347

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                                                       Table  A-VII-21
                                                         CHEMICAL WASTES
                                                  CONTROL & TREATMENT TECHNOLOGY  (continued)
Pollutant Parameter
Chlorine
(Once-through Con-
denser Cooling)
Control and/or
Treatment
Technology
1. Control of Residual
Cl with automatic
instrumentat ion
2. utilize mechanical
Effluent
Redact ion
Achievable
Control to
0.2 mg/1
Eliminates
Industry
Usage
Limited usage in
the industry-
Technology from
sewage treatment
practiced in some
Costs
Capital
$5,000
No Cost Data
Operating
Negligible
Available
                         cleaning
                                             Cl  discharge   plants-all systems
                                                            are not capable of
                                                            being converted to
                                                 	mechanical cleaning.
 Chlorine
 (Recirculating)
1.  Control of Residual
    Cl  with automatic
    instrumentat ion
                                                            -As described above-
                     2.  Reduction of Cl
                         with sodium
                         bisulfite
                        Below detect-  Being installed in
                        able limits    a new nuclear
                                       facility,-however
                                                                                                     Data   Available

Aluminum/Zinc 1.
(Water Treatment,
Chemical cleaning,
Coal Ash Handling, 2.
Coal Pile Drainage)
3.
Oil 1.
(Chemical cleaning,
Ash Handling, Floor
s Yard Drains)
2.
Phenols 1.
(Ssh Handling, Coal
Pile Drainage, Floor
s Yard Drains) 2.
3.

Chemical Precip-
itation
Ion Exchange
Deep Well Disposal -
Oil-water Separator
(Sedimentation
with skimming)
Air Flotation
Biological
Treatment
Ozone Treatment
Activated Carbon

Removal to
1.0 mg/1
Similar to
excess NaHSO is
discharged.
Limited usage $500-53000/1000 gpd 10-180C/1000 gal.
Copper
	 As described above 	 . 	
Removal to
15 mg/1
Removal to
10 mg/1
Removal to
1 mg/1
Removal to
< 0.01 mg/1
Removal to
< 0.01 mg/1
Common usage $1,500-$ 15 ,000 No data
based on 500 gal/Mw
25-400 Mw range
Limited usage $5,000-$50,000 No data
N-^t practical $130- $2800/1000 gpd 22C/1009 gal.
in the industry.
Not practiced No data No data
in the industry.
Not practiced $50-$350/1000 gpd 4C-15«/1000 gal.
in the industry.
 Sulfate/Sulfite
(Water Treatment,
Chemical cleaning.
Ash Handling, Coal
Pile Drainage, SO
Remova 1)
Ion Exchange(Sulfate)
Oxidation s Ion
Exchange (Sulfite)
                                             75-95%
Not practiced     Total cost of  $2.00/1000 gal.
in the industry.
Ammonia
(Water Treatment,
Slowdown, chemical
Cleaning, Closed
1. Stripping



50-90%



Not practiced;
several installa-
tions in sewage
treatment
Total cost



- 3C/1000 gal.






Cooling Water Systems)



Oxidizing Agents
(Chemical Cleaning)


BOD/COD
(Sanitary Wastes)
COD (Water Treatment
Chemical cleaning)

Fluoride
(Chemical Cleaning)
2. Biological
Nitrification
3. Ion Exchange
Neutralization with
reducing agent and
precipitation where
necessary.
Biological Treatment

,1. chemical Oxidation
2. Aeration
3. Biological Treat.
Chemical Precipitation

Removal to
2 mg/1
80-95%
Neutral pH &
>95% removal


85-95%

85-95%
85-95%
85-95%
Removal to
1 mg/1
Not practiced for
these waste streams
Not practiced
Limited usage



Common practice

Limited usage
Not practiced
Not practiced
Limited usage

No

Total cost.
No



$25,000-$35

No
No
No
Total cost

Data

- IOC/1000
Data



,000

Data
Data
Data
Available

gal.
Available



Negligible

Available
Ava ilable
Available
- 10-50C/1000 gal.


 Boron               Ion Exchange
(Low Level Radwastes)
                       Removal to       Not  generally
                         1 mg/1         practiced-radio-
                                        active  material would
                                        concentrate  on ion
                                        exchange  resin requir-
                                        ing  inclusion in  solid
                       348              radwaste  disposal
                                        system.
                                                                                                        Available

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                                                      TABLE A-VII-22

                                                FLOW RATES-CHEMICAL WASTES
Waste Stream
                                  Reported Data
                        Waste Flow or Volume
                                                Frequency
                                                                 Typical
                                                              Flow or Volume
                                                                                   Basis
                                                                                                    Remarks
Condenser Cooling Water
  Once-Through

  Recirculating
Water Treatment
  Clarification
  Softening
  Ion Exchange
                        20-7200 x 10  GPD
                          No Discharge
                          No Discharge,
                         1-533,00 x 10  GPD
  Evaporator
Boiler Slowdown
Chemical Cleaning
  Boiler Tubes
  Boiler Fireside

  Air Preheater
  Misc. Small Equip.
  Stack
  Cooling Tower Basin

Ash Handling
Dra*inage
  Coal pile
                        0.1-1060 X 10J GPD
                        0.05-1120 X 10  GPD
                        3-5 Boiler Volumes
24-720 x 10J GAL.

43-600 x 103 GAL.
No reported data
No reported data
No reported data

5-32,000 x 103 GPD
                        17-27 x 10  GAL/YR.
  Floor & Yard Drains   No reported data
Air Pollution Control   No Discharge
  Devices

Misc. Haste Streams
  Sanitary Wastes       No reported data
Plant Laboratory and    No reported data
  Sampling

Intake Screen Backwash  No reported data
Closed Cooling Systems  No reported data

Low Level Rad Wastes    Mo reported data




Construction Activity   No reported data
                                      500-1500 GPM/Hu

                                        Varies from 0.3% to 4% of
                                        curculatlng water flow.
                                                52-365
                                                cycles/yr.

                                                300-365
                                                cycles/yr.
                                                25-365
                                                cycles/yr.
                                                once/7 mos.-  1 boiler vol.per
                                                once/100 mos. 1-2 hrs.-Boiler
                                                              draindown time.
                                                2-8/yr.       300,000 GAL.
                  Flow reported in PPC
                  Form 67.
                  Slowdown  depends on water
                  quality and varies from
                  2-20 concentrations.
                                                                          Extremely variable-
                                                                          depending on raw water
                                                                          quality.
                                                                          Extremely variable-
                                                                          depending on raw water
                                                                          quality.

                                                                          Flow reported in FPC
                                                                          Form 67.
                                                4-12/yr.
                                                              200,000 GAL.
Frequency-once
per 24-30 mos.

5/yr.

6-12/yr.
                                                Dependent
                                                on rainfall
                                                                                Reported data
                                                                                based on 43-60
                                                                                inches of rain
                                                                                year.
                                                                                                  Cleaned infrequently
                                                                                                  Cleaned infrequently

                                                                                                  Overflow from as!; ponds
                                                                                                  reported in FPC Form 67.
                                                                          Flow dependent upon
                                                                          frequency,  duration and
                                                                          intensity of rainfall

                                                                          Flow dependent upon fre-
                                                                          quency & duration of
                                                                          cleaning and stormwater
                                                                          runoff.
                                                              25-35 gal/capita/ Personnel:
                                                                day             operators-1 per 20-40 N"
                                                                                maintenance-1 per 10-15 M»
                                                                                administrative-1 per 15-25
                                                              5 gal./day
                                                                                                  Nominal,  variable flow
                                                                                                  Guideline requires col-
                                                                                                  lection S removal of
                                                                                                  debris-flow data not
                                                                                                  significant.
                                                                                                  Flow extremely vari-
                                                                                                  able depending on treat-
                                                                                                  ment techniques,  leakage,
                                                                                                  etc.

                                                                                                  Flow depends primarily
                                                                                                  on rainfall.

-------
                                       Table A-VII-Z3
                               COSTS/EFFLUENT REDUCTION BENEFITS
              CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS OTHER THAN HEAT
                              HIGH VOLUME WASTE STREAMS-

           Waste Stream: Nonrecirculating main condenser cooling water
           Pollutant / Technology
                                                  Cost / Effluent Reduction Benefit,
                                                                        concentration
CO
en
o
Chlorine-free available

  Uncontrolled addition(S)
  Controlled addition(S)  less than
  Shutdown mechanical cleaning(S)
  On-line mechanical cleaning (S)
          Chemical addition treatment*(N)
          Alternative biocide use*(N)
       Copper
          Present system(C)
          Alternative condenser
          tubs material(S)*

          One-stage chemical treatment (N)
              Base
          0.01/2
          0.01/approaching 0
          0.01/approaching 0
             for existing units
less than 0.01/approaching 0
             for new units
          Prohibitive
           Unknown

              Base
        Prohibitive for existing
                       units
          0.01/0 for new units
          Prohibitive
        Meaning of   C = commonly employed
          Symbols   CT = currently transferrable
                    PT = potentially transferrable
                                              N
                                              S
                                              *
         net  luiown  to be  practiced
         sonm usage
         i:,ay  substitute one  pollutant
           for  another

-------
                                             Table A-VII-24
                                     COSTS/EFFLUENT REDUCTION BENEFITS
                    CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS OTHER THAN HEAT
                                  -INTERMEDIATE VOLUME WASTE  STREAMS-

          Waste  Streamsi  Slowdown from recirculating main  condenser cooling water systems
                          Nonrecirculating ash sluicing  water
                          Nonrecirculating wet-scrubber  air pollution  control systems
                          Nonrecirculating house  service water
                Pollutant  / Technology
 Chlorine-free available
    Uncontrolled addition(S)
    Controlled addition(S)
    Shutdown mechanical cleaning(S)
    On-line mechanical cleaning(S)
    Chemical addition treatment*(S)
    Alternative biocide use*(N)
 Copper-total
    Present system(C)
    Alternative condenser
    tube material(S)*

    One-stage chemical treatment(N)
 Chemical Additives
    Uncontrolled addition(S)
    Controlled addition(S)
    Chemical substitution*(S)
    Design for corrosion protection(C)
 Mercury-total
    Present system(C)
    One-stage chemical treatment(CT)
    Fuel substitution(N)
 Oil and Grease
    Present system(C)
    One-stage separation(S)
    Two-stage separation(CT)

Total Phosphorus  (as P)
    Present system (S)
    One-stage chemical  treatment(CT)
    Chemical treatment
    with filtration(CT)
    Chemical substitution (PT)
 pH Value
    Present system(C)
    Coneutralization(C)
    Chemical addition (6)
 Total Suspended Solids
    Present system(C)
    Conventional  solids  separation(C)
    Fine solids  separation(CT)
    Dry  ash handling system(S)
 Total Dissolved  Solids
    Present system(N)
    Brine concentration(CT)
ChromiUM-total
   ^"Present system  (S)
    Chemical treatment  (CT)
    Chemical substitution (PT)
Zinc-total
    Present system  (S)
    Chemical treatment  (CT)
    Chemical substitution (PT)
                                                            Cost / Effluent Reduction Benefit,
                                                       [mill/** j / C«g/i]ef£luflnt concentratio:
                                                             Base
                                                   less than 0.01/2
                                                             0.01/approaching 0
                                                             0.01/approaching 0
                                                                for existing units
                                                   less than 0.01/approaching 0
                                                                for new units
                                                             0.01/approaching 0
                                                             Unknown

                                                             Base
                                                          Prohibitive
                                                             for existing units
                                                             0.01/0 for new units
                                                             0.03/1

                                                             Base
                                                         Better than base
                                                             Unknown
                                                             Costly for existing
                                                               closed coaling
                                                                   systems
                                                   less than 0.01/approaching 0
                                                               for new  systems

                                                             Base
                                                            Unknown/0.3
                                                             Unknown

                                                             Base
                                                             0.01/10
                                                             0.02/8
                                                              Base
                                                            0.03/5

                                                            0.05/less than 5
                                                              Unknown

                                                              Base
                                                          less than 0.01
                                                          less than 0.01

                                                              Base
                                                              0.01/15
                                                           Prohibitive
                                                              0.01/sign. red.

                                                              Base
                                                           Prohibitive

                                                              Base
                                                        (?1/1000  gal)/0.2
                                                            Unknown

                                                              Base
                                                            0.05/1
                                                            Unknown
Meaning of     C = commonly employed               N
  Symbols     CT = currently transferrable         S
              PT = potentially transferrable       *
                                                        not known to be practiced
                                                        some usage
                                                        may substitute one pollutant
                                                          for another
                                       351

-------
                          Table A-Vtl- 25
                  COSTS/EFFLUENT REDUCTION BENEFITS
CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS OTHER THAN HEAT
                    -LOW VOLUME WASTE STREAMS-

    Waste Streamsi Blowdown from recirculating ash-sluicing  systems
                   Slowdown form recirculating wet-scrubber  air
                      pollution control  systems
                   Boiler blowdown
                   Cooling tower basin cleanings
                   Floor drainage
                   Intake screen backwash
                   Laboratory and sampling streams
                   Low-level radwastes*
                   Miscellaneous equipment cleaning
                   - Air preheater
                   - Boiler fireside
                   - Boiler tubes
                   - Small equipment
                   - Stack, etc.
                   Sanitary system
                   Service and small cooling water systems blowdown,  etc.
                   Water treatment
      Technology / Pollutant
      Cost / Effluent Reduction Benefit,
[mill/kwh] , [mg/1] „,            ,_   .
           '   y   effluent concentration
Present System(C)
One-Stage Chemical Treatment(S)
     Copper-total
     Iron-total
     Heavy metals in general
     Oil and grease
     pH value

     Numerous misc. parameters
Two-Stage Chemical Treatment(CT)
     Chromium-total
     Copper-total
     Iron-total
     Heavy metals in general
     Oil and grease
     pH value
     Total suspended solids
     Numerous misc. parameters
Brine Concentration and Recycle(PT)
     All parameters

Biological Treatment(C)

     BOD, etc.
                                                        Base
                                             0.05 mill/kwh
                                                            10 mg/1
                                                            10 mg/1
                                                            10 mg/1
                                                            1.0 IK-/'
                                                         6.0 tc -. . 0
                                                            13 uiy/1
                                                      significant reductions
                                             0.1  mill/kwh
                                             0.5
                0.2  mg/1
                  1  mg/1
                  1  mg/1
                  1  mg/1
               < 10  mg/1
              6.0 to 9.0
                 15  mg/1
           significant  reductions
       mill/ kwh
                                                         no discharge
                                             0.01 mill/kwh

                                                         municipal stds.
  Meaning of   C = commonly employed
    Symbols   CT = currently transferrable
              PT = potentially transferrable
      N =  not  known to be practiced
      S =  some usage
      * =  no applicable technology due to
           possible radiation hazards
                                      352

-------
                                    Table A-VII- 26
                            COSTS/EFFLUENT REDUCTION BENEFITS
          CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS OTHER THAN HEAT
                             -RAINFALL RUNOFF WASTE STREAMS-
          Waste  Streams:
               Coal-pile drainage
               Yard and roof drainage
               Construction activities
             Technology / Pollutant
                                            Cost  / Effluent  Reduction Benefit,
                                      [mill/kwh ]  ,  [mg/1 ]  ,..-    .        .   . .
                                           '      '    ^   effluent concentration
CO
Ul
CO
Present System(C)

Conventional Solids Separation(S)

     Oil and grease
     pH value                    /
     Total suspended solids.

One-Stage Chemical Treatment of
 Polluted Portions of Runoff (CT)
     Oil and grease
     pH value
     Total suspended solids
     Numerous misc. parameters

One-Stage Chemical Treatment of
  Entire Runoff(N)

Two-Stage Chemical Treatment(N)
         Base

OoOl mill/kwh
            no reduction
            no change
               15 mg/1


0.01 mill/kvrti
               10 mg/1
            6.0 to 9.0
               15 mg/1
          significant reductions

unknown


unknown
           Meaning  of
              Symbols
             C = commonly employed
            CT = currently transferrable
            PT = potentially transferrable
       N = not known to be practiced
       S = some usage

-------
                           PART A

                      CHEMICAL WASTES

                        SECTION VIII

         COST, ENERGY AND NON-WATER QUALITY ASPECTS
Irvtroduct ion

This  section  discusses  cost estimates for the control and
treatment technology  discussed  in  the  previous  section,
energy  requirements  for this treatment technology and non-
water quality related aspects of  this  technology  such  as
recovery  of  byproducts,  ultimate  disposal  of brines and
sludges, and effects on the overall energy situation.

The estimates contained herein assume ample availability  of
land.   It  is recognized that powerplants located in highly
developed urban areas  may  incur  costs  several  times  in
excess of those shown,  other assumptions include no unusual
foundation  or  site preparation problems.  Estimates do not
consider regional differences in construction costs.


Due to the wide range of water volumes required  from  plant
to  plant  for  the individual unit operations involved, and
further, due to the wide range   (frcm  plant  to  plant)  of
costs  per  unit  volume of water treated, which are further
related to the effluent reductions obtained, the costs  vary
widely  for  the  removal  of specific pollutants to various
degrees.  For example,  boiler  fireside  chemical  cleaning
volumes  vary  from  24,000 gal to 720,000 gal per cleaning,
with cleaning frequencies ranging from  2  to  8  times  per
year.    The   operating  costs  of  chemical  precipitation
treatment for copper and iron removal  to  1  mg/1  effluent
concentration and for chromium removal to an effluent of 0.2
mg/1 range from $0.10 to $1.30/1000 gal.  Furthermore, there
are  approximately 10 or more separate unit operations which
are sources of waste water at power generating plants,  each
with   its   station-specific  flow  rate  and  waste  water
characteristics,   as   well    as    cost    peculiarities.
Site-related   factors   concerning  the  practicability  of
various re-use practices  make  these  .practices  even  more
difficult to cost, due to the added complexities involved.
                            355

-------
Central Treatment Plant Costs

Although   powerplants  produce  many  different  wastewater
streams  with  different  pollutants  and   different   flow
characteristics,  the  most  feasible  concept  of treatment
consists of the combination  of  all  compatible  wastewater
streams,  with equalization or holding tanks to equalize the
flow through the treatment units.  Figure A-VIII-1  shows  a
typical  flow diagram for a possible central treatment plant
for coal-fired powerplants.

Wastewater treatment facilities for treating chemical wastes
therefore consist essentially  of  a  series  of  tanks  and
pumps,  and  interconnecting piping:  special equipment such
as  pressure  filters,  vacuum  filters,   centrifuges,   or
incinerators  as  may  be required.  Tanks serve for several
purposes, as equalization  tanks  to  permit  the  following
units   to   operate  under  constant  flow  conditions,  as
neutralization tanks to adjust acidity or alkalinity, or  as
coagulation and precipitation tanks to provide for mixing of
a  coagulant,  the  formation  of  the  precipitates and the
separation of the precipitates from the  treated  flow.   In
most  cases,  the  mechanical equipment inside the tank is a
minor cost consideration, although in the  case  of  certain
types  of tanks used for softening and similar reactions the
equipment cost may be significant.  Chemical feeders may  be
of  the  dry  volumetric  type  or of the solution type.  In
either case, the cost of the feeder is likely to  be  minor,
although  costs  of  associated equipment for the storage of
chemicals is often significant.   A  substantial  amount  of
data is available on chemical feeders.

Cost  curves  are  given  in  Figures  A-VIII-2,  3  for the
principle items of equipment required for the  treatment  of
chemical type waste water.

A  cost  analysis  is based on  a central treatment plant as
shown in Figure A-VIII-1 for  all  low-'-olume  waste  waters
containing  chemical  pollutants.   The design flows assumed
for this plant are  given  in  the  figure.   The  estimated
equipment  sizes  and  costs  for  central  treatment plants
corresponding to 100 Mw and 1,000 Mw coal-fired plants, oil-
fired plants, gas-fired plants and nuclear plants are  given
in  Tables A-VIII-1, 2, 3 and 4 respectively.  Total capital
costs for these plants, including  equipment,  installation,
construction,  engineering  and contingency costs, are given
in Tables A-VIII-5, 6, 7 and 8 respectively.  Capital  costs
for  plants of capacities other than 100 and 1,000 Mw can be
estimated from Figure  A-VIII-U.   Annual  costs,  including
fixed  changes against capital and operating and maintenance
costs are given in Tables A-VIII-9, 10, 11 and 12.  Cost for
labor, chemicals and power are  based  on  the  cost  versus
                            356

-------
CO
CP
—I
                                       Figure A-VIII-1
                FLOW SHEET -  COAL  FIRED PLANT CENTRAL TREATMENT PLANT
             BOILER TUBE
EQUIPMENT CLEANINGS
90 gal/mw
(0.25 gpd/mw)
BOILER FIRESIDE
800 gal/mw
(4.44 gpd/mw)
AIR PREHEATER
700 gal/mw
(11. 7 gpd/mw)
MISC, 210 gal/mw


EQUALIZATION
TANK41
1800 gal/mw

             (1.17 gpd/mw)
          ION EXCHANGE
88 gpd/mw
         LABORATORY WASTES
             10 gpd/mw

           COOLING TOWER
           BASIN WASHING
             (210 gal/mw)
             1.17 gpd/mw
           RECIRCULATING
        SCRUBBER 20 gpd/mw
          BOILER BLOWDOWN
             52 gpd/mw
             FLOOR DRAINS
             30 gpd/mw
                                                                                      LIME 7.2 x 10~4-!-b
                                                                                                 gal
                                                                                          (0.013 Ib/day/mw)
                                                  18  gal/mw
                                                  pH=3 (assume)
                                                                                                 REACTOR
                                                                                                 (0.8 gal/mw)
                                                                                                 1 HR. DETENTION
                                                                                                    pH 8.5
172 gpd/mw
FLOCCULANTS
  1lb/1000 gal
 (0.13lb/day/mw)
                                                                                                          DISCHARGE TO
                                                                                                          RECEIVING WATERS
                                                                                    1% SLURRY
                                                                                    20LB/DAY/MW
                                                                                    (3.0 gpd/mw)
                                                              30 gpd/mw
                                                                                                      SLUDGE
                                                                                                   (0.2 Ib/day/mw)

-------
                1,000
oo
en
          en
          M
          m
          rH
O

W

•g
fl
(0
3
O
^
+J
          -P
          CO
          O
          U

          3
          s
                   100
                    10

                        1              10            100             1,000          10,000

                             Capacity, thousands of gallons



                    Figure A-VIII-2 Costs of Equalization Tanks  and Oil Removal Tanks

-------
                   1,000
10
en
10
n

CTl
iH


05

to
•H
H
O
Tf

4-1
O

w
'O

n)
0)
              CO
              O
              O

              -P
              C


              I
              •H
              w
                     100    •--
                      10
                                 ,- ";-..- "i ij i"r'" •; n~T~i'"
                                r-^jT-ir-iTi!-! :n-
                  Figure A-VIII-3
                              1               10             100             1,000

                      Capacity, thousands of gallons  per day


                             Costs of  Clarifiers, Reactor Systems,  and Filters

-------
                                        Table A-VIII-1

                                   Estimated Equipment Costs

                      Central Treatment Plant for Coal-Fired Powerplants
Description
Equalization Tank No.l (gal)
No. 2
No. 3
Oil Removal- Tank No.l (gal)
No. 2
Reactor System (GPD)
Clarifier (GPD)
' Filter* (GPD)
Pumps and Piping
Major Equipment Cost
100 Mw
Size/Capacity
180,000
38,000
3,000
1,800
3,000
1,800
22,000
300
-

$ (1000)
38
12
1.7
3.5
4.5
2.7
7
1
10.9
81.3
1000 Mw
Size/Capacity
1,800,000
380,000
30,000
18,000
30,000
18,000
220,000
3,000
-

$ (1000)
111
65
10
9.5
12.5
4.5
22
10
20.2
264.7
co

-------
                                       Table A-VIII-2

                                  Estimated Equipment Costs

                     Central Treatment Plant for  Oil-Fired Powerplants
Description
Equalization Tank No.l (gal)
No. 2
No. 3
Oil Removal Tank No.l (gal)
No. 2
Reactor System (GPD)
Clarifier (GPD)
Filter* (GPD)
Pumps and Piping
Major Equipment Cost
100 Mw
Size/Capacity
180,000
38,000
1,500
1,800
1,500
1,800
20,500
300


$(1000)
38
12
1
3.5
3.3
2.7
6.8
1
10.9
79.2
1000 Hw
Size/Capacity
1,800,000
380,000
15,000
18,000
15,000
18,000
205,000
3,000

i
$(1000)
111
65
5.8
9.5
8.6
4.5
21
10
20.2
255.6
oo
en
       * Note: 5 gpm/ft2 and $265/ft2  (UWAG  study page  11-24)

-------
                                      Table A-VIII-3

                                  Estimated Equipment Costs

                     Central Treatment Plant for Gas-Fired Powerplants
Description
Equalization Tank No.l (gal)
No. 2
Reactor System (GPD)
Clarifier (GPD)
Filter* (GPD)
Pumps and Piping **
Major Equipment Cost
100 Mw
Size/Capacity
30,000
36,000
142
15,300
210


$ (1000)
10
11
1.5
5.8
1
5.5
34.8
1000 1'iw
Size/Capacity
300,000
360,000
1,420
153,000
2,100

,
$ (1000)
55
62
2.6
18
7
10.1
154.7
co
cr>
ro
       *  Note:  5  gpm/ft2 and $265/ft2 (UWAG study page 11-24)

     ** Note: Assumed to be 50% of the size for the corresponding coal-fired case

-------
                                       Table A-VIII-4

                                  Estimated Equipment Costs

                     Central Treatment Plant for Nuclear Powerplants
Description
Equalization Tank No.l (gal)
Reactor System (GPD)
Clarifier (GPD)
Filter* (GPD)
Pumps and Piping **
Major Equipment Cost
100 Mw
Size/Capacity
21,000
36,000
142
15,300
210

$(1000)
7.2
11
1.5
5.8
1
5.5
32
1000 Mw
Size/Capacity
210,000
360,000
1,420
153,000
2,100
.
$(1000)
41
62
2.6
18
7
10.1
140.7
co
01
co
       *  Note:  5 gpm/ft2 and $265/ft2 (IWAG study page 11-24)

      ** Note:  Assumed to be 50% of the size for the corresponding coal-fired case

-------
                                       Table A-VIII-5
                                  Estimated Total Capital Costs
                          Central Treatment Plant for Coal-Fired Powerplants
Item

Major Equipment Cost
Installation Cost
@ 50% for new sources
@ 100% for retrofit
Instrumentation
d> 20%
Construction Cost
Engineering
@ 15%
Contingency
@> 15%
Total Capital Cost
($/kw)
100 Mw
Retrofit
$(1000)
81,3
81.3


16.3

178.9
26.8
26.8
232.5
(2.33)
New Sources
$(1000)
81.3
40.7


16,3

138.3
20.8
20.8
179.9
(1.80)
1000 Mw
Retrofit
$(1000)
264.7
264.7


52.9

582.3
87.3
87.3
756.9
(0.76)
New Sources
$(1000)
264.7
132.4


52.9

450.0
67.5
76.5
585.0
(0.59)
CO
O!

-------
                                       Table A-VIII-6

                                 Estimated Total  Capital  Costs

                         Central Treatment Plant  for Oil-Fired Powerplants
Item
Major Equipment Cost
Installation Cost
@ 50% for new sources
@ 100% for retrofit
Instrumentation
d> 20%
Construction Cost
Engineering
@ 15%
Contingency
@ 15%
Total Capital Cost
(£/kw)
loor-v
Retrofit
$ (1000)
79.2
79.2
15.8
174,2 '
26.2
26.2
226,6
(2.27)
New Sources
$ (1000)
79.2
39.6
15.8
134.5
20,2
20.2
175.0
(1.75)
1000 Mw
Retrofit
$(1000)
255.6
255.6
51.2
562.4
84,4
84.4
731.2
(0.73)
New Sources
$(1000)
255.6
127.8
51.2
434.6
65.3
65.3
565.2
(0.57)
CO

-------
                                     Table A-VIII-7
                                 Estimated Total Capital Costs
                         Central Treatment Plant for Gas-Fired Powerplants
Item

Major Equipment Cost
Installation Cost
@ 50% for new sources
f> 100% for retrofit
Instrumentation
@ 20%
Construction Cost
Engineering
d> 15%
Contingency
@ 15%
Total Capital Cost
($Aw)
100 IV
Retrofit
$ (1000)
34.8
34.8

7.0
76.6
15.3
15.3
107.2
(1.07)
New Sources
$(1000)
34.8
• 17.4

7.0
59.2
8.9
8.9
77.0
(0.77)
1000 MM
Retrofit
$(1000)
154.7
154.7

30.9
340.3
51.1
51.1
442.5
(0.44)
New Source^
$(1000)
154.7
77.4

30.9
263.0
39.5
39.5
342.0
(0.34)
er>

-------
                                         Table A-VIII-8

                                  Estimated Total Capital Costs

                          Central Treatment Plant for Nuclear Powerplants
Item
Major Equipment Cost
Installation Cost
d> 50% for new sources
@ 100% for retrofit
Instrumentation
@ 20%
Construction Cost
Engineering
@ 15%
Contingency
@ 15%
Total Capital Cost
($/ kw)
100 Mw
Retrofit
$(1000)
32.0
32.0

6.4
70.4
10.6
10.6
91.6
(0.92)
New Sources
$ (1000)
32.0
16.0

6.4
54.4
8.1
8.1
70.6
(0.71)
1000 Mw
Retrofit
$(1000)
140.7
140.7

28.1
309.5
46.5
46.5
402.5
(0.40)
New Sources
$(1000)
140.7
70.4

28.1
239.2
35.8
35.8
310.8
(0.31)
co
er>

-------
n
r»
CTi
CO
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H
H
O
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M-l
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m
CO
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CO
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.p
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ft
(0
n)
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W
10,000
     1,000
        100
    10
                         -.--•
        ii:_i	RaKk- " !	i ;! :H' i-:. i
        _'_—;--Goai-f:iried:--   '  '
                                     Ex i st i ng Pi a nt s
                                          Plants
                                                          10,000
      10              100            1,000
          Plant Generating  Capacity, megawatts

  Figure  A-VIII-4   Estimated Total Capital Costs of Central

                          Treatment Plants
                      368

-------
                                  Table A- VIII-9

                               Estimated  Annual Costs

                   Central Treatment Plant  for  Coal-Fired Powerplants*

Item

Construction Cost (CC)
Total Capital Cost (TCC)
Maintenance @ 3% of CC
Fixed Charges @ 15% of TCC
Chemicals and Power '
Labor
Total Annual Cost
Unit Cost, mills/kwh
Base-load (0.77 capacity factor)^
Cyclic (0.44 capacity f actor )#
Peaking (0.09 capacity f actor )#
100 jy
Retrofit
.5 (1000)
178.9
232.5
5.4
34.9
4.2
100.0
144.5
0.214
0.375
1.84
Iw
New Sources
$ (1000)
138.3
179.9
4.1
27.0
4.2
100.0
135.3
0.201
0.353
1.72
1000 i
Retrofit
$ (1000)
582.3
756.9
17.5
113.5
38.0
190.0
359.0
0.055
0.096
0.467
4W
New Sources
$ (1000)
450.0
585.0
13.5
87.7
38.0
190.0
329.2
0.049
0.086
0.422
CO

vo
     * Note: Flow basis is  220
    # Note: Assumes  full  costs of maintenance,  chemicals,  power, and labor.

            These costs would  actually be  less  than shown  and would reflect the

            extent of utilization of the plant.

-------
                                   Table A-VIII-10
                                  Estimated Annual  Costs
                      Central Treatment Plant for Oil-Fired Powerplants*

Item
i
! Construction Cost (CC)
!
1 Total Capital Cost (TCC)
i Maintenance @ 3% of CC
; Fixed Charges @ 15% of TCC
Chemicals and Power
Labor
Total Annual Cost
Unit Cost, mills/kwh-
Base-load (0.77 capacity factor)*
Cyclic (0.44 capacity factor) #
Peaking (0.09 capacity factor) #
100 1
Retrofit
$ (1000)
174.2
226.6
5.3
34.0
4.0
98.0
141.3
0.211
0.369
1.80
^w
New Sources
$ (1000)
134.5
175.0
4.0
27.2
4.0
98.0
133.2
0.198
0.346
1.69
1000
Retrofit
$ (1000)
562.4
731.2
16.9
109.7
36.0
185.0
347.6
0.052
0.091
0.445
DJw
New Sources
$ (1000)
434.6
565.2
13.0
84.8
36.0
185.0
318.8
0.047
0.082
0.400
CO
•>J
o
       * Note: Flow basis is 205  GPD/Mw
       # Note: Assumes full  costs of maintenance, chemicals, power, and labor.
               These costs would  actually be less than shown and would reflect the
               extent of  utilization of the plant.

-------
                             Table A-VIII-11
                           Estimated Annual Costs
               Central.Treatment Plant for Gas-Fired Powerplants*



CO
•~J


Item
Construction Cost (CC)
Total Capital Cost (TCC)
Maintenance @ 3% of CC
Fixed Charges @ 15% of TCC
Chemicals and Power
Labor
. .
Total Annual Cost
Unit Cost, mills/kwh
Base-load (0.77 capacity factor) #
Cyclic (0.44 capacity factor) #
Peaking (0.09 capacity factor) #
100 rte
Retrofit
$ (1000)
76.6
107.2
2.3
16.1
3.0
90.9
111.4
0.165
0.289
1.41
New Sources
$ (1000)
59.2
77.0
1.8
11.5
3.0
90.0
106.3
0.159
0.277
1.36
1000 IV
Retrofit
$ (1000)
340.3
442.5
10.2
66.4
28.0
175.0
279.6
0.042
0.073
0.356
New Sources
$ (1000)
263.0
342.0
7.9
51.3
28.0
175.0
262.2
0.039
0.068
0.335
 * Note: Flow basis  is 155 GPD/Mw.
# Note: Assumes full annual costs of maintenance, chemicals, power, and labor.
        These costs would actually be less than shown and would reflect the
        extent of utilization of the plant.

-------
CO
^J
ro
                                 Table A-VIII-12
                               Estimated Annual  Costs
                  Central  Treatment  Plant  for Nuclear Powerplants*

Item
Construction Cost (CC)
Total Capital Cost (TCC)
Maintenance @ 3% of CC
Fixed Charges @ 15% of TCC
Chemicals and Power
Labor
Total Annual Cost
Unit Cost, mills/kwh
Base-load (0.77 capacity factor )H=
Cyclic (0.44 capacity factor) #
Peaking (0.09 capacity factor) #
100 I
Retrofit
$ (1000)
70.4
91.6
2.1
13.8
3.0
90.0
108.9
0.162
0.284
1.39
8-.'
New Sources
$ (1000)
54.4
70.6
1.6
10.6
3.0
90.0
105.2
0.156
0.273
1.33
100C f.
Retrofit
$ (1000)
309.5
402.5
9.3
60.4
28.0
175.0
272.7
0.040
0.070
0.345
IW
New Sources
$ (1000)
239.2
310.8
7.2
46.7
28.0
175.0
256.9
0.038
0.066
0.322
    * Note: Flow basis  is  155 GPD/Mw
    # Note: Assumes full annual costs of maintenance/ chemicals, power, and labor.
            These costs would actually be less than shown and would reflect the
            extent of utilization of the plant.

-------
capacity  functions  shown in Figure A-VIII-5, which in turn
are based on the following units cost:

    Operations Labor    $20,000/man-year
    Lime                $27/ton
    Flocculant          $0.05/lb
    Electricity          12 mills/kwh
Costs for Wastes Not Treated at Central Treatment Plant

The following wastes are not considered suitable for  treat-
ment at a central treatment plant for chemical wastes:

Cooling  water  (once-through system), cooling water blowdown
(closed system), sanitary wastes, roof and yard drains, coal
pile   runoff,   intake    screen    backwash,    radwastes,
nonrecirculating  ash  sluice  water,  nonrecirculating wet-
scrubbing air pollution control waste  water,   once-through
(nonrecirculating)    house   service  water.   Recirculating
bottom ash sluicing water blowdown is considered  separately
although incorporation in the central treatment plant may be
feasible in some instances.
Cooling Water-Once Through Systems

The  treatment technology for once-through condenser cooling
water systems consists of maintaining the residual  chlorine
in  the  effluent  below an established limit by controlling
the  chlorine  added  to  the  system.   The  capital  costs
involved consist of the cost of a residual chlorine analyzer
and   feedback  controls  to  adjust  the  feed  rate.   The
installed cost of a residual chlorine analyzer  and  control
equipment is estimated to be about $5,000 regardless of size
of  unit.   This  cost  is  easily amortized through savings
realized by reduced consumption of chlorine.

Costs of on-line mechanical cleaning of condenser tubes  are
given in Tables A-VIII-13 and A-VTII-14.

There  are several alternative materials available which can
replace copper based alloys  as  condenser  tube  materials.
The  most  widely  used  copper alloys are admiralty, with a
copper content of 70% and Cupro-nickel alloys with a  copper
content  of  from  70  to 90 percent.  Replacement materials
consist of stainless steel which provides a good  option  in
inland  fresh  water  locations  and  titanium  which  finds
                             373

-------
                             1,000
CO




CO

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                         o
                         T3
                         o

                         CO

                         3
                         rd
                         CO
                         3
                         O
                         £
                         -P
                         -P
                         CO
                         O
                         O
                         m

                         §
                         c
                               100
       10
                                   1              10               100            1/000

                                         Capacity/  thousands of gallons  per day
                 FIGURE A-VIII-5
         Annual Costs of Labor/ Chemicals and Power

         for  Chemical Treatment

-------
                                                  Table A-VIII-13
                                   Capital and  Operating Costs for On-Line Tube Cleaning  Equipment
                                                                                                 389
System
Recirculating
Sponge Balls
Plastic Brushes
Caoital Costs
S/106 Btu/hr $/kw
Rejected
120-290
38-125
0.48-1.16
0.15-.50
Annualized Capital
Mills/kwh(")
.008-. 020
.003-. 009
_____ Operati ng i
$10° Btu/hr1
Rejecte.d
2.85-5.15
3.07-6.12
ind Maintenance
Costs
Mills/kwh
(a 1
0013-.00241 '
fc)
,0014-.0028V
Total Ar.r.ual
Costs
Mills/kwh
.009-. 022
.004-. 01 2
CO
^J
01
      a.  Power costs estimated at 4 mills/kwh.  Maintenance labor estimated at $7.00/hr
      b.  Based on 15% per year
      c.  Includes allowance for replacing  brushes every five years.

-------
                                                           Table A-VIII-14
                                             Typical  Sponge Rubber Ball Tube Cleaning  System Costs ^a^  389
Unit Capacity
Mw
900
1,190
680
950
Cooline Water
Kecirculation Rate
gpm
405 . 000
440,000
220 OOO
882 , 000
Equipment Cost * '
S
$229,000
312,000
165,000
556,000
$/Mw
$254
284
243
585
Additional Power
Required to Operate
System, kw
70
76
46
166
Replacement Ball
Costs ,$/yr
$6 , 400
15,000
6,000
11,000
Maintenance
Labor Rqd ,
hrs/wk
1
1
1
2
CO
-J
         (a)  Data provided by Mr. W. I. Kern,  Amertap  Corporation
         (b)  Estimated total installed cost of system,  including capital equipment  for new installation
             2 x equipment cost.

-------
greater applicability in coastal  plants  operating  on  sea
water.   Both stainless and titanium are highly resistant to
corrosion which allows the use of thinner  tube  thicknesses
in most applications.  The overall heat transfer coefficient
for  both  of  these  materials  is somewhat less, at normal
operating conditions, than the  copper  based  alloys,  thus
requiring  a  greater tube length.  In addition, the cost of
titanium is considerably more  than  copper  and  these  two
factors  have  combined  to  limit  the use of titanium to a
relatively  few  coastal  applications.   However,   several
plants  have  retubed with this material based on economical
analysis which showed that  reduced  tube  failures  lowered
overall  maintenance  costs.   Stainless steel, on the other
hand is competitive with the copper based alloys in terms of
price  and  its  greater  tolerance  to  both  erosion   and
corrosion  has  led to a dramatic growth in its use over the
last 10 years.

Table A-VIII-15, shows a cost comparison of the use of these
alternatives tube materials for typical condenser conditions
(7.5 ft/sec and  1.0"  diameter  tubes)  and  recent  (197U)
materials  prices.  The table shows that the use of titanium
to retube an existing condenser might add as much as 90%  to
the retubing cost.  The use of stainless steel is competitve
with the cost of both admiralty and copper-nickel tubing.

Installation  of  alternate tube material at existing plants
can be done at the time of normal condenser retubing.  Major
condensers can be completely retubed  in  approximately  one
month.

Cooling Water Blowdown - Closed Systems

The  treatment  technology  is essentially the same as for a
once-through system.  Residual chlorine is monitored in  the
effluent,  and  blowdown is permitted only when the residual
chlorine is below the established limit.  It is possible  to
schedule  blowdown  only  at  such  times  when the residual
chlorine level meets the  effluent  limitation.   Additional
costs  would  occur  in  cases  where sedimentation would be
provided for suspended solids removal,  and  where  chemical
treatment   would  be  required  for  removal  of  chromium,
phosphorus, or zinc.   Sedimentation  costs,  where  needed,
would  be  approximately  7  cents/1000  gallons treated and
chemical treatment  costs,  where  needed,  would  be  about
$1/1000 gallons.

Capital  investment  and  operating costs were estimated for
various  chrornate  reduction  systems,  based  on  the  flow
diagram   shown   on  Figure  A-VII-17  and  the  wastewater
                            377

-------
                                                     Table A-VIII-15
                                              COST COMPARISON OF ALTERNATIVE  TUBE MATERIAL

                                                        (1"0 tubes; velocity  7.5 ft/sec)
CO
-«J
00
Manorial
Admiralty
90/10 Cupro-Nickel
Titanium
Stainless Steel (316)
Copper
Content (%)
20
90
0
0
BWG
18
20
22
22
Overall
Heat Transfer
Coefficient
(Btu/hr/ftZ/F)
600
570
535
520
Heat
Transfer
Multiplier
1.00
1.05
1.12
1.15
Unit
Cost
$/ft
0.74
0.96
1.26
0.76
Cost
Multi-
plier
1.00
1.29
1.70
1.02
Total
Multi-
plier
1.00
1.36
1.90
1.17

-------
characteristics shown in  Table  A-VII-11.   Estimates  were
based  on  a  1,000 Mw fossil-fuel plant operating at a heat
rate of 10,UOO Btu/Kwh  (Efficiency  =  33X)   and  having  a
circulating  water flow rate of 600,000 gpm at a temperature
differential of 20°F.  For such  a  system,  the  amount  of
blowdown  required  depends  on  the  characteristics of the
makeup water supply, in particular, the number of cycles  of
concentration  possible  before scaling occurs.  The capital
cost of a chromate reduction system is in turn a function of
the  blowdown  rate.   Table  A-VIII-16  shows  the  capital
investment  costs for chromate reduction systems for various
blowdown rates and the corresponding  number  of  cycles  of
concentration.

The  maximum  number  of  cycles  of  concentration  can  be
increased ty pretreatment of the makeup supply to reduce the
specific  parameter  limiting  the  number  of   cycles   of
concentration.     Thus    there    are   obvious   tradeoff
possibilities between pretreatment of makeup water and post-
treatment of blowdcwn.

Operating costs of chromate  reduction  systems  consist  of
capital  charges,  maintenance,  labor,  and  materials  and
supplies.  The first three items are essentially fixed,  but
materials  and  supplies vary with the hours of operation of
the system and the level of chromate carried in the  system.
Table A-VIII-17 shows the various costs as a function of the
chromate concentration.

Unit  costs  for chromate reduction systems are developed in
Table A-VIII-18

Typical  automatic  blowdown  control  equipment  costs  are
estimated  to  be  $7,300  including  installation.389.  The
installation of conventional  pH  controlling  equipment  is
estimated to be about $3,000.3«»

Table  A-VIII-19  taken  from  Reference 389 gives costs for
sedimentation ponds, cooling towers  and  chemical  recovery
for blowdown treatment.

Sanitary Wastes

Sanitary   wastes  are  generally  discharged  to  municipal
sewerage systems, or if municipal sewers are not  available,
treated  in biological process treatment plants.  The volume
of sanitary wastes is primarily a function of  the  size  of
the   labor   force.    For  most  powerplants  in  isolated
locations, a minimum  size  factory  preassembled  activated
sludge type treatment plant will provide adequate treatment.
                             379

-------
                     Table A-VIII-16

              CAPITAL INVESTMENT COSTS FOR
               CKROMATE REDUCTION SYSTEMS
Slowdown Rare
rl /s     gpm

         5,400
         2,400
           720
Assumptions :
          Cycles of
       Concentration

             3
             5
            10

1,000 Mw fossil-fuel
Heat rate 10,400 Btu/kwh
600,000 gpm at 20°F  AT
Evap. - 2%
                Capital Cost
                $780,000
                 537,000
                 364,000
                                          (Efficiency = 33%)
                     Table A-VIII-17

  VARIABLE OPERATING COSTS FOR MATERIALS AND SUPPLIES
            CKROMATE REDUCTION SYSTEMS
Item
S02
H2S04
NaOH
Polymer
Power
Unit Cost
$0.17/lb.
$0.02/lb.
$0.04Vlb.
$2.00/lb.
$0.03/kwh
Cost per 1000 gal, processed

Chromate Concentration, mg/1
  10     50     100     200
$.05
.08
.145
.02
.0075
$.11
.12
.20
.02
.0075
.4575
$.175
.16
.29
.02
.0075
.6525
$.317
.20
.40
.02
.0075
.9345
                             380

-------
                        Table A-V1II-1B
                      UNIT COSTS OF
               CHROMATE REDUCTION SYSTEMS

Capital Investment Costs

    Construction Cost                    $413 000
    Engineering                            62^000
    Contingencies                          62,000
      Total                              $537,000

Annual Costs

    Capital Cnarges @15% x Total         $ 80,500
    Maintenance @3% x Constr. Cost         12,400
    Labor                                  23,700
      Fixed                              $116,600
    Materials and Supplies                394,400
                                         $511,000

Unit Costs, mills/kwh

    Capacity Factor         1.00    0.67    0.35
    Fixed Costs             0.013   0.020   0.038
    Materials and Supplies  0.045   0.045   0.045
      Total                 0.058   0.065   0.083

Note;  1000 Mw fossil-fuel plant, 5 cycles, 10 mg/1 Chromate
                  381

-------
                             Table A-VIII-19    slowdown Treatment System Costs  389
System

sediment 'it i (.••••. Pond




Mechanical Draft
Evaporative
Cooling Tower
Chr ornate Recovery
Installation
Costs
S/m3/hr fed
3-6




20-30


8400
Annualized , ,
Capital Costs
$/l,000 m3 fed
0.05-0.10




0.34-0.51


144
Operating and .
Maintenance Costs3'
5/1,000 m3 fed
0.01-0.02(c)




2.20-2.75


37
Total Costs
S/1,000 m3 fed
0.06-0.12




2.54-3.26


181
Principal System
Characteristics

1. Provides solids settling
chlorine dissipation, and
usually some cooling
2. Costs dependent on land
values and climate.
1. Allows positive control of
blowdown temperature.
2. May require biocide treatment.

CJ
00
NJ
              (a)  Based on 15  percent per year
              (c)  Maintenance  estimated at 3 percent per year of capital investment

-------
The  installed  cost  of  these  plants  is  estimated to be
$25,000 - $35,000 depending on geographic location.

Materials Storage and Construction Runoff

The cost  of  materials  storage  and  construction   runoff
treatment  is a function of the meteorological conditions at
each particular site.   Capital  costs  of  lined  retention
ponds capable of holding various volumes of runoff are shown
in  Figure  A-VIII-6.  Costs for neutralizing chemicals will
vary with pH and frequency of treatment.

Systems to collect coal pile  run-off  installed  in  recent
years vary considerably, in complexity and costs.  Elaborate
collection  systems  would  be required at some plants where
unusual terrain conditions and space limitations exist.   At
one  midwestern  plant  of  about  1,000 Mw capability a new
system collects run-off by gravity in a concrete basin  from
which  it  is pumped to an adjacent ash settling basin.  The
collection and treatment  systems  cost  about  $500,000  to
install.   On  the  other  hand,  at  one eastern plant such
collection can be accomplished merely by grading of adjacent
areas to route run-off by gravity to an existing  ash  pond.
This particular system cost about $20,000 to install.444

The assumptions made for estimating the cost of constructing
facilities  for  containment  of  the runoff from a one acre
area for the storage of coal and other materials  are  given
below:458

    1.   The estimates of cost are based on  a  10-year,  2U
         hour event in which 0.114 m  (4.5 in) of rain falls.

    2.   The surface of the land to be  used  as  a  storage
         area has a 3 degree grade.

    3.   The  soil  is  permeable  so  that  an  impermeable
         subbase  must be prepared.  The impermeable base is
         prepared by grading 0.6 m (2 ft) from the  edge  of
         the  square  storage  area.  This graded surface is
         backfilled, graded level, and compacted to a  depth
         of  0.15 m  (5 in).  Polyethylene sheeting is placed
         on the dikes described later.  Overlaps  of  0.3  m
         (12  in)  at the seams of the sheeting are used.  A
         0.45 m  (1.5 ft) layer of earth is than  graded  and
         compacted over the polyethylene, including the face
         of the dikes described later.

    4.   Dikes are constructed across the  downhill  end  of
         the  square  storage  area, and for about one-third
                           383

-------
  140
  120
'j'lOO
CO
o
Q

O
o
o
c
•H
O
U
80
   60
m
•U
•H
04

-------
         the distance up each side.   The dikes will be 2.5 m
         (8.2 ft)  high at the crest.   The crest will be  1.5
         m  (5  ft)  wide, and the total width of the base of
         the dikes,  which are trapezoidal in  cross-section,
         will be 12  m (40 ft).  The dike at the downhill end
         of  the  storage  area  is  provided with a concrete
         sluiceway so that water can overflow in  the  event
         of  a  catastrophic  rainfall.   The  crest  of the
         sluiceway is 1.5 m (5 ft)  above the grade level  of
         the  base  of  the dike.  The dikes are constructed
         prior to placement of the  polyethylene  sheets  so
         that the upstream faces of the dikes can be covered
         with polyethylene, and then earth, and compacted.

    5.    Trenches are dug  across  the  uphill  end  of  the
         storage  area  and along each side to divert runoff
         into the diked area.

    6.    Neutralization  facilities  are  used  to  maintain
         within  proper  limits  the pH of any overflow from
         the diked area at a rate of up to  4.5  acre-inches
         averaged  over  one day, as controlled by the weir.
         Any flow in excess of  this  level  is  allowed  to
         bypass  the  treatment  facility.  These facilities
         include a storage hopper and feeder for lime and  a
         pH  sensor  and  controller  along  with  necessary
         wiring.  Mixing of the lime with overflow from  the
         containment   pond,   when   overflow   occurs,  is
         accomplished  by  the  use  of  a  mixer   in   the
         downstream  trough  of  the  sluiceway.   The  lime
         feeder is controlled by a pH  controller  with  the
         sensor  downstream  from  the  sluiceway.   The  pH
         controller will activate the feeder  in  proportion
         to  the  amount the pH is lower than a pre-selected
         point.

    7.    A settling basin, created by  excavation  to  build
         the  dike,  is sized to provide a detention time of
         24 hours   (taking  into  account  the  build-up  of
         sediment  for  the  volume  of  the 10-year 24 hour
         event.  An  overflow  is  provided.   The  settling
         basin is not lined.  See Figure A-VTII-7 which is  a
         sketch of the runoff treatment system.

The  unit  costs  used  in  estimating  the  above  cost are
$1.18/cu  m   ($0.90/cu  yd)   for   grading,   filling   and
compacting;  $0.27/sq m  ($0.025/sq ft) for purchasing 10-mil
polyethylene film (quoted  price);  and  $1.65/lineal  meter
($0.50/lineal ft) for machine trenching.*sa
                            385

-------
        TRENCH
                           DIKE
CO
CD
                      MATERIALS
                       STORAGE
                         AREA    SLUICEWAY •'
WEIR
                                                                     LIME STORAGE
                                                                     LIME FEEDER
                                                                        pH SENSOR/CONTROLLER
                                                                 MIXER
SETTLING
  BASIN
                                                                                     Overflow
                                                                                           River
                                                              Bypass
      Figure A-VIII-7      Materials  Storage Area Runoff Treatment

-------
The  total  cost  of  the  O.U04  hectare  (1 acre)  area for
storing coal and other materials is estimated to be $17,000,
including  the  cost  for  preparing  impermeable   sub-base
($3,300), trenches and dikes ($1,100), and the sluiceway and
neutralization     facilities     including     installation
($8,500) .*»«

For a larger facility, the cost of trenches  and  dikes  are
estimated  to be proportional to the square root of the size
of the storage area, since their length is  proportional  to
the  square  root  of  the  enclosed  area.  The cost of the
sluiceway and neutralization facilities are estimated to  be
proportional  to  the  0.6  power of the size of the storage
area, since the cost  versus  size  characteristics  of  the
components  involved  can  be  approximated using this scale
factor.*6*  Estimated cost  for  treatment  of  runoff  from
materials  storage  areas  and construction activities for a
100 Mw and a 1,000 Mw coal-fired plant is given in Table  A-
VIII-20.   Estimated  costs  for  plants  of other sizes are
shown in Figure A-VIII-10.  The controlled area  is  assumed
to  be 0.03 acresAMw in each case, which is comprised almost
entirely cf the area of the coal pile.  Costs for oil-fired,
gas-fired, and nuclear plants would therefore be  relatively
insignificant.

Intake Screen Backwash

The incremental cost of land disposal of debris removed from
intake screens would be  insignificant in most cases.

Floor and Yard Drains

The  installed  cost of two API-type oil-water separators at
plant no. 3702 (400 Mw) is $70,000, or  $0.18/kw,  to  treat
about  56  I/sec   (900  gpm) of a floor and yard drain waste
water stream.

Radwaste

No treatment is assumed due to possible hazardous effects of
concentrating radioactive wastes.

Ash Sluicing Systems

In cases where sedimentation would be required for suspended
solids removal from ash sluice water,  the  costs  would  be
about   7  cents/1000  gallons.   Having  achieved  adequate
suspended solids  removal,  the  effluent  is  suitable  for
recycle for ash sluicing, which would involve an incremental
cost  for  pumps, piping and blowdown controls.  Flow sheets
                            387

-------
                                     Table A-VIII-20
                                     Estimated Costs
                 Materials  Storage  and Construction Activities  Runoff  Treatment
                                    (Coal-Fired  Plant)
Item
Area Controlled @ 0.03 acre/Mw
Trenches, dikes, and settling basin
Sluiceway, diversion, and
neutralization facilities
Major Component Cost
Installation Cost*
Instrumentation Cost*
Construction Cost
Engineering @ 15%
Contingency @ 15%
Total Capital Cost
( $Aw )
Model
1 acre
$ 1,100
8,500 .
$ 9,600
0
0
$ 9,600
1,440
1,440
$12,480
100 Mw
3 acres
$ 1,910
16,430
$18,430
0
0
$18,340
2,750
2,750
$23,840
( 0.24 )
1000 Mw
30 acres
$ 6,030
65,400
$71,430
0
0
$71,430
10,700
10,700
$92,830
( 0.09 ) |
co
00
CO
       *Note  : Included in major  component  cost

-------
for  the  adaption  of  recirculating  bottom  ash  sluicing
systems where ash pond sedimentation is already employed are
given  in  Figures A-VIII-8, 9, one of which applies where a
combined ash pond is used for both fly ash  and  bottom  ash
and  the  other   applies  where  the  ash pond handles only
bottom ash.  Equipment costs are determined from  Figure  A-
VIII-2,  3.   It  is assumed, based on site plans of all TVA
coal-fired plants that 6,000 ft  of  return  pipe  would  be
needed  for a 1,000 Mw plant and further, that the length of
return pipe required for plants of other capacities would be
proportional  to  the  plant  capacity  to  the  0.6  power.
Equipment  costs  for  100 Mw and 1,000 Mw coal-fired plants
are  given  in  Tables  A-VIII-21,  22,  respectively,   for
adaptation  of  recirculating bottom ash systems for the two
types of ash pond usage.  Corresponding  capital  costs  are
given  in  Tables  A-VIII-23, 24.  The estimated relation of
capital costs to  plant  generating  capacity  is  given  in
Figure  A-VIII-10.   Estimated  annual  costs  are  shown in
Tables A-VIII-25, 26.

The backfitted configured recirculating ash sluicing  system
at   plant   No.  3630,  which  utilizes  no  ash  pond  for
sedimentation,  cost  approximately  3  million  dollars  to
handle  the  bottom  ash from coal turned at a rate of 3,000
tons/day.   However,  the  costs  for  this  system  include
modification  of floor and yard drainage, neutralization and
disposal of demineralizer and  boiler  cleaning  wastes  and
modification  of trash screens as well as the configured ash
water recycle system.  System components include a coal pile
trench,  collecting  basin,  filtering  pond,   neutralizing
tanks,   pumps,   piping,   hydrobins,   settling  tank  and
recirculating tank.  The system is designed  to  achieve  no
discharge  of  pollutants  except for those contained in the
moisture removed with the settled ash.  The plant uses once-
through cooling systems.

The capital cost of the configured recirculating bottom  ash
system  at  plant  No.  5305 was $2,100,000.  Dnit 1, with a
capacity of 700 Mw, was installed in late 1971 and  Unit  2,
with   the  same  capacity,  was  installed  in  late  1972.
Assuming the costs to be approximately  the  same  for  both
units  and  a  5  percent increase in costs between 1972 and
1973, the 1973 cost for a 700 Mw  recirculating  bottom  ash
system  would be about $1,100,000.  Using this as a base and
assuming a  0.6  scale  factor  on  costs  versus  size  (Mw
capacity)  the  capital  costs  for  a  100 Mw unit would be
approximately $420,000 or 4.20 $/kw, and $1,360,000 or  1.36
$/kw  for  a  1,000 Mw unit.  Costs would vary from case-to-
case.
                          389

-------
CO
10
O
                                  Figure A-VIII-8
                 FLOW  SHEET - RECIRCULATING  BOTTOM ASH
                                  SLUICING  SYSTEM  SLOWDOWN TREATMENT
                                                                                     WATER
                                                                                   (9 gpd/mw)
              RECIRCULATING BOTTOM ASH
              SLUICING WATER
              5000 gpd/mw
 BOTTOM ASH
    POND
                      pH 3
                      (ASSUME)
           RECYCLE FOR BOTTOM
           ASH SLUICING
           5000 gpd/mw)
400 gpd/mw MAKEUP
                  FLOCCULANTS
                  1 LB/1000GAL
                  (0.4 Ib/day/mw)
     DISCHARGE TO
     RECEIVING
     WATER
                                                              ^  PH 7.
                                r
                                                                                   5000 gpd/mw)
                        TSS 1000 mg/J? (ASSUME)
                                      SLOWDOWN
                                      400 gpd/mw
                                      TSS 1000PPM
                                         CLARIFIER
                                              -0
                                             1% SLURRY
                                             45 gpd/mw
                                  DISCHARGE TO
                                  RECEIVING WATER
                                                                                  SLUDGE
                                                                    LIME
                                                                7.2 x 10"4 Ib/gal
                                                                (3.6 Ib/day/mw)
                                                                                                                         LIME
                                                                                                    5% LIME SLURRY

-------
                        Figure  A-VIII-9       TREATMENT OF COMBINED ASH OVERFLOW
                                                   RECYCLE FOR BOTTOM ASH SLUICING
                                                           5000 gpd/mw)
                    RECIRCULATING BOTTOM ASH
                   SLUICING WATER 5000 GPO/MW
                       FLY ASH SLUICING WATER
                                  6000 gpd/mw
Co
10
                                                        COMBINED
                                                        ASH POND
                                        FLOCCULANTS
                                        1 Ib/IOOOgal
                                        (5.5 Ib/day/mw)
          DISCHARGE TO

      RECEIVING WATERS
         —'5400 gpd/mw
                                   OVERFLOW
                                   10,000 gpd/mw
                                   TSS 60 mg/J
                                   SO4  510 malt
                                   HARDNESS 244 mg/7 AS CaCO3
                                                 LIME OR ACID
          SLUDGE
                                                                  -MAKEUP
                                                                    400 gpd/mw
                                                                                                              6000 gpd/mw)
                                                                                            REACTOR

                                                                                            (pH ADJUSTMENT)
                                                                                            208 gal/mw (1 HR. DETENTION)
                             FILTER
1% SLURRY'
8000 Ib/day/mw
 (1000 gpd/mw)
                                                          (•ASSUMES THAT THE WEIGHT OF PRECIPITATE IS TWICE THE WEIGHT OF POLLUTANTS)

-------
                                           Table A-VIII-21
                                      Estimated Equipment Costs
                                   Recirculating Bottom Ash System
                                and Treatment of Bottom Ash Slowdown
Component

Lime Mixing System (Ib/day)
Clarifier (gpd)
Filter (gpd)
Pumps and Piping
Major Equipment Cost
100 Mw
Size/Capacity
360
40,000
4,500


$
2,000
9,400
16,000
21,500
48,900
1000 Mw
Size/Capacity
3,600
400,000
45,000


$
3,500
30,000
34,000
87,000
154,500
CO
«-O
ro

-------
00
to
co
                                     Table A-VIII-22
                                Estimated Equipment Costs
                            Recirculating Bottom Ash System
                   and Treatment of Combined Ash Pond Overflow
Component

Reactor (gpd)
Clarifier (gpd)
Filter (gpd)
Pumps and Piping
Major Equipment Cost
100 Mw
Size/Capacity $
540,000
540,000
100,000


9,200
36,000
44,000
21,500
110,700
1000 Mw
Size/Capacity
5,400,000
5,400,000
1,000,000


$
16,000
210,000
94,000
87,000
407,000

-------
                                           Table A-VIII-23
                                       Estimated Capital  Costs
                                    Recirculating Bottom  Ash System
                                and Treatment  of Bottom Ash Slowdown
Item

Major Equipment Cost
Installation Cost
@50% for new sources
@100% for retrofit
Instrumentation
@20%
Construction Cost
Engineering
@15%
C ont i ng enc y
d>15%
Total Capital Cost
($Aw)
100 Mw
Retrofit
($1000)
48.9
48.9


9.8
107.6
16.1

16.1

139.8
(1.40)
New Sources
($1000)
48.9
24.5


9.8
83.2
12.5

12.5

108.2
(1.08)
1000 Mw
Retrofit
($1000)
154.5
154.5


30.9
339.9
50.9

50.9

441.7
(0.44)
New Sources
($1000)
154.5
77.3


30.9
262.7
39.4

39.4

341.5
(0.34)
co

-------
                                       Table A-VIII-24

                                   Estimated Capital  Costs

                                 Recirculating Bottom Ash System

                          and Treatment of Combined Ash Pond Overflow

Item
«
Major Equipment Cost
Installation Cost
d> 50% for new sources
@ 100% for retrofit
Instrumentation
@ 20%
Construction Cost
Engineering
® 15%
Contingency
@ 15%
Total Capital Cost
($Aw).
100 Mw
Retrofit
($1000)
110.7
110.7


22.1

243.5
36.5

36.5

316.5
(3.17)
New Sources
($1000)
110.7
55.4


22.1

188 o 2
28.2

28.2

244.6
(2.45)
1000 M"
Retrofit
($1000)
407.0
407.0


81.3

895.3
134.4

134.4

1,164.1
(1.16)
New Sources
($1000)
407.0
203.5


81.3

691.8
103.9

103.9

899.6
(0.90)
<*>
to
en

-------
n
r-
en
s-i
m
rH
H
O
o

CO
fl
en
3
O
-P
en
0
U
-P
•H
a
ro
O

rH
a
-P
o
13
. •...; . '• !.  .  ' • :...

                                 *:I '•  '• •• I  i Hi!'
~ Existing Plants

- -"New 'Plant's  	" ~"~

•-rrrBoth _Ebcis-ting	

	i_  .and.J3ew. .Plants.
       10              100           1,000

           Plant Generating Capacity, megawatts
                   10,000
                      Figure A-VIII-10


    Estimated Total.Capital Costs  for Materials  Storage and

    Construction Activities Rainfall Runoff Treatment,

    Recirculating Bottom Ash Systems with Slowdown Treatment,

    and Recirculating Bottom Ash Systems with Treatment of

    Combined Ash Pond Overflow,All for Coal-Fired Plants
                        396

-------
                                        Table A-VIII-25
                                      Estimated Annual Costs
                                   Recirculating  Bottom  Ash System
                                and Treatment of  Bottom  Ash Slowdown*

Item
Construction Cost (CC)
Total Capital Cost (TCC)
Maintenance @ 3% of CC
Fixed Charges @ 15% of TCC
Chemicals and Power
Labor
Total Annual Cost
Unit Cost, mills/kwh.
Base-load ( 0.77 capacity f actor )#
Cyclic ( 0.44 capacity f actor )#
Peaking ( 0.09 capacity f actor )#
;_ 100
Retrofit
($1000)
107.6
139.8
3.2
22.0
7.5
120.0
152.7
0.228
0.398
1.95
Mb.'
New Sources
($1000)
83.2
108.2
2.5
16.2
4.8
100.4
123.9
0.183
0.321
1.57
I
1000
Retrofit
($1000)
399.9
441.7
10.2
66.3
70.0
230.0
466.5
0.069
• 0.121
0.590
	
Mw
New Sources
($1000)
262.7
341.5
7.9
51.3
4.4
200.0
263.6
0.039
0.068
0.334
CO

-------
CO
«£>
00
                                Table A-VIII-26
                               Estimated Annual Costs
                             Recirculating Bottom Ash  System
                          and Treatment of Combined Ash  Pond Overflow*
                                 (  Retrofit  Only)

Item
Construction Cost (CC)
Total Capital Cost (TCC)
Maintenance @ 3% of CC
Fixed Charges @ 15% of TCC
Chemicals and Power
Labor
Total Annual Cost
Unit Cost
Base-load ( 0.77 capacity factor )#
Cyclic ( 0.44 capacity factor)#
Peaking ( 0.09 capacity f actor )#
100 Mw
($1000)
243.5
316.5
7.3
47.5
90.0
250.0
394.8

0.587
1.03
5.02
1000: Mw
($1000)
895.3
1,164.1
26.9
175.0
870.0
480.0
1,559.9

0.108
0.189
0.923
        * Note: Flow basis  is  5,400
        # Note: Assumes  full annual costs of maintenance,  chemicals, power, and  labor.
                These costs would actually be  less than  shown and would  reflect  the
                extent of utilization of the plant.

-------
Reference U60 estimates  the  costs  of  settling  ponds  at
$5,000/acre for 100 acre ponds and $l,000/acre for a pond of
2,400  acres.  Reference 370 estimates that 300-UOO acres of
ash ponds (fly ash and bottom ash) would be required  for  a
3,000  Mw  coal-fired  plant.  Assuming the above costs (0.5
scale factor on costs versus size) and a  pond  size  of  12
acres/100  Mw  and 120 acres/1000 Mw, the capital cost of an
ash pond (fly ash and bottom ash) for a  100  Mw  coal-fired
plant would be $180,000 or $1.80/kw and $550,000 or $0.55/kw
for a 1,000 Mw coal-fired plant.  Assuming acreage for ponds
handling  only bottom ash to be 25% of the above and for fly
ash 75% of the above, bottom ash ponds would cost $90,000 or
$0.90/kw for a 100 Mw plant and $280,000 or $0.28/kw  for  a
1,000  Mw  plant;  and  fly ash ponds would cost $150,000 or
$1.50/kw for a 100 Mw plant and $U80,000 or $O.U8/kw  for  a
1,000 Mw plant.

Dry  fly  ash  systems  costs  would  vary from case to case
depending on the quantities of  ash  transported  and  other
factors.   Cost have been reported of $150,000 for a 100-600
Mw plant handling 80 tons/hour and $500,000  for  a  700  Mw
plant  handling 150 tons/hour.**9  Both costs do not include
storage silos which may cost approximately as  much  as  the
other  parts  of the system.  Both costs are for retrofitted
systems and include equipment only.  For  the  700  Mw  case
above, the total capital costs is estimated to be $2,210,000
including   50*   installation;   20%  instrumentation,  15%
engineering, and 15 % contingency  costs.   Applying  a  0.6
scale  factor,  total  capital  costs  for a new 100 Mw unit
would be  about  $550,000  or  $5.50/kw  and  $2,600,000  or
$0.26/kw  for  a  new  1,000  Mw  unit.  Estimated costs for
retrofit  systems  would  be  more  if  a  100%  factor  for
installation costs were used.
The use of recalculation bottom ash systems for all sources,
dry   fly   ash   systems   for  new  sources,  and  primary
sedimentation of fly ash for existing sources  is  estimated
to  achieve  the  removal  cf  approximately  28,000,000,000
Ib/year, by 1990, of total suspended solids that would  have
otherwise been discharged  (over 99* removal) .  This estimate
is based on the following assumptions:

    33% of coal-fired generation would have used dry fly ash
    systems (base-line)

    72% of coal-fired generation would have used  ash  ponds
    (base-line)
                             399

-------
    26%  of  coal-fired  generation  would  have  discharged
    directly (base-line)

    2% of coal-fired generation  would  have  discharged  to
    sewers (base-line)

    1990 coal-fired generation is 330,000 Mw

    Capacity factor 1990 coal-fired generation is 0.6

    In 1990, 67% of coal-fired generation will use  dry  fly
    ash systems

    In 1990, 1% of coal-fired generation will  discharge  to
    sewers

    In 1990, 0%  of  coal-fired  generation  will  discharge
    directly

    Ash generated  by  a  1,000  Mw  coal-fired  plant  (0.6
    capacity  factor)  is 900,000 Ib/day fly ash and 300,000
    Ib/day bottom ash

    Overflow from primary sedimentation  of  fly  ash  at  a
    1,000 Mw coal-fired plant  (0.6 capacity factor)  contains
    700 Ib/day of solids

    Discharges of solids from a treated recirculating bottom
    ash system at a 1,000 Mw coal-fired plant (0.6  capacity
    factor) are about 60 Ib/day.


Costs for Complete Treatment of Chemical Wastes for Reuse

Because  of  the  wide range of opportunities and associated
incremental costs of achieving no  discharge  of  pollutants
from  waste  water  sources other than cooling water systems
and rainfall run-off  (based on  the  technology  of  maximum
recycle  with  evaporation  of  the  final effluent) a model
plant is employed as a  basis  for  considerations  of  this
higher level of technology.  The features of the model plant
are  selected  to  produce  conservatively  high incremental
costs of applying this technology, i.e. the determined costs
would be at a level higher than would be expected for almost
all other plants.  The model plant would have  such  adverse
characteristics  that recycle of all water (except that used
in ash sluicing systems or  in  wet-scrubber  air  pollution
control  systems)  would  not  be  practicable  except after
distillation.  Distillation is much  more  costly  than  the
chemical  addition  and sedimentation treatments which would
                           400

-------
 be  used  in most cases.  Ash sluicing water and  wet-scrubber
 water  would  be recycled  after sedimentation  (or filtration)
 for solids removal.  The  model plant would have  to  distill
 blowdown from  ash  sluicing  for  recycle to other processes,
 however,  the  quantities of water  distilled  would  be  less
 than the feed   intake   to   the  system of low quality waste
 waters from other sources  by  the  amount  of  evaporation
 during   sluicing   and  the amount cf moisture removed in the
 ash. Therefore,  the assumption of the presence of  wet  ash
 sluicing is consistent with the conservative approach of the
 cost    analysis.    Similar   considerations   pertain   to
 wet-scrubber  air pollution  control  systems.    Non-solar
 evaporation is further assumed.

 Conceptual  flow  diagrams have been developed for such plans
 for coal-fired   and oil-fired   powerplants.   These   flow
 diagrams are  shown in Figures A-VIII-11 and A-VIII-12.  Cost
 estimates were then  prepared  based on these flow diagrams.

.The three major process units required to provide a complete
 treatment of chemical wastes for reuse within a powerplant
 include  a softener and chemical feed system  to  reduce  the
 hardness of the cooling tower blowdown, a brine concentrator
 to   preconcentrate  the   blowdown brines resulting from the
 recirculating of  ash sluicing water, and an evaporator-dryer
 to  finally reduce the sludge  to a solid cake for disposal by
 landfill.

 The capital costs, operating  costs,  and  annual  and  unit
 costs  for  a complete treatment system for chemical wastes
 exclusive of  once-through cooling water and rainfall  runoff
 are estimated to  be  as follows:

     Capital cost,  3-6 $/kw

     Operating costs, 1 $/yr-kw

     Annual costs,  1-3 $/yr-kw

     Unit costs, 0.2-0.5 mill/kwh  (base-load)

 This system will  produce  no discharge  of  pollutants  while
 returning the  water  to the process for reuse.  The costs
 represent upper limits of cost.   At some plants it  may  not
 be   necessary to  concentrate  brine and evaporate to dryness.
 For example,  plants  in the southwestern United States  would
 probably  be  able to  utilize evaporation  ponds  at   a
 substantial   saving  in   cost.    Mine-mouth   plants   will
 frequently  have   requirements  for  large  volumes  of  low
 quality  water for coal processing with ultimate disposal  to
                           401

-------
  COOL-
  ING
  TOWER
  MAKE-UP
    890
  GPM
LIQUID
WASTES
FROM ION
EXCHANGE
& EVAP. ONLY
14,3000 GPD
Il6 GPM)
                                       COAL 80,800 LB/HR
AIR 788,000 LB/HR
                OUTPUT HEAT BALANCE:-
                POWER-3.42 X 108 BTU/HR
                FLUE GAS-1.58 X 108
                BTU/HRT. 7
                COOLING TOWER-
                                                                                                                                            ASSUMPTIONS

                                                                                                                                INPUT:-10.5 X 106 BTU PER MW
                                                                                                                                FOR COAL -13,000 BTU/LB.
                                                                                                                                AIR REO'D-7.5 LB/10.000 BTU
                                                                                                                                WATER PRODUCED IN FLUE GASES-0.4 LB/10,000 BTU
                                                                                                                                15% OF INPUT IS LOST TO FLUE GASES
                                                                   FLUE GASES
                                                                   184,000 SCFM (b.d.l®
                                                                   ~400°F & 105°F D. P.
                                                        INPUT:-      „
                                                        HEAT-10.5 X 108 BTU/HR
                                                                                            DRY FLY ASH
                                                                                            FOR DISPOSAL
                       | 254,000 SCFM |b.d.|@ 135°F (SAT.)	*	R_EHEAT (II
                                                                                                                                         SLUDGE FOR
                                                                                                                                         DISPOSAL (CaSO4)
                                                                                                                                        •^*^fc^fe*^M  -   T)
 FLUE GASES TO
 ATMOS. AFTER
 REHEAT (IF REQ'D.)
                                                                                                               COOLING TOWER

                                                                                                              EVAPORATE 1000 GPM
                                                                                                              (ASSUME NEGLIGIBLE
                                                                                                              DRIFT LOSS)
                                                                                                              MAKE-UP-1.1 X 1000 GPM
                                                                                                              -100 CONCENTRATION
                                                                                                                OPERATION
                                                                                                                CONTROLLED
                                                                                                                DOSAGE(S) OF
                                                                                                                CHLORINE
                                                                                                                                       BASIN CLEANING
                                                                                                                                      5300 GPY
                                                                                                                                    410,000 GPD.
                                                                                                                       ASH
                                                                                                                       SLUICING
                                                                                                                       SYSTEM


                                                                                                                       LOSS BY
                                                                                                                       EVAPOR-
                                                                                                                       ATION
                                                                                                                                                              ASH SLUICING
                                                                                                                                                              SYSTEM
NEUTRALIZATION  pH ADJUSTMENT
& SEDIMENTATION  (IF REO'D) OIL
                 SEPARATION &
                 TSS REMOVAL
                                    SLUDGE
                          TO CITY
                          SEWERS (IF
                          ALLOWED)
                                                              NET SLOWDOWN @10%,
                                                              OF CENTRAL TREAT
                                                              MENT PLANT FLOW
                                                                                                                                         LEGEND
                                                                                                                                                                 - WATER
                                   NET BLOW-    I-
                                   IDOWN 11.6 GPMl
                                                                          JBRINE
                                                                          ICONCENTRATORl"
                                                                CONCENTRATED .
                                                                SLUDGE
SLUDGE TO
ASH POND
                                                                                            CITY SEWERS
                                                                                            (I FALLOWED)
                                                                                              MOIST SOLIDS
                                                                                              FOR DISPOSAL
	FLUE GASES
    -OIL
    >• SLUDGE
    -OPTIONAL ARR'GT.
                                       FIGURE A-VIII-11100 MW COAL-FIRED STEAM ELECTRIC POWERPLANT RECYCLE AND REUSE OF CHEMICAL WASTES 1

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                                                                                                                                          ASSUMPTIONS


                                                                                                                                  INPUT; - 10.5 « 106 BTU PER MW FOR
                                                                                                                                  NO.6 6lL: • 18.000 BTU/LB., 8 LB/GAL
                                                                                                                                  AIR REQ'D. • 13.5 LB/LB of OIL
                                                                                                                                  WATER PRODUCED IN FLUE GASES - 0.849 LB/LB
                                                                                                                                  15% OF INPUT OF OIL IS LOST TO FLUE GASES
                                                                                                                                                            FLUE GASES TO
                                                                                                                                                            ATMOSPHERE AFTER
                                                                                                                                                            REHEAT (IF REO-D)
                                     CLOSED WATER
                                     COOLING SYSTEMS
                                                                    CONDENSATE
                                                                    AS MAKE-UP
                                                                                                              MAKE-UP WATER -138 GPM
                                                                    FLUE GASES
                                                                    170,000 SCFMIb.d.)
                                                                    e 490°F &
                                                                    113°F D. P.
                                 BOILER
                                 MAKE-UP
                                 108,000 GPD
                                 (~74 GPM)
                                                      INPUT: 10.5 X 108 BTU/HR.
                                                                                                                           MOIST SOLIDS
                                                                                                                           FOR DISPOSAL
                                                      OUTPUT:      .  .
                                                      POWER-3.42 X 108 BTU/HR
                                         NO. SOIL
                                         58.300 LB/HR.
                                         (7ioOGPH)
                       FLUE GASES-
                        1.58 X~108 BTU/HR.
                       COOLING'TOWER:
                        5.5 X 108 BTU/HR.
                        (BY DIFFERENCE)
                                                                                                                       AJ240.000 ACFM€»140°F (SAT'D)..
COMBUSTION AIR
758.000 LB/HR
                                                                                           DRY FLY ASH
                                                                                         ,  FOR REBURN
                                                                                           AND/OR DISPOSAL
                                                                    BOILER
                                                                    SLOWDOWN
                                                                    5200 GPD
                                                                    l~3.7 GPMI
                                                                                    20°FATRISE
                                                                                    (ASSUME)
                                                                                                                COOLING TOWER

                                                                                                             EVAPORATE -1000 GPM
                                                                                                            ; (ASSUME NEGLIBLE DRIFT
                                                                                                            ' LOSS)
                                                                                                            JMAKE UP:~1.1 X 1000GPM
                                                                                                             -100 CONCENTRATION
                                                                                                             OPERATION
                                                                                                     CONTROLLED
                                                                                                     DOSAGE IS) OF CHLORINE
                 MOIST SOLIDS
                 FOR DISPOSAL
                                                                SLOWDOWN
                                                                @10%*1.6GPM
                                                                              SLOWDOWN 0 10%=10 GPM
FLOOR AND
YARD
DRAINAGE
                                                                                                          BASIN CLEANING ~ 5300 GPY .
                                                                        NET BLOW DOWN |
                                                                        11.6G
                                                                                       CITY SEWERS
                                                                                       (IF ALLOWED)
                                                                       BRINE
                                                                       CONCENTRATOR
SLUDGE FOR
DISPOSAL
        TO
        CITY SEWERS
        (IF ALLOWED)
SLUDGE FOR
DEWATERING
 pH ADJUSTMENT
JlFREO'DIOIL
 SEPARATION &
 TSS REMOVAL
                                                                                                                              WATER
                                                                                                                              FLUE GASES
                                                                                                                              OIL
                                                                                                                              SLUDGE
                                                                                                                              OPTIONAL ARRGT
                                                         CONCENTRATED
                                                         SLUDGE
                                                          •"  MOIST SOLIDS
                                                              FOR DISPOSAL
                                FIGURE A-VIII- 12100 MW OIL-FIRED STEAM ELECTRIC POWERPLANT RECYCLE AND REUSE OF CHEMICAL WASTES

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the  mine.   The estimates assume that no alternate ultimate
disposal methods for  the  brines  are  available  and  that
evaporation  to  dryness  is  the  only  feasible  method of
ultimate disposal.  Under these  assumptions,  the  cost  of
complete treatment is estimated to be 0.30 mills per kwh for
a  100  Mw plant and 0.11 mills per kwh for a 1,000 Mw plant
assuming a unity capacity factor.  For a typical  base  load
plant  operating  at  a capacity factor of 0.67, these costs
increase to 0.45 mills per kwh for a 100 Mw plant  and  0.17
mills  per  kwh  for  a  1,000  Mw  plant.  Costs for plants
operated in the cycling mode at a capacity  factor  of  0.35
are  about  0.86  mills per kwh for a 1000 Mw plant and 0.32
mills per kwh for a 100  Mw  plant.   Costs  for  a  100  Mw
peaking  plant  are about 1.5 mills per kilwatt hour.  These
costs are about 5, 6, and 12 percent  of  production  costs,
respectively.   The  above  costs  assume  the full capacity
costs of maintenance,  labor,  chemicals,  and  power.   The
actual  costs  for these items would be lower than shown and
would reflect the degree of utilization of the plant.  Costs
for smaller plants would be generally higher and  costs  for
larger plants would be generally lower.  Costs would be less
for plants in climates suitable for solar evaporation.  Cost
would be generally less for nuclear plants and for gas-fired
plants  because there is no requirement for water related to
ash handling.  From an overall standpoint,  costs  would  be
generally  lower  than  the costs for the model plant due to
the conservative assumptions employed in  the  model.   Full
recycle  of  blowdown from evaporative recirculating cooling
water systems would be significantly more costly.  The costs
of achieving no discharge of pollutants other than  heat  by
complete   chemical   treatment   and   recycle   provide  a
conservatively high estimate of achieving  no  discharge  of
pollutants from low-volume waste sources only.

Energy

Energy requirements for the treatment of chemical wastes are
not  a  significant  consideration.   Most  of the processes
utilized for the treatment of  chemical  wastes  require  no
input  of  energy other than that required for conveying the
liquid.  Some of the processes involved  in  the  technology
for achieving no discharge of pollutants involve a change of
state  from  the liquid phase to the vapor phase, and others
such  as  vacuum  filters  and   reverse   osmosis   require
substantial mechanical energy.  However, these processes are
generally  applied  to  only  a  small  portion of the total
wastes, so that again  the  overall  effect  is  negligible.
Based  on  the  flow  diagrams for a central chemical wastes
treatment  plant  and  for  complete  treatment   facilities
designed   to   achieve  no  discharge  of  pollutants,  the
                            404

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estimated energy requirements for  central  waste  treatment
are  less  than  10  kw per 100,000 kw of plant capacity, or
less than 0.01% of the plant output.  For complete treatment
and reuse, including steam evaporation to dry  material  for
ultimate  disposal,  the  energy  requirements are less than
0.2% of the plant output.  For plants capable  of  achieving
no   discharge   by   utilizing  evaporation  ponds,   energy
requirements are about 0.04X of the plant output.

Non-Water Quality Environmental Impacts

The  waste  treatment  processes  previously  discussed  are
essentially  separation  techniques  which  produce a liquid
fraction suitable for discharge or reuse and a  liquid-solid
residue which requires ultimate disposal.  The residues from
ion exchange, evaporation, and reverse osmosis processes are
concentrated  brines,  which  carry  the  solids in solution
form.  The residues from other waste treatment processes are
sludges  of  various  types  and  concentration,  which  may
contain from 0.5 to 5.0 % solids in the suspended form.  The
ease  with  which  these  sludges  can  be further dewatered
depends on the type of sludge.  At one end of the scale  are
sludges  which  contain a high propcrtion of mineral solids,
and which dewater readily to about 20% solids.  At the other
end of the  scale  are  gelatinous  sludges  such  as  those
resulting  from alum coagulation which are very difficult to
dewater.  The following  paragraphs  describe  some  of  the
dewatering  and  ultimate  disposal techniques applicable to
steam electric powerplants.

Intermediate Dewatering Devices

A number of devices are available for the  intermediate  de-
watering  of sludges from their original concentration of 1-
5% solids to about 15-30%  solids.   These  devices  include
vacuum filters, pressure filters and centrifuges.

Vacuum filters are devices consisting of a drum covered by a
filter  media  and rotating slowly while partially submerged
in a reservoir containing the sludge  to  be  dewatered.   A
vacuum  of  40 to 80 kN/sq m  (12 to 25 in. of Hg) is applied
to the inside of the drum, causing  a  layer  of  sludge  to
adhere  to  the  surface of the media.  As the layer emerges
from the reservoir, it is further dried by air  being  drawn
through  the  layer and into the interior of the drum.  Just
prior to resubmerging  into  the  reservoir,  the  dewatered
sludge is removed from the drum by a scraper and conveyed to
disposal.
                          405

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Some  sludges  contain  very fine or filamentous solids that
clog the filter media and prevent the flow of liquid and air
through the media.  Such sludges must be treated to increase
the porosity  of  the  filter  cake.   Treatments  prior  to
filtration may consist of the addition of ferric chloride to
colloidal   sludges   or   diatomaceous   earth  to  sludges
containing a high proportion of silty material. 18Z

Pressure filters are similar to vacuum filters  except  that
the  sludge or suspension is forced through the filter media
by pressure rather than by vacuum.  The most  common  filter
media  arrangement  consists  of a series of vertical frames
covered by a cloth media.  The sludge is applied  through  a
header  to  the  outside  of  the  filter  media,  while the
filtrate is collected from the  inside.   A  filter  aid  is
commonly used to increase the filterability of the sludges.

Neither  vacuum  filters nor pressure filters have been used
for pollution control in steam electric powerplants  to  any
significant  extent,  although  certain  types  of  pressure
filters are used in some forms of condensate polishing.

Centrifuges are intermediate dewatering devices  which  make
use  of the gravitational forces in liquids rotating at high
speeds to  separate  particulate  matter  from  suspensions.
There  are  no  known instances of centrifuges being used by
steam electric powerplants for pollution  control,  but  the
technology  is available and should be considered as a means
of concentrating and dewatering sludges.

Evaporation Ponds (Lagoons)

Evaporation ponds are a feasible method of ultimate disposal
for plants having the  necessary  land  area  available  and
having  climatic  conditions  favorable  to this method.  In
general, annual evaporation should exceed annual rainfall by
over  50  cm  (20  in).   This  would   restrict   uncovered
evaporation  ponds to the southwestern portion of the United
States.

Ponds are  generally  lined  to  prevent  seepage  into  the
ground.   Multiple  ponds  are  usually  provided  to  allow
evaporation from one pond while ether  ponds  are  receiving
wastes.   Facilities  must also be provided to remove solids
accumulated in the pond.

Landfill

Landfills are the most common method of  disposal  of  solid
residues.   However, leachate from chemical wastes deposited
                             406

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in landfills may cause groundwater problems.  If the  wastes
contain  soluble  components,  fill  areas must be lined and
leachate and runoff collected and treated as for  coal  pile
runoff.

Conveyance to Off-Site Disposal

Conveying brines and sludges to off-site disposal facilities
is  a  method  of ultimate disposal provided that the washes
have  been  concentrated  to  make  conveying   economically
attractive  and  provided  there  is a facility to which the
wastes can be delivered.  Alternate  methods  of  conveyance
are   by   trucks,  railroad  cars  or  pipeline.   Pipeline
conveyance is the most economical means  for  quantities  in
excess  of  100  cu  m  (26,000  gal)   per day.  For smaller
quantities, truck or rail hauling is more  economical,  with
distance  the  deciding factor.  Trucking is more economical
for distances below 50 km (35 miles)  with  rail  haul  more
economical  for longer distances.  In any case, costs are of
the order of $0.01 - 0.10 per cu m-km  ($0.05  -  $0.50  per
1000  gal  -  mile)  exclusive  of  disposal  charges by the
receiving agency. 369  These costs are sufficiently high  to
make  conveyance  economically  unattractive except at sites
having no alternate means of disposal.
                             407

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                           PART A

                      CHEMICAL WASTES

                     SECTIONS IX, X, XI

  BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY AVAILABLE,
                 GUIDELINES AND LIMITATIONS
           BEST AVAILABLE TECHNOLOGY ECONOMICALLY
           ACHIEVABLE, GUIDELINES AND LIMITATIONS
            NEW SOURCE PERFORMANCE STANDARDS AND
                   PRETREATMENT STANDARDS

Best Practicable Control Technology Currently Available

Cooling Systems

Free available chlorine discharges in both recirculating and
nonrecirculating cooling water systems are to be limited  to
average  quantities  reflecting  concentrations  of 0.2 mg/1
during a maximum of 2-hours a day   (aggregate)   and  maximum
quantities,  during these periods, reflecting concentrations
of 0.5 mg/1.  These  limitations can be achieved by means of
available feedback control systems presently in wide use  in
other applications.  Chlorination for biological control can
be  applied intermittently and thus should not be applied on
two or more units at the same plant simultaneously in  order
to  minimize  the  maximum  concentration  of total residual
chlorine  at  any  time  in  the  combined   cooling   water
discharged  from  the  plant.  Generally Chlorination is not
required at higher chlorine levels  or  for  more  than  two
hours   each   day   for  each  unit.   However,  additional
Chlorination may be allowed in specific  cases  to  maintain
tube cleanliness.  Alternative methods of reducing the total
residual   chlorine  in   condenser  cooling  water  systems
include  chemical  treatment,  substitution  of  other  less
harmful  chemicals,  and use of mechanical means of cleaning
condenser tubes.  Mechanical cleaning is  employed  in  some
plants  but  its practicability depends on the configuration
of  the  process  piping  and  structures  involved  at  the
particular unit.  Moreover, chlorine may still be discharged
even with mechanical cleaning of condenser tubes, because of
its continued use in maintaining biological control in other
parts  of  the  cooling system.  Further removal of residual
chlorine in nonrecirculating condenser cooling water systems
by chemical treatment is  available  but  is  not  generally
practicable  because  of  the  additional  costs involved to
treat the large volumes of water involved.
                             409

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Chemical treatment of recirculating  cooling  water  systems
would be less costly and the pollution potential of residual
bisulfide  chemicals  added  would  be less significant than
with nonrecirculating  cooling  water  systems  due  to  the
smaller    wastes   water   volumes   requiring   treatment.
Experience in this  technology  is  highly  limited  in  the
powerplant  field;  however,  this  is  a  well  established
technology in the water supply industry.  Other technologies
potentially  available  for  recirculating   cooling   water
systems  are  split stream chlorination, blowdown retention,
and  intermittent  discharge  programmed  with  intermittent
chlorination.

The  use  of  chemicals  for  control  of biological growth,
scaling and  corrosion  in  evaporative  cooling  towers  is
commonplace.  The types and amounts of chemicals required is
highly  site-dependent.   Chromate addition is not generally
required for corrosion control.  Phosphates and  zinc  salts
are  employed  in  some  cases.  Insufficient data exists to
judge what alternative chemicals for control  of  corrosion,
etc.,  would  be  generally  practicable  from a cost versus
effluent reduction benefit, standpoint.  Minimum discharge of
added chemicals  can  be  achieved  by  employing  the  best
practicable   technology   for  water  treatment  and  water
chemistry  to  minimize  the  quantities  of  blowdown  flow
required.   In  cases  of  new sources, design for corrosion
protection can eliminate the need for chemical additives for
corrosion protection.  Treatment of cooling  tower  blowdown
by  chemical  addition  for  effluent  pH  control,  and  by
sedimentation for  reduction  of  effluent  total  suspended
solids   is   achievable,  however,  essentially  all  total
suspended solids that  would  be  removed  would  come  from
sources other than the process (intake water and air).

Low-Volume Waste Waters

Low-volume  waste water sources include boiler blowdown, ion
exchange  water  treatment,  water   treatment   evaporative
blowdown,  boiler  and  air heater cleaning, other equipment
cleaning, laboratory and sampling streams,  floor  drainage,
cooling  tower  basin  cleaning, blowdown from recirculating
ash   sluicing   systems,   blowdown   from    recirculating
wet-scrubber   air  pollution  control  systems,  and  other
relatively low volume streams.  These wastes, where  by  the
specific  waste water parameters of the untreated waste, can
be practicably  treated  collectively  by  segregation  from
higher volume wastes, equalization, oil separation, chemical
addition, solids separation, and pH adjustment.
                             410

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Oily  streams  such  as  waste  waters  from boiler fireside
cleaning, air preheater cleaning and miscellaneous equipment
and  stack  cleaning  would  be  practicably   treated   for
separation  of oil and grease, if needed, to a daily average
level of 15  mg/1.   Addition  of  sufficient  chemicals  to
attain  a  pH level in the range 9 to 10 and total suspended
solids of 30 mg/1 in the effluent of  this  treatment  stage
would  be generally practicable considering the pH levels of
the untreated waste streams and the waste water flow volumes
involved.  Generally, the higher the pH  level,  with  total
suspended  solids  of  30  mg/1,  the  greater  the effluent
reduction  benefits  attained  for  the  numerous  chemicals
removed  by treatment.  Examples of pollutants significantly
reduced by  this  treatment  are  the  following:   acidity,
aluminum, biochemical oxygen demand, copper, fluoride, iron,
zinc,  lead,  magnesium, manganese, mercury, oil and grease,
total chromates, total phosphorous, total suspended  solids,
and  turbidity.   Some  waste water characteristics, such as
alkalinity, total dissolved solids, and total  hardness  are
increased,  however.  Following the above treatment it would
be practicable, in a second stage, to adjust the effluent pH
to a level in the range 6.0 to 9.0 in compliance with stream
standards, with sedimentation to attain final daily  average
effluent total suspended solids levels of 30 mg/1.  Effluent
daily  average  concentrations  of  levels  of  1 mg/1 total
copper  and  1  mg/1  total  iron  are  achievable  by   the
application of this technology to segregated metal equipment
cleaning  waste  waters  and  to segregated boiler blowdown.
The effluent limitations in mass units,  in  any  particular
plant,  would  be the products of the collective flow of the
affected  low-volume  waste  sources  times  the  respective
concentration levels.

Segregation and treatment of boiler cleaning waste water and
ion  exchange  water treatment waste water is practiced in a
relatively few plants, but some  degree  of  segregation  is
potentially  practicable  for all plants.  Oily waste waters
are segregated from non-oily waste streams  at  some  plants
and  the  oil  and  grease removed by gravity separators and
flotation units.

Combined treatment of waste water streams  is  practiced  in
numerous   plants.  However,  in  most  cases  treatment  is
accomplished only to the  extent  that  self-neutralization,
coprecipitation  and  sedimentation  occur  because  of  the
joining and detention of the waste water streams.  Chemicals
are added during combined treatment at some  plants  for  pH
control.  Most of these plants employ lagoons, or ash ponds,
while a few plants employ configured settling tanks.
                             411

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Separate  regulations are now being formulated by EPA to set
forth effluent limitations for sanitary  waste  waters  from
privately-owned  treatment  works  such as would be the case
for sanitary waste treatment for steam electric powerplants.

Once-Through Ash and Air Pollution Control Systems

Daily average effluent total suspended solids levels  of  30
mg/1 are practicably attainable as are oil and grease levels
of 15 mg/ and pH values in the range 6.0 to 9.0.  Due to the
fact  that  intake  water  to ash sluicing and air pollution
control systems is often well in excess of  this  level,  an
effluent  limitation of 30 mg/1 total suspended solids times
the waste water flow would, in many of those cases,  require
the  removal of  quantities of suspended solids not added by
the plant.  In the light of  this,  in  cases  where  it  is
authorized  to take account of suspended solids not added by
the plant, it should be practicable for  an  effluent  total
suspended  solids level for these streams to be limited to a
greater number of pounds per day but not in  excess  of  the
total intake to the plant for these systems.

Dry  processes  are  used  by  most oil-fired plants for ash
handling, while only fly ash is handled dry  at  some  coal-
fired  plants.  Gas-fired plants have little or no ash.  The
extent of the practicability of employing dry processes  for
bottom ash'handling at coal-fired plants is not known.

Rainfall Runoff Waste Water Sources

Rainfall  run-off  waste  water  sources  include  materials
storage drainage and.run-off from  construction  activities.
Construction   activities   include   only   those   in  the
immediately vicinity of the generating unit (s) and  related
equipment.   Runoff  from other parts of the site  ( land for
future  generating  units,  construction  of  access  roads,
cooling  ponds  and  lakes,  visitor  centers,  etc.) is not
intended  to  be  covered  by  this  limitation.    Effluent
limitations of 50 mg/1 total suspended solids and a pH value
in  the  range  6.0 to 9.0 reflect the technology of diking,
neutralization, and solids separation.

Best Available Technology Economically Achievable

The  technology of re-use and recycle of all waste water  to
the   maximum   practicable  extent,  with  distillation  to
concentrate all lew-volume water wastes and to recycle water
to the process, and  with  evaporation  to  dryness  of  the
concentrated waste followed by suitable land disposal is not
                             41:

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judged to be generally warranted due to the finding that the
technology has not been fully demonstrated.

Re-use of waste water streams is practiced at relatively few
plants,  but  some  employ  recycle  of  ash  sluice  water.
Distillation concentration with recycle is currently planned
for at least three plants.  Some  stations  plan  to  employ
re-use   of  cooling  tower  blowdown  in  wet-scrubber  air
pollution control systems.  Since water quality requirements
for bottom ash sluicing operations and are  relatively  low,
some  degree  of re-use should be practicable for all plants
where  these  operations  are  employed.    Best   available
technology  economically achievable is reflected by retrofit
systems for the recycle of bottom ash transport water with a
resulting blowdown flow of 8 percent of the  volume  of  ash
transport   water   treated  by  sedimentation  to  a  total
suspended solids level of 30 mg/1, an oil and  grease  level
of  15  mg/1  and  a  pH  value  in  the  range  6.0 to 9.0.
Universal retrofitting of dry fly ash systems would  not  be
economically  achievable.   The  concept  of cascading water
use, i.e., recycle and re-use  of  water  from  applications
requiring  high  quality  water  to  applications  requiring
successively lower water quality, to reduce to the volume of
waste water, if any,  ultimately  requiring  evaporation  or
other  treatment,  while  practicable  in  all  cases, would
generally be subject to a case-by-case analysis to determine
the optimum among the various candidate systems.

Chemical treatment of blowdown  from  recirculating  cooling
water system for removal of total chromium, total phosphorus
(as  P)  and  zinc,  while  not  currently  demonstrated  in
powerplant applications, could be achieved by 1983,  in  the
relatively  small  number of cases where it would be needed.
Corresponding effluent limitations, based on the application
of this technology, are 0.2  mg/1  total  chromium,  5  mg/1
total  phosphorus   (as  P), and 1 mg/1 zinc-total, all times
the waste water flow.

Chlorination programs  to  achieve  no  discharge  of  total
residual  chlorine  from recirculating cooling water systems
have been  determined  to  be  not  fully  demonstrated  and
therefore cannot be generally applied by 1983.

Rainfall runoff limitations are the same as best practicable
control technology currently available.

New Source Performance Standards

In  view  of the current technical risks associated with the
application  of  distillation  technology  to  waste   water
                            413

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recycle and chlorinaticn programs to achieve no discharge of
total  residual  chlorine  from  recirculating cooling water
systems,  new  source  performance   standards   have   been
determined to be identical to the limitations prescribed for
best  available  control  technology economically acheivable
with the following  exceptions.   Recirculating  bottom  ash
transport  systems  designed  for new sources can reasonably
achieve effluent limitations based on a blowdown flow  of  5
percent  of  the ash transport flow volume.  No discharge is
allowed   of   corrosion   inhibitors   in   blowdown   from
recirculating evaporative cooling water system, based on the
availability  of design technology for corrosion prevention.
No  discharge  of  pollutants  from   nonrecirculating   ash
sluicing  system,  based on  the general availability of dry
fly ash systems and of recirculating wet bottom ash systems.

Rainfall runoff limitations are the same as best practicable
control technology currently available.

Application of Effluent Limitations Guidelines and Standards

The effluent limitations for  a  powerplant  are  determined
based   on  the  existing  or  planned  flow  rates  of  the
individual waste sources  at  the  plant  and  the  effluent
limitations  corresponding to each of the waste sources.  An
example is given in Figure A-X-1  and  Table  A-X-1  of  the
determination  of  the  effluent limitation for a simplified
hypothetical case.  The extent of  the  feasibility  of  the
flow  arrangement shown is not known and is presented solely
as an example of the application of the effluent limitations
guidelines  and  standards.   For  the  plant   shown,   the
determination  of  the  limitations, for the metal equipment
cleaning wastes is straight-forward since there is no  reuse
or  combination with other wastes prior to treatment, except
that the waste waters are combined with other wastes  waters
immediately  prior  to discharge.  Boiler blowdown, however,
is combined with other waste waters prior to  treatment,  as
is  ash  transport  water  and  seme of the waste water from
other low-volume wastes sources.  Some of the cooling  tower
blowdown  and some of the waste waters from other low-volume
waste sources are reused  directly  for  ash  transport.   A
portion of the overflow of the first stage (ash pond) of the
combined  treatment of ash transport water, boiler blowdown,
and wastes from other low-volume waste sources  is  recycled
for  use  in bottom ash transport.  The remainder of the ash
pond  overflow  receives  final  treatment  prior  to  being
combined  with treated metal equipment cleaning waste waters
and some of the cooling tower blowdown prior to discharge.
                             414

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                  Intake 62,890
(Jl
             70
             40
            660
            400
          5,000
   METAL
 EQUIPMENT
  CLEANING
                                                   CENTRAL TREATMENT
          Slowdown
         62,120
                          BOILER
                                          Slowdown 40
   OTHER
LOW-VOLUME
  SOURCES
   BOTTOM
    ASH
  TRANSPORT
    FLY
    ASH
  TRANSPORT
  COOLING
   TOWER
                                        4.600
5,000
                                        5,000
                                                   ASH POND
                                         Slowdown 7,000
                                            Drift 120

                                            Evaporation 50,000
                               OVERFLOW
                               TREATMENT
, f  Discharge
           ^.
   12,770
                  Figure A-X-T    Hypothetical  Powerplant Water Flows
                                  ( Flows  shown in units of 1000 liters/day)

-------
                              Table A-X-1

                 Effluent Limitations for Hypothetical Powerplant
Source
Metal Equipment
Cleaning
Boiler Slowdown
Other Low-Volume
Sources
Bottom Ash
Transport
Fly Ash Transport
Cooling Tower
Blowdown
Flow,
1000 I/day
70
40
660
5,000
5,000
12,000
Total
Effluent Limitations, kg/day
TSS
2.1
(30)*
1.2
(30)
19.8
(30)
12.0
(30/12.5]
150.0
(30)
K
185.1+
Fe
0.07
(1)
0.04
(1)
N
N
N
N
0.11+
Cu
0.07
(1>
0.04
(1)
N
N
N
N
0.11+
Zn
N
N
N
N
N
12.0
(1)
12.0+
Cr
N
N
N
N
N
2.4
(0.2)
2.4+
P
N
N
N
N
N
60.0
(5)
60.0+
O&G
1.05
(15)
0.60
(15)
9.9
(15)
6.0
(15)
75.0
(15)
N
92.55+
* Note: Concentration bases, mg/1, shown in parentheses
+ Note: Plus effluent from sources with no limitation

-------
In each case, the  effluent  limitations  for  a  particular
waste   water  source  are  based  on  the  wastewater  flow
emanating from that source,  regardless  of  the  subsequent
reuse,  recycling,  or  combination  of  the wastewater with
other streams, and regardless of the  source  of  the  water
used  by  that source.  A discharger may find that the reuse
of certain waste streams results in a less costly  pollutant
removal  scheme  than  one  employing  no  reuse  due to the
reduction in the  final  flow  volume  requiring  treatment.
Water  reuse  may  also  be employed to reduce the volume of
water required by  the  plant  or  to  reduce  the  cost  of
influent water treatment.

In   no  case,  however,  should  the  effluent  limitations
computed for a plant  which  combines  waste  water  streams
reflect  effluent reductions (mass units)  less than would be
achieved by the same plant in the case that  the  individual
limited  waste  water  streams  are  not combined with other
waste water streams that are cr are not limited.  Within the
context of the above, effluent limitations computed for  the
plant  should  not  reflect  the  transfer  from  individual
limited waste water streams, whose limitations are based  on
chemical  precipitation  and  sedimentation  technology,  of
pollutants (other than pH) that would otherwise  be  removed
by  chemical  precipitation and sedimentation to other waste
water  streams  that  have  no  limitations  which   reflect
chemical precipitation and sedimentation technology.

If  other  regulations  permit  allowances  to  be  made for
pollutants brought into the  plant  in  make-up  waters,  no
distinction  should  be  made  in  the  effluent limitations
between inert suspended solids brought into  the  plant  and
inert suspended solids added by the plant.  Suspended solids
that  are not inert, such as precipitated metals, should not
be discharged in exchange  for  inert  suspended  solids  in
make-up water.  The requirements can generally be met by the
technology   that   provides  the  basis  for  the  effluent
limitations developed in  this  document  since  the  limits
developed are assumed to apply as gross limits.

For  the purposes of estimating the costs of the application
of available technology  for  the  reduction  of  pollutants
discharged  from  both  continuous  and  intermittent  waste
sources, it is assumed  that  waste  waters  are  discharged
after  treatment  on  a  continuous  and  uniform basis year
round.  A discharger may find, however, that an  alternative
discharge  schedule  would  be less costly or otherwise more
desireable, in which case the  effluent  limitations  should
reflect  the  discharge  flow volume program proposed by the
discharger.
                              417

-------
Costs

The incremental costs of controlled additions  of  chlorine,
in  the  cases  where  chlorine  is  required for biological
control, are less than 0.01 mill/kwh.  In the relatively few
cases where chromates are added for  corrosion  control  and
where  other  less harmful chemicals and methods can provide
effective corrosion control the incremental costs  are  less
than  0.01  mill per kilowatt hour.  The incremental cost of
mechanical cleaning to replace some fraction  of  the  total
required  chlorine  additives is approximately 0.01 mill/kwh
for existing stations and considerably less  for  new  units
whether at new or existing plants.

Cost  estimates  based on the combined treatment of selected
low-volume streams for oil and grease separation,  equaliza-
tion, chemical precipitation, solids separation, and further
based  on  generalizations with respect to the cost of land,
construction, site preparation and with respect to the waste
water volume, indicate an approximate cost of 0.1  mill  per
kilowatt-hour depending upon the plant1s generating capacity
and  utilization.  The highest costs are associated with the
smaller plants and peaking plants which generally  have  the
highest  basic  generating  cost.   In  general,  the entire
incremental cost should be felt by individual  plants  since
this  type  of  complete chemical treatment is not generally
employed.

Sedimentation  of  ash  sluicing  water,  etc.,  would  cost
typically  about 7 cents/1000 gal, with the incremental cost
in mills/kwh being  related  to  the  quantitites  of  water
treated.   Since  many  plants  already  have  some  type of
sedimentation facility, the incremental  costs  of  improved
sedimentation  performance if required will be some fraction
of the cost cited.

In the  few  cases  where  it  would  be  required  chemical
treatment  for removal of phosphorus, total chromium or zinc
from cooling tower blowdown would cost about  0.1  mill  per
kilowatt-hour.    Incremental  costs  of  dry  ash  handling
systems for new sources are estimated to be less  than  0.01
mill/kwh  and  would  largely depend on the economics of dry
ash disposal or sale versus wet  ash  disposal  in  specific
cases.

Recirculating  ash  sluicing  systems  require sedimentation
discussed above plus pumps, piping and  a  blowdown  system.
Incremental  costs above sedimentation are approximately 0.1
mill/kwh for existing plants and considerably less  for  new
plants.
                            418

-------
The  incremental  costs  of  equipment  design for corrosion
protection  are  normally  largely  offset  by  other   cost
benefits  such  as  reduced  costs  of  chemicals.   The net
incremental costs for both lined  cooling  tower  components
and  stainless  steel  or  titanium condenser tubes would be
less than  0.1  mill/kwh  total.   Replacement  of  existing
cooling tower components might be more expensive however.


Enercrv and Other Non-Water Quality Environmental Impacts

Energy   requirements   for   technologies   reflecting  the
application of the best  available  technology  economically
achievable  for pollutants other than heat are less than 0.2
percent of the total plant output.

The non-water quality impacts of technologies  available  to
achieve  limitations  on  pollutants  other  than  heat  are
negligible  with  respect  to  air  quality,  noise,   water
consumption  and  aesthetics.  Solid waste disposal problems
associated  with  achieving  the  limits  required  by  best
practicable   control  technology  currently  available  are
similarly  insignificant.   Systems  with  evaporation   and
recycle of waste water will not generally create significant
amounts  of  solid  waste.   If  recycle  of  blowdown  from
evaporative  recirculating  cooling  systems  were   to   be
employed,  however,  considerable volumes of solid waste may
be  generated.   In  most  cases  these   are   nonhazardous
substances  requiring only minimal custodial care.  However,
some constituents may be hazardous and may  require  special
consideration.   In  order to ensure long term protection of
the   environment   from   these   hazardous   or    harmful
constituents, special consideration of disposal sites may be
made.   All  landfill  sites where such hazardous wastes are
disposed should be selected so as to prevent horizontal  and
vertical  migration  of  these  contaminants  to  ground  or
surface waters.  In cases where geologic conditions may  not
reasonably   ensure  this,  adequate  legal  and  mechanical
precautions (e.g.  impervious liners)  should  be  taken  to
ensure   long   term  protection  to  the  environment  from
hazardous materials.   Where  appropriate  the  location  of
solid   hazardous   materials   disposal   sites  should  be
permanently recorded in  the  appropriate  office  of  legal
jurisdiction.
                             419

-------
                           PART B

                     THERMAL DISCHARGES

                         SECTION V

                   WASTE CHARACTERIZATION

General

Significant   thermal   discharges   from   steam   electric
powerplants occur when a powerplant utilizes a  once-through
circulating  water  system  to reject the heat not converted
into electric energy.  The amount of heat energy  discharged
with the circulating water is equal to the heat value of the
fuel  less the heat value converted into electric energy and
miscellaneous station losses.  The heat energy discharged is
therefore directly related to the efficiency of  the  plant.
According  to  industry  practices, the efficiency of a gen-
erating unit is expressed as its  heat  rate,  in  units  of
Joules per kwh (Btu per kwh).  A new fossil-fired generating
unit  may  be designed for a heat rate of 9.5 million Joules
per kwh (9,000 Btu/kwh).  Since one kwh is equivalent to 3.6
million J/kwh (3,413  Btu),  such  a  plant  would  have  an
efficiency of 38%.

The  transfer of heat from the condensing steam to the cool-
ing water results in  a  temperature  rise  of  the  cooling
water.  For a given amount of heat transfer, the temperature
rise  of  the cooling water is inversely proportional to its
flow.  That is, one may either  heat  a  small  quantity  of
water  a  great  deal,  or a large quantity of water a small
amount.   On  the  average,  temperature  rises  have   been
centered  about  9 degrees C (16 degrees F)  for economic and
process  considerations   (Figure  B-V-1).   It   is   clear,
however, that almost any lower limit on temperature rise can
be  achieved  given  a  sufficiently large source of cooling
water and  no  economic  constraints.   It  is  also  clear,
however,  that  a  temperature difference reduction does not
limit the amount of heat rejection.

Quantification of Waste Stream Characteristics

The data presented below  were  obtained  from  the  Federal
Power  Commission  and  represent a summary of the data col-
lected on "FPC Form 67" for the  year  1969.28°  These  data
have  been  screened  to  eliminate obvious inconsistancies.
The statistical analyses have been performed using  standard
subroutines   available   from   IBM   in  their  scientific
subroutine package  (1000) operating  units.   All  units  in
                             421

-------
                                MINIMUM=1

                                MRXIMUM=38

                                MEflN=15

                                STflNDRRO OEV = 5
 o
 o
 o
 o
 o
 o
 o
 C\J_
=2-
o
 o
 o
 o
 o
 o,
 r\j
        5.00    10.00   15.00  . 20.00   25.00   30.00   35.00   HO.00
                CONDENSER  DELTR T  (DEC. F)


       UNIT  CONDENSER  DELTfl  T
                      FIGURE B-V-1


                         422

-------
this  sample  are fossilfueled.  Heat rates for the industry
are profiled in Figure B-V-2.  This figure  shows  the  mean
unit  heat  rate to be approximately 11.8 million Joules/kwh
(11,200 Btu/kwh) with a standard deviation of  approximately
2.86  million Joules/ kwh (2,700 Btu/kwh).  These statistics
are not weighted by generation.  Weighted figures  show  the
national  average  heat  rate  to be about seven (7)  percent
lower.281 Given the heat rate, one may calculate the cooling
water heat rejection for  fossil  plants  in  the  following
manner:

1.  Multiply the heat rate by the boiler efficiency (0.8-0.9
are reasonable efficiencies to use for this calculation)

2.   Subtract  from  that  number  the energy of one  (1)  kwh
(3,600,000 Joules or 3,413 Btu).

3.  The result is the heat rejected  to  the  cooling  water
stream.

The result obtained from this calculation is slightly higher
than  the  real  requirement  in  most cases.  This analysis
ignores the difference between the lower and higher  heating
values  of  the fuel.  Heat rates can be reported using high
heating values although all this energy is not available  to
do  work.   The  difference is lost forming water vapor from
the hydrogen in the fuel and oxygen in the air.  Various in-
plant heat and steam losses, and the power  requirements  of
the  plant's  auxilliary  equipment are also ignored.  Using
this analysis, the mean plant in our  sample  rejects  about
seven   (7) million Joules (6,640 Btu) per net kwh generated.
Table B-V-1 lists heat rates, efficiencies, and  waste  heat
produced for a range of plants typical of the industry.  The
heat  rejection  requirements calculated above are satisfied
by the heating  of  the  circulating  water.   Figure  B-V-1
indicates  that  the  mean temperature rise  (unit basis, not
weighted) of the cooling water is  between  eight  and  nine
degrees  C  (about 15 degrees F) with a standard deviation of
about three degrees C (5 degrees F).

Flow rates range from, about 1,100  liter/min   (300  gpm)   to
4,000  liter/min   (1,100  gpm) for each megawatt of load.2»o
Thus a 100 Mw unit operating at capacity may discharge up to
400,000 liter/min  (110,000 gpm)  of  water  heated  to  nine
degrees  C  (15-16 degrees F) above ambient.  (A more  typical
number would be about two-thirds of this  example  based  on
national heat rates).

The  maximum  summertime  temperature of the heated effluent
varies with location, but is strongly centered  (Figure  B-V-
                           423

-------
                                 MINIMUM=8706

                                 MflXIMUM=27748

                                 MERN=11216

 §                               STflNDflRD DEV=2710

 0

 CM'



 o
 o

 o
 o.
 t\j
 o
 U3-
 o
 IT-
 o
 C\J_
o
     m


 ^0.00   120.00   160.00  200.00  240.00  280.00  320.00  360.00  400.00
             UNIT  HEflT RflTE (BTU/KW-HR)    *102



       UNIT  HEflT  RflTE  DISTRIBUTION
                         FIGURE B-V-2



                            424

-------
                               Table B-V-1




           EFFICIENCIES, HEAT RATES AND HEAT REJECTED BY COOLING WATER
Plant
Efficiency,
%

38
34
29
23
17

34
29
Plant
Heat Rate
Heat Converted
to Electricity
Stack and Plant
Heat Losses
Heat Rejected
to Cooling Water
Joules per Jcwh x 10~ (Btu/kwh )
Fossil-Fueled Units
9.5 ( 9,000)
10.5 (10,000)
12.5 (12,000)
15.5 (15,000)
21.0 (20,000)
3.6 (3,400)
3.6 (3,400)
3.6 (3,400)
3.6 (3,400)
3.6 (3,400)

0.95 ( 900)
1.05 (1,000)
1.25 (1,200)
1.55 (1,500)
2.1 (2,000)
4.95 ( 4,700)
5.85 ( 5,600)
7.65 ( 7,400)
10.35 (11,100)
15.3 (14,600)
Nuclear Units
10.5 (10,000)
12.5 (12,000)
3.6 (3,400)
3.6 (3,400)
0.5 ( 500)
0.6 ( 600)
6.4 ( 6,100)
8.3 ( 8,000)
in

-------
3)  about 35 degrees C  (95 degrees F).  It is interesting to
note the large number of plants  operating  at  or  above  a
maximum  summertime outfall temperature of 39 degrees C (102
degrees F).  At  elevated  temperatures  turbine  efficiency
frequently begins to suffer.

Table  B-V-2  summarizes data received from powerplants vis-
ited under this contract.  Many of the plants  visited  were
among the most efficient in the nation.

The visits were, in general, made to examine unique features
in  control  or efficiency incorporated in the plant.  These
data, therefore, represent typical values for  newer  modern
plants  rather than an industry-wide cross section.  Of some
interest, however, are the  data  from  the  nuclear  plants
visited.   Since  all  nuclear plants in utility service are
relatively new, these plants may be  considered  typical  of
nuclear  plants.   It is observed that the heat rejection is
considerably higher for nuclear plants (by a factor of  more
than  1.5)   than  for  the fossil-fueled plants studied.  In
addition, the temperature rise for  the  nuclear  plants  is
generally higher.

Industry-wide Variations

Heat  rate varies about thirteen percent regionally.zel This
variation is due to relative equipment age, availability  of
high  quality  fuel,  and  economic  and other factors.  For
example, the northeastern section of the  country  has  many
old,  relatively inefficient units which must be operated to
meet loading requirements.  On the other hand,  the  western
section   of   the  country  uses  a  great  deal  of  lower
heating-value  lignite  which  contributes  to  its   higher
average  heat rate.  The southeastern section of the country
can attribute its lower  average  heat  rate  to  many  new,
large,  efficient  units burning high-quality fuel.  The net
effect of the regional heat rate variation on heat rejection
requirements may be as high as twenty percent (see  previous
section  for  calculations).   This number may be considered
conservative, however, since some of the regional heat  rate
variation is fuel quality dependent.

Temperature  'rise  varies  with  both  heat rate and cooling
water availability.  In  addition,  considerations  such  as
economics,   ambient  water  temperature,  and  water quality
requirements weigh heavily upon  the  design  cooling  water
temperature  rise.   Thus, temperature rise requires a plant
by plant evaluation.
                             426

-------
                               MINIMUM=1
                               MRXIMUM=1 18
                               MERN=95
°                              STRNDRRD DEV=13
o
                   qin
      2c.cc   40.00   eo.cc   so.oo   100.00   :ao.oo   mo.oo   ISU.OD
               MflX.  OUTFRLL TEMP.  (DEC. F)

      MRX,   SUMMER  GUTFniL  TEMP0
                       FIGURE B-V-3

                         427

-------
                                              TABLE B-V-2
                                        PLANT VISIT THERMAL DATA
Plant
0640
1209
2612
1723
3117
1201
1201
5105
2525
0801
1209
4217
4846
3713
2512
3115
2527
0610
2119
ID Fuel
Nuclear
Nuclear
Nuclear
Nuclear
Nuclear
Oil & Gas
Oil & Gas
Oil
Oil
Coal & Gas
Coal & Gas
Coal
Coal
Coal
Oil
Oil & Gas
Oil
Oil & Gas
Coal
Capacity
MM
916
1456
700
1618
457
139.8
792
1157
1165
300
820
1640
1150
2137
542.5
644.7
28
750
2534
Nuclear Averages
Fossil
Averages

Heat Rate
Joules/kwh
x 10-'
N.A.
1.1
1.1
N.A.
1.07
1.02
N.A.
1.09
.95
1.12
.99
1.03
1.05
.92
.94
1.06
1.02
1.15
N.A.
1.09
1.03
Cooling Temp.
Water Flow Rise
M3/min °C
1688
4735
1476
3564
1362
439
2002
1851
2346
1056
2078
2120
2838
3883
632
1429
94.6
1332
2937
N/A
N/A
15.6
8.9
13.9
13.3
10.0
5.7
8.5
13.2
8.2
N.A.
7.3
14.4
7.5
10.0
16.1
9.3
N.A.
10.0
13.9
12.34
10.34
Discharge Temp.
°C
Summer
30.0
40.6
N.A.
36.7
28.6
34.0
39.6
45.4
31.0
N.A.
38.9
31.7
N.A.
28.3
33.4
28.2
N.A.
36.7
N.A.
N/A
N/A
Winter
27.0
28.9
N.A.
14.4
13.9
22.3
29.1
18.2
12.7
N.A.
27.3
17.8
N.A.
17.8
22.6
13.2
N.A.
20.0
N.A.
N/A
N/A

Average
28.3
35.6
N.A.
N.A.
21.7
26.8
32.4
36.3
21.4
N.A.
33.9
26.7
N.A.
N.A.
28.0
21.0
N.A.
26.7
N.A.
N/A
N/A
Heat Dissipation
roules/Hr
X 10-9
6580
10588
5135
11916
3417
624.3
4271
6116
4840
N.A.
3786
7676
5336
9744
2552
3343
N.A.
3343
10229
N/A
N/A
Joules/kwh
X 10-6
7,194
7.27
7.349
7.37
7.48
4.466
5.39
5.285
4.156
N.A.
4.626
4.68
4.645
4.56
4.71
5.196
N.A.
4.46
4.04
7.33
4.68
N.A. - Not Available
H/A  - Not Applicable

-------
Maximum temperature of the outfall varies with both  ambient
temperatures and temperature rise.  Thus higher temperatures
should  be  expected in the southern section of the country.
This expectation is somewhat mitigated by the fact that  the
steam  cycle  has efficiency limitations beyond certain tem-
peratures.  Thus, utilities economically  optimize  tempera-
ture  rise  (a  lower temperature rise requires more pumping
power and/or a larger condenser)  and  final  temperature  (a
higher   final   temperature  reduces  turbine  efficiency).
Therefore, regional variations in maximum summertime outfall
temperature are not  as  large  as  regional  variations  in
ambient water temperatures.

Seasonal  variations in heat rate, temperature rise and out-
fall temperature may be significant  but  move  in  opposing
directions.  That is, when the ambient temperature, the max-
imum  outfall  temperature  and  the heat rate increase, the
temperature rise, in general, falls.  In  many  sections  of
the  country, the summer heat rate is higher than the winter
heat rate because many inefficient peaking  plants  are  run
only  in  the  summer months.  This effect is in addition to
the efficiency loss created by ambient conditions.  The  ef-
ficiency  loss  is  of  particular concern since peak demand
usually coincides with  the  worst  (for  power  generation)
ambient  conditions,  which can cause power shortages.  Con-
versely, the wintertime heat rate (usually better than  sum-
mer) occurs at a time when demand is below peak.  Therefore,
the  heat rejected per kwh, the total heat rejected, and the
maximum outfall temperature are all lower.  While  the  tem-
perature  rise  may  be higher in the winter, it can be con-
trolled by increasing the cooling water flow (which was  cut
back  for  economic  reasons to cause the higher rise in the
first place) .

Age is a frequently mentioned parameter for the thermal  ef-
fluent of powerplants.  Historically, plant aging has been a
double edged sword.  The aging process included material and
equipment  deterioration  (turbine blade erosion, etc.) which
is an absolute loss over a period of time, and  obsolescence
which   is   a   relative   deterioration.   Recent  history
indicates281, however, that there  has  .been  no  heat  rate
improvement  on  a national basis for over a decade.  There-
fore, heat rate deterioration with age is only a function of
material deterioration which is much less dramatic than  the
historic  cycle improvements.  Furthermore, older plants are
traditionally smaller than newer plants.   With  the  demand
for   electricity  increasing  exponentially,  the  capacity
required for peaking and cycling in a system approaches  the
capacity of their older plants.  Therefore, the older plants
are usually derated to peaking and cycling service while the
                             429

-------
larger  new  units are base loaded.  Temperature rise is not
significantly affected by age  (Figure  B-V-4).   While  the
trend  has been slightly upward over the years, the increase
has  been  slight  (largely  for   thermodynamic   reasons).
Maximum  outfall temperature has not changed materially over
the years because the two determining  factors  (other  than
natural conditions)  have changed in offsetting directions.

Unit  capacity has a small effect on heat rate and virtually
no effect on temperature rise.  The effect on heat  rate  is
due  largely  to engineering and capital cost considerations
and to the fact that  small  plants  are  not  usually  base
loaded.

Variation with Industry Grouping

Nuclear  plants  reject  about  5051 more heat to the cooling
water per kwh than fossil plants.  Fossil-fueled plants  re-
ject  from  10%  to  20% of the available fuel energy to the
atmosphere through the stack.  This energy leaves the  plant
in the form of water vapor (heat of vaporization)  created by
burning hydrogenous fuel and heated exhaust gases.

Nuclear  plants  reject  virtually  all  their  heat  to the
cooling water.  If this were the only factor, nuclear plants
of the same efficiency as fossil plants  would  reject  from
18%  to  43% more heat per kwh than fossil plants.  However,
nuclear plants of current design (PWR, BWR)  cannot  produce
superheated  steam  for  the  generation  cycle.   For  this
reason, a well-designed nuclear plant can seldom be expected
to exceed a thermal  efficiency  of  3U%  under  even  ideal
conditions  while well-designed, well-run fossil plants have
achieved thermal efficiencies of up to 39% as an average for
an entire  year's  operation  (plant  no.  3713) 29».   Thus,
nuclear  plants  can  be  expected  to reject more heat than
fossil plants for thermodynamic reasons.  The sum  of  these
two effects yields cooling water heat rejection requirements
in  the  range  of  50%  higher  for nuclear plants than for
fossil plants.  The higher heat rejection  requirements  for
nuclear  plants  are  usually  met by increasing the cooling
water flow and slightly raising the  temperature  difference
across the condenser.  This method is practiced to avoid the
additional   thermodynamic  inefficiencies  associated  with
higher outfall temperatures.

Nuclear plants, then, closely approximate new fossil  plants
in  temperature rise and maximum outfall temperature and are
significantly higher in cooling water requirements.  Fossil-
fueled units can be divided into three categories, based  on
hours operated per year.  The lowest group are operated less
                            430

-------
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                               431

-------
than  two thousand (2,000) hours per year.  The intermediate
group are operated more than two thousand (2,000)   and  less
than  six thousand (6,000) hours per year, while the highest
groups are operated more than six thousand (6,000)  hours per
year.

The highest group heat rates average  11.25  million  Joules
per  kwh  (10,636 Btu/kwh, see Figure B-V-5)  with a standard
deviation  of  about  3.1  million  Joules  per  kwh  (2,100
Btu/kwh).   Intermediate group heat rates average about 13.3
million Joules per kwh (12,U9U Btu/kwh,  see  Figure  B-V-6)
with  a  standard  deviation of about 3.1 million Joules per
kwh  (2,950 Btu/kwh), while the lowest group  averages  about
16.6 million Joules per kwh (15,793 Btu/kwh, see Figure B-V-
7)  with a standard deviation of U.72 million Joules per kwh
(4,U80 Btu/kwh).  The variation in the  heat  rate  mean  is
over  forty-seven  percent, with heat rate varying inversely
with utilization.   The  variation  in  cooling  water  heat
rejection  requirements is clearly higher than the variation
in heat rate since the major portion of the additional  heat
must  be  rejected  to the cooling water.  This is only true
when the plant is on-line.  If a plant is  on  hot  standby,
the  heat  is  rejected to the atmosphere through the stack.
The impact of the increased heat rate is reduced sharply  by
two  factors.   The units with the higher heat rates are on-
line less than the most utilized units and produce far  less
electric  power.   As a result, the total heat rejection per
year  is  far  less  than  for  the  most  utilized   units.
Furthermore,  a  significant  contribution  to the high heat
rates of the less utilized units is the practice of  keeping
these   units   on  hot  standby  during  periods  when  the
probability  of  peaking  demands  is  high.   During  these
periods,  these units produce no electricity and, therefore,
have an infinite heat rate but reject little or no  heat  to
•the  cooling  water.   Thus,  the  heat rate figures for the
least utilized plants tend to be  misleading   (on  the  high
side)  as  well  as  less  important than those for the most
utilized.

(It should again  be  noted  that  all  statistics  in  this
section  are unweighted arithmetic means.  Weighing averages
by  generation  would  produce  lower   heat   rates,   and,
therefore, lower cooling water heat rejection requirements).

Condenser  temperature  rise  does  not  vary  with industry
categorization  (for fossil units).  The mean for  all  three
groups  (based en hours operated per year) is about eight to
nine degrees C  (15-16 degrees F) with a  standard  deviation
of  a  little  under  tnree  degrees  C  (5 degrees F).  (See
figures B-V-8, B-V-9, and B-V-10).
                             432

-------
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                           433

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                          436

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                        437

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                           433

-------
Maximum outfall temperature  will  not  vary  with  industry
grouping  since  it  is the sum of ambient water temperature
(which is unrelated to grouping) and temperature rise across
the condenser (which does not vary with grouping).

In summary,  the  only  waste  stream  characteristic  which
varies  with  industry  grouping  is  the  quantity  of heat
rejected to the cooling water.   The  other  characteristics
vary  with  locale,  season,  etc., and require site-by-site
evaluation to draw any reasonable conclusion.

Finally, Table B-V-3 summarizes typical waste stream charac-
teristic ranges for each grouping.

Effluent Heat Characteristics from Systems Other Than Main
Condenser Cooling Water

Waste heat  from  house  service  water  systems  and  other
smaller  sources  can  contribute  about  1X  of  the  total
effluent heat  discharged  from  a  generating  plant.   For
example,  the  thermal  discharges of one nuclear plant  (no.
4251) are shown in Table B-V-4.  House service water systems
can   be   either   once-through    (nonrecirculatory)    or
recirculating.   Nuclear  plants have emergency core cooling
systems connected to the house service water system.   Where
closed  house  service  water  systems  are used for nuclear
plants,  U.S.  Atomic  Energy  Commission  Safety  Guide  27
requires   (indirectly)  that  sufficient water be stored on-
site  (storage pond) to assure  an  ultimate  heat  sink  for
safety purposes.

Environmental Risks of Powerplants Heat Discharges

Reference  U46  reports  the  results  of  analyses  of  the
environmental risks associated with thermal discharges  from
powerplants  by age, size, etc.  based on a random sample of
180 plants with  455  units.   The  sample  represents  one-
seventh of the U.S. generating capacity through 1978.
                             439

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it*
£t
O
                                           Table B-V-3


                  TYPICAL CHARACTERISTICS  OF WASTE HEAT REJECTION
	 	 _— — _— — !
Grouping
Nuclear
Fossil (Nat-
ional Average)
Reference 281
High Utilization
Intermediate
Utilization
Low Utilization
r 	
Heat Rate,
Joules/ kwh
x 10~7
1.02 - 1.16
1.11
0.92 - 1.32
1.05 - 1.69
1.05 - 2.1
Heat Rejection to Water*
Joules /kwh
x 10
0.72 - 0.80
0.58
0.42 - 0.80
0.53 - 1.07
0.53 - 1.43
Temperature Rise,
°C
10 - 16
8.6
4.5-13
4.5-13
4.5-11
       * Note:  Calculated by method discussed in this section for fossil-fueled plants
                  and from Table B-V-2 for nuclear plants,,

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                               Table  B-V-4
                     TOTAL PLANT THERMAL DISCHARGES
                       Plant No. 4251  (nuclear)
Cooling Water System
Main Condenser
Primary Plant Components
Secondary Plant Components
Centrifugal Water Chiller
Control Room Air Conditioner
Steam Generator Blowdown
(Discharged 1 hr out of
every 100 hr)
Flowrate, gpm
480,400
5,800
11,000
3,000
200
50 max
AT, °F
26
22
10
9
10
120
Heat, Btu/hr x 10~6
6,290
66*
55
13
1
3 max
* Note: 175 x 10  Btu/hr during plant cooldown once a year.

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                           PART B

                     THERMAL DISCHARGES

                         SECTION VI

              SELECTION OF POLLUTANT PARAMETER


Rationale

The Act, Section 502(6), defines heat as a pollutant.

The  purpose  of  this  analysis  is to suggest a functional
parameter reflecting the level of effluent  heat  reductions
achievable  by  the  application  of  available  control and
treatment technology for steam  electric  powerplants.   The
determination  of  a  suitable  parameter  for measuring the
thermal component of the effluent is an  essential  part  of
the  work  in  developing effluent limitation guidelines for
thermal discharges.

The change that has occurred in the  cooling  water  passing
through the condenser is an increase in its internal energy.
This  term  is  also  called  "heat content".  The change in
internal energy or heat content is a  product  of  the  mass
rate  of  water  flow,  its  temperature  increase,  and its
average specific heat.

Both the temperature increase of the cooling water  and  its
discharge  temperature  do not include the quantity of water
discharged at  this  temperature  level,  and  thus  do  not
reflect  the  total  energy or heat discharged.  A parameter
based on  temperature  alone,  therefore,  would  not  be  a
reflection  of  the  effluent  heat  in  the  discharge.  To
adequately evaluate the heat rejection to a receiving water-
body, a parameter reflecting total internal  energy  of  the
discharge is required.

The  parameter  that  has  been  chosen  in  this  report to
represent the effluent thermal characteristics is the  total
increase  in  internal energy or heat content of the cooling
water.  This parameter directly reflects that change in  the
effluent which results in thermal effects.

The  increase  in  internal  energy  or  heat content of the
cooling water is a function of the size of  the  powerplant.
In  order  to compare different size plants, the increase in
internal energy must be  determined  per  kilowatt  hour  of
plant output for each case.  The increase in internal energy
                             443

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or heat content of the condenser cooling water is determined
as follows:

         U = m x ex  T
                 kw

    Where    0 = increase in internal energy of
 condenser cooling water

         m = mass flow rate of cooling water

         c = specific heat of cooling water

         T = temperature increase of cooling water

        kw = unit power output

With commonly used sets of units  U would be expressed in
J/kwh (Btu/kwh) .  Dimensionally, m is expressed kg/hr
(Ibs/hr) cf cooling water, c = 4.186 J/kg/°C (1 Btu/lb/°F)
and  T is expressed in °C (°F)

For example, consider a powerplant with the following
conditions:

Power output:  kw = 225 x 10  kilowatts

Cooling water flowrate: m = 2.72 x 10  kg/hr (6.0 x 10 Ibs/hr)

Temperature increase of cooling water:   T =  11.1°C  (20°F)

Specific heat of cooling water: C = U.186 x 10 J/kg/°C (1 Btu/lb/°F)

The resultant internal energy increase is:

     U = 2.72 x 10 fU.186 x 10 1 (11.U  = 5626 x 10 J/kwh
              225~x 10

or in English units:

     U = 6.10_x_10	111_J[201 = 533 Etu/kwh
               ~225~x 10

This  parameter  provides  a measure of the heat rejected to
the receiving waterhody in a manner  which  can  be  readily
monitored.   The  only  quantities in the equation requiring
measurement are the cooling water flow and temperature  rise
and  power  output  of  the  unit.   Each  of  these  can be
monitored directly without  difficulty  and  utilized  in  a
                             444

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straightforward  manner  to compute the increase in internal
energy or heat content.

Environmental Significance of Effluent Heat

The  effects  of  effluent  heat  on  the  environment   are
generally correlated with water temperature.

Temperature  is  one  of  the most important and influential
water quality characteristics.  Temperature determines those
species that may be present; it activates  the  hatching  of
young,   regulates   their   activity,   and  stimulates  or
suppresses their growth and development;  it  attracts,  and
may  kill  when the water becomes tco hot or becomes chilled
too   suddenly.    Colder   water    generally    suppresses
development.   Warmer  water  generally accelerates activity
and may be a primary cause of aquatic plant  nuisances  when
other environmental factors are suitable.

Temperature is a prime regulator of natural processes within
the  water  environment.  It governs physiological functions
in  organisms  and,  acting  directly   or   indirectly   in
combination   with  other  water  quality  constituents,  it
affects  aquatic  life  with  each  change.   These  effects
include   chemical   reaction  rates,  enzymatic  functions,
molecular  movements,  and   molecular   exchanges   between
membranes  within  and between the physiological systems and
the organs of an animal.

Chemical reaction rates vary with temperature and  generally
increase as the temperature is increased.  The solubility of
gases in water varies with temperature.  Dissolved oxygen is
decreased by the decay or decomposition of dissolved organic
substances  and  the decay rate increases as the temperature
of the water increases reaching  a  maximum  at  about  30°C
(86°F).   The  temperature  of  stream  water,  even  during
summer,  is  below  the  optimum  for   pollution-associated
bacteria.   Increasing  the  water temperature increases the
bacterial  multiplication  rate  when  the  environment   is
favorable and the food supply is abundant.

Reproduction   cycles   may   be  changed  significantly  by
increased temperature  because  this  function  takes  place
under restricted temperature ranges.  Spawning may not occur
at  all  because  temperatures  are  too high.  Thus, a fish
population may exist in a  heated  area  only  by  continued
immigration.    Disregarding   the   decreased  reproductive
potential, water temperatures need not reach  lethal  levels
to decimate a species,  temperatures that favor competitors,
                             445

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predators,  parasites,  and disease can destroy a species at
levels far below those that are lethal.

Fish food organisms are altered severely  when  temperatures
approach  or exceed 90°F.  Predominant algal species change,
primary  production  is  decreased,  and  bottom  associated
organisms  may be depleted or altered drastically in numbers
and distribution.  Increased water  temperatures  may  cause
aquatic plant nuisances when other environmental factors are
favorable.

Synergistic  actions of pollutants are more severe at higher
water  temperatures.   Given  amounts  of  domestic  sewage,
refinery  wastes,  oils, tars, insecticides, detergents, and
fertilizers more rapidly deplete oxygen in water  at  higher
temperatures,  and  the  respective  toxicities are likewise
increased.

When water  temperatures  increase,  the  predominant  algal
species  may change from diatoms to green algae, and finally
at high temperatures to blue-green algae, because of species
temperature  preferentials.   Blue-green  algae  can   cause
serious  odor  problems.   The  number  and  distribution of
benthic organisms decreases as water  temperatures  increase
above  90°F,  which  is close to the tolerance limit for the
population.  This could seriously affect certain  fish  that
depend on benthic organisms as a food source.

The  cost  of fish being attracted to heated water in winter
months may be considerable, due to fish mortalities that may
result when the fish return to the cooler water.

Rising temperatures stimulate the decomposition  of  sludge,
formation  of  sludge  gas,  multiplication  of  saprophytic
bacteria and fungi (particularly in the presence of  organic
wastes),  and  the  consumption  of  oxygen  by putrefactive
processes, thus affecting the  esthetic  value  of  a  water
course.

In  general,  marine  water  temperatures  do  not change as
rapidly or range as widely as those of freshwaters.   Marine
and  estuarine  fishes,  therefore,  are  less  tolerant  of
temperature variation.  Although this limited  tolerance  is
greater  in  estuarine  than  in  open water marine species,
temperature changes are more important to  those  fishes  in
estuaries  and  bays  than  to  those  in open marine areas,
because of the nursery and replenishment  functions  of  the
estuary   that   can   be   adversely  affected  by  extreme
temperature changes.
                            446

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                           PART B

                     THERMAL DISCHARGES

                        SECTION VII

              CONTROL AND TREATMENT TECHNOLOGY
Introduction

This section contains a general discussion  of  the  various
methods   for   controlling  thermal  discharge  from  steam
electric power stations.  There are three methods  available
to  reduce  the  gross  amount of heat rejected to receiving
waters from the steam  electric  power  generation  process.
These methods are:

     . process change
     . waste heat utilization
     . cooling water treatment

Various  process  changes  can  be made to the basic Rankine
cycle to increase its  thermal  efficiency.   These  process
changes  include  increasing boiler temperature and pressure
rating, the addition of reheat and regenerative  cycles  and
reducing turbine exhaust pressure.  In addition, the Rankine
cycle  can  be replaced with other forms of generation which
are inherently non-polluting.  Several of these new forms of
generation are already available, such as  the  gas  turbine
Brayton  cycle and the combined cycle plant.  Looking to the
future,  transfer  of  gas  turbine  technology   from   the
aerospace industry offers the promise of gross plant thermal
efficiencies  approaching  50%  in  the  latter  part of the
decade.  Since the gas turbine is air cooled, its  increased
use  can  significantly  reduce  heat rejection to receiving
waters.

The replacement of the conventional Rankine steam plant with
other forms of power generation is also receiving  increased
attention.  It is anticipated that conservation of available
energy  resources  will  require larger expenditures in coal
research and in the  development  of  new  power  generation
technologies  which do not require fluid fossil fuel.  These
new generation technologies include solar  generation,  fuel
cells,  MHD  and  geothermal  power.   In  the nuclear power
field, the production of a demonstrator breeder  reactor  by
the   end   of  the  decade  will  lead  to  higher  thermal
efficiencies in nuclear power generation.
                             447

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The  utilization  of  portions  of  heat  contained  in  the
discharge  of  condenser cooling water can reduce the amount
of heat rejected from steam electric powerplants.  There are
two different ways in which power station waste heat can  be
beneficially  employed  by others.  This first is to use the
low grade heat contained  in  the  condenser  cooling  water
itself.   Several  small-scale  projects  for utilizing low-
grade heat (mostly for agriculture and aquaculture purposes)
will be described,  other uses for partially expanded  steam
(extraction steam utilization) for industrial process steam,
space  heating  and  cooling,  and water desalting have been
practiced at several locations in conjunction with  electric
power  generation.   The  use  of  extraction  steam methods
generally involves a degradation of the  power  cycle  since
the  steam at the extraction  point has significant enthalpy
remaining.   Because  of  this  loss  of  cycle  efficiency,
extraction  steam  utilization  tends to raise the heat dis-
charged as measured  in  Joules/kwh.   It  is  necessary  in
evaluating  this  type  of alternate use of steam to combine
both the powerplant and the alternate use to  determine  the
benefits derived.

The  major  weakness  of  most  programs  of  low-grade heat
utilization and single-purpose extraction steam  utilization
is that many of the alternate uses of the available heat are
seasonal.   This  means that the additional costs associated
with  providing  the  steam  distribution  systems  must  be
written  off  over relatively few hours during the year.  It
also means that the full amount of heat must  be  discharged
to the waterway during those periods when the secondary heat
consumers  are not operating.  This weakness largely defeats
the purpose of employing low-grade heat utilization systems.
The total energy concept seeks to overcome this  shortcoming
by aggregating all uses of heat in a region to fully utilize
available  energy  on a year-round basis.  Most total energy
systems in this country are small, consisting of  individual
shopping   centers,  educational  complexes  and  commercial
developments.  Larger total energy systems exist in  Europe.
It  is  felt  that  the  rapidly  increasing  cost of energy
brought about  by  greater  worldwide  competition  for  the
earth's  remaining fossil-fuel resources will make the total
energy concept  more  attractive  in  the  future.   Several
different waste heat utilization projects will be described.

A  number  of  different  technologies  have been applied to
condenser cooling water discharges to reduce  heat  rejected
to   the  waterways.   Three  basic  treatment  options  are
available; open cooling systems, closed cooling systems, and
combinations of the two.  Open cooling systems discharge the
full condenser flow following supplemental cooling.   Closed
                            448

-------
systems  recycle the bulk of the circulating water flow back
to  the  condenser  following   supplemental   cooling   and
discharge  a  small fraction as blowdown to control salinity
buildup in the system.

Open cooling systems employing evaporative cooling have  the
basic  disadvantage  of not being able to maintain a desired
level of treatment year-round due to seasonal variations  in
wet  bulb temperature.  Open cooling systems have a distinct
advantage over closed systems in that they do not affect the
turbine backpressure.  A closed cooling system can produce a
low-level  heat  discharge  year-round  at  the  expense  of
increased   turbine   backpressures.    Increasing   turbine
backpressure entails increased station cost above  the  cost
associated  with the cooling system.  These additional costs
are incurred to buy replacement power for those periods when
the station (because of high backpressures)  cannot  produce
its  rated  capacity  (capacity penalty) and also to pay for
increased fuel cost for less efficient  turbine  performance
(energy  penalty).   Both  open  systems  and closed systems
require additional power to operate pumps, fans, etc., which
affects station capacity  and  fuel  cost  to  some  degree.
Incremental   capacity   and   fuel  costs  are  higher  for
backfitting existing units than for new units.

Most existing treatment of condenser cooling water has  been
designed  to  operate in a recycle mode.  These systems have
generally teen installed where sufficient  water  for  once-
through  cooling  was  unavailable.  Some closed systems are
designed to allow open system operation for a portion of the
year.  All of the available cooling  water  treatment  tech-
nologies will be described in this section.

Process Change

Background

In  order  to  properly  understand  both  the  problems and
possible solutions regarding thermal discharges from  power-
plants,  it  is  necessary to review a few essential thermo-
dynamic principles.  Only  those  principles  that  directly
relate   to   the   situation  being  investigated  will  be
discussed.  They will  be  presented  in  simplified  terms,
allowing   a   small   relaxation   cf  rigorous  scientific
exactitude.

The discussion is presented in three steps.  First presented
are principles, and then shown how  they  affect  the  steam
electric  powerplant cycle.  Next, historic developments are
reviewed,  relating  them  to  the  principles.    This   is
                              449

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important  to  understanding  some  approaches  to improving
plants in regard  to  thermal  effects.   Finally,  we  have
related  principles as guides to possible new types of power
generating   systems   with   improved    thermal    effects
characteristics.

Thermodynamics is the study of the conversion of energy from
one form to another, particularly the forms of energy called
"heat"   and  "work".   The  purpose  of  a  steam  electric
powerplant is to convert heat into work or power,  which  is
the  rate  of  work.   Thus,  steam electric powerplants are
directly concerned with thermodynamics.  Important questions
to pose about this process of getting work from heat are:

1.  How can we increase the amount of work obtainable from a
    given amount of heat?

2.  Is there a limit to how  much  work  obtainable  from  a
    given amount of heat?

3.  What happens to the heat  that  is  not  converted  into
    work?

Thermodynamics  is  based  largely  on  two laws.  These are
called the "First Law" and  "Second  Law".   Before  stating
these  laws, it is necessary to include a few definitions of
words or phrases used in the statements of these laws, or in
explaining them.

Keat engine {powerplant)  - a device or plant used to convert
heat into work.

Energy - the ability to do work.  Heat  and  work  are  both
forms of energy.  Work may appear as mechanical energy (such
as the rotation of a wheel) or electrical energy.

Cycle  - the processes or changes which the working fluid of
heat engine (powerplant)  goes through.
                             \
Efficiency - the proportion of  energy  input  (heat)   to  a
powerplant which is converted to energy output (work).

Reservoir - an energy source or an energy receiver.

There  are  a  number of ways of stating the laws of thermo-
dynamics.  We have chosen a special phrasing that seems most
applicable to this study.  It should be remembered that this
is a restricted non-rigorous statement.
                           450

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First Law - the total energy supplied to a  powerplant  must
be removed from the plant.

This  statement  is  akin  to  the  conservation  of  energy
interpretation of the First  Law,  i.e.,  there  must  be  a
budget  or  accounting  of  the energy, and this budget must
balance.

Figure E-VII-1 shows a simplified example of the energy flow
for a power producing engine or plant.

The powerplant receives energy in  the  form  of  heat  from
combustion  of fossil fuels, or from nuclear reaction.  Some
of this energy is converted to a useful output in  the  form
of  work  (electricity).   There  is also heat energy output
from the plant.  This is mainly the energy  associated  with
thermal discharge to receiving waters.

The First Law, which requires an energy balance, thus can be
stated in equational form for this example as:

    Energy In  (Heat) = Energy Out (Work) + Energy Out (Heat)
    or rearranging Energy Out (Heat)  = Energy In (Heat)  -
    Energy Out (Work)

The  importance  of this for thermal discharges is that once
the proportion of Heat Energy In that is converted  to  Work
Energy  Out  is  determined,  the  remainder  is a source of
thermal discharge.  For example, in Figure B-VII-2  relative
values   of   energy   are   indicated  for  a  hypothetical
powerplant.  For this plant, for every 100 units  of  energy
input, HO units are converted to useful work.  The First Law
reveals  that  inexorably  there are 60 units of energy that
must be rejected to the surroundings.   (The relative  values
in  this  example- are close to those typical of modern steam
electric powerplants).

Note however, that the First Law does not require  that  any
heat  be rejected from the powerplant.  It only says that we
cannot produce more energy in the  form  of  work  than  the
quantity  of energy  (in the form of heat) supplied.  At this
point, the following might be asked:

    "Does the energy rejected have to  be  in  the  form  of
    heat?"  "Can  we  build a plant with a better efficiency
    than  in  the  example   cited,   which   seems   pretty
    inefficient   (40X)?"  "Is there any limit on efficiency,
    other than economic considerations?   This  is,  can  we
    reduce  the  heat  rejected  to the environment, without
    limit?"
                             451

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      ENERGY IN
        (HEAT)
POWER
PLANT
ENERGY OUT
   (WORK)


ENERGY OUT
  (HEAT)
        FIGURE B-VII-1 ENERGY FLOW FOR A POWER PLANT
100 ENERGY UNITS IN
     (HEAT)
POWER
PLANT
40 ENERGY UNITS OUT
      (WORK)


60 ENERGY UNITS OUT
      (HEAT)
 FIGURE B-VII-2  ENERGY BALANCE FOR A POWER PLANT (FIRST LAW)
                          452

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Such questions have important implications.  They lead to  a
statement of the Second Law of Thermodynamics:

    "It  is  impossible  for  a  powerplant  to receive heat
    energy from a source and to produce the same  amount  of
    energy as work."

It  might  be  noted  at  this  point that the Second Law of
Thermodynamics cannot be proven from other  principles.   It
is  a  conclusion  reached  by  experience:  observation and
experimentation.  We can picture  a  powerplant  that . would
violate  the  Second  Law as stated in Figure B-VII-3.  Note
that it does not violate the First Law.  In order  to  bring
this  powerplant into conformity with the Second Law, we try
to rearrange its operation as shown in Figure  B-VII-U.   We
are  not producing the same amount of energy as work, as was
supplied in the form of heat.  But now we are violating  the
First Law, as there is an energy unbalance.

In  order  to  make this plant conform to both laws, we must
rearrange its operation as shown in Figure B-VII-5.

The remaining 60 energy units in the form of  heat  must  be
rejected tc the receiver, which is the environment.

Based   on   our  senses  and  experience,  we  are  usually
psychologically  comfortable  with  the   First   Law.    It
expresses  a  principle that a budget must balance.  Yet the
Second Law may seem irrational.  There seems to  be  nothing
unnatural in having a powerplant receive heat energy and, as
a  result,  produce  some  power  with  no  other results or
effects occurring.  Nevertheless,  evidence  indicates  that
such  a  powerplant  cannot  be  built.   Some  heat must be
rejected.  But how much?  Could we build a  powerplant  that
is  99% efficient, if we considered it financially feasible,
thus  rejecting  a  negligible  quantity  of  heat  to   the
environment?

There is an upper limit on the efficiency of any powerplant.
This limit is that provided by a powerplant that operates on
a  completely  reversible cycle.  In this type of cycle, the
plant receives heat  only  at  a  constant  temperature  and
rejects  heat  only at a constant temperature.  In addition,
there are no losses such as friction in any of the processes
taking place.  The efficiency of such a  powerplant  depends
only  on  the  temperature  at which the plant receives heat
from the source, and the temperature  at  which  it  rejects
heat to the surroundings.
                               453

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 100 ENERGY
  UNITS IN
                POWER
                PLANT
100 ENERGY UNITS
   OUT (WORK)
 FIGURE B-VII-3 POWER PLANT VIOLATING SECOND LAW
 100 ENERGY
  UNITS IN
                POWER
                PLANT
 40 ENERGY UNIT3
    OUT (WORK)
FIGURE B-VII-4  POWER PLANT VIOLATING FIRST LAW
                   454

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                          100 ENERGY
                           UNITS IN
                                                 POWER
                                                 PLANT
40 ENERGY UNITS
  OUT (WORK)
                                                                 60 ENERGY
                                                                 UNITS OUT
m
                        FIGURE B-VII-5  POWER PLANT CONFORMING TO FIRST AND SECOND LAW

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The  efficiency of this type of plant can be determined from
the following equation:

         Ere = 100 (1-T2)    (1)
                      Tl

where    Ere = efficiency of reversible cycle powerplant

         Tl  = temperature at which plant receives heat
                from heat source, expressed in absolute units

         T2  = temperature at which plant rejects heat to
                surroundings expressed in absolute units

This equation'can be derived from the Second Law of  Thermo-
dynamics,  in  a  somewhat  lengthy  procedure.  There are a
number of these completely reversible cycles that have  been
conceived  of.   The  best known is called the Carnot cycle.
For this reason, the above efficiency is  often  called  the
Carnot   Efficiency,  although  any  cycle  that  meets  the
specified conditions will have the same efficiency.

It will be instructive to determine what the efficiency of a
completely  reversible  cycle  would  be  for   temperatures
representative  of  modern  steam electric powerplants.  The
maximum temperature at which a plant receives heat is  about
600°C  (1,000°F).   This  is  a  limit  resulting  from  the
decreasing strength of metals at elevated temperatures.  The
minimum temperature at which a plant rejects heat  is  about
32°C  (90°F).   This is a limit resulting from the available
temperature of normal surroundings,  unless  a  plant  could
reject  heat  to  outer  space  at  absolute zero, -273°C (-
«460°F) .

Converting these  temperatures  to  their  absolute  values,
(degrees Rankine), and calculating the efficiency:

         Tl   = 1000 + 460 = 1460°R

         T2   = 90 + 460 = 550°R

         Ere  = 100 (1-550)  =62%
                       1460

This  is  the  highest efficiency that can be reached by any
powerplant operating within these temperature  limits.   The
efficiency  of the most modern powerplants incorporating the
best technology features, operating within these temperature
limits, reaches 40fl.  These  modern  powerplants  achieve  a
quite high efficiency, relative to the maximum.  If one does
                              456

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not  consider  the  Second  Law limitations, 40% seems a low
figure, and  we  might  conclude  that  great  increases  in
efficiency   could   be   made   with   reasonable  research
investment.  But in reality, the "perfect" powerplant  under
these  conditions  is  itself  only 62% efficient.  Thus, an
actual modern powerplant has an efficiency relative  to  the
theoretical possible of:

         Relative Efficiency = 40 x 100 = 65%
                               64

Considering  additionally,  the  minimum practical losses in
each of the components in a powerplant,  even  the  relative
efficiency  of  65% is low as an indicator of the likelihood
of further  improvements  in  the  existing  steam  electric
powerplant   cycle.    In  any  case,  even  with  the  best
theoretical cycle, the same basic  problem  would  exist  of
discharging large amounts of waste heat to the surroundings,
since   only  about  a  33%  reduction  in  present  thermal
discharges would be accomplished.

Referring to Equation  (1), note that the efficiency  of  the
completely  reversible  cycle  is increased by raising Tl or
lowering T2, and that 100% efficiency can be  achieved  only
with  an absolute zero temperature T2, or approached with an
infinite temperature Tl.

History of the Steam Electric Power Plant Cycle

In  this  section,  we  will   outline   the   chronological
development of the thermodynamic cycle of the steam electric
powerplant.   The  purpose  of  this approach is to indicate
what  methods  have  been   developed   to   improve   cycle
efficiency, and indirectly reduce the heat discharged to the
environment.   This  will  aid in understanding problems and
possible directions for future cycle improvements.

The  discussion  should  begin  with  a  description  of   a
completely reversible cycle, as it is the best theoretically
achievable.  In this way, each actual powerplant development
may be compared to the paragon.

The  Carnot  cycle  is  chosen  as the completely reversible
cycle  to  describe.   Figure  B-VII-6   shows   the   basic
components  of  the  Carnot steam powerplant cycle:  boiler,
turbine,  condenser  and  compressor.   The  components  are
connected  by piping as shown, with the direction of flow of
the fluid between them as indicated.
                              457

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                                                                         POWER OUT
m
00
                                BOILER
                                                                        POWER IN
                                   FIGURE B-VII-6 CARNOT CYCLE STEAM POWER PLANT

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The heat source may be combustion of fossil fuel or  nuclear
reaction (or recently geothermal heat).  Heat is transferred
from  the  source  to water in the boiler.  The water enters
the boiler in a saturated liquid condition.  This means that
it is at a temperature where it  will  begin  to  boil  when
heated.   It  does  not  need  to  be  heated  up to boiling
temperature.  The water is  completely  evaporated,  and  it
leaves  as  saturated  steam.   This  means that it has been
completely converted to vapor, but its temperature  has  not
increased.   (Further  heating  of  the  vapor  to  a higher
temperature produces superheated steam).

The steam then flows to a steam turbine, where its energy is
used to rotate a shaft and generate power.  In so doing, the
steam temperature and  pressure  drop  considerably  in  the
turbine.   Steam leaving the turbine flows to the condenser,
where heat is removed from it.

The condenser removes enough heat to partially condense  the
steam  entering.   Thus a mixture of liquid and vapor leaves
the condenser.  The temperature of the condensing steam does
not change during the process.  This mixture  is  then  com-
pressed  in  a  compressor.  This compression process raises
the temperature and pressure of the fluid, and  also  causes
the condensation of the remaining vapor.  The result is that
the  fluid  leaves the compressor at the pre-determined con-
ditions set for the boiler, as  a  saturated  liquid.   Note
that power is required to operate the compressor.

As heat is added in the boiler at a constant temperature and
removed  in  the  condenser  at  a constant temperature, and
assuming no losses in any equipment, the  cycle  will  be  a
completely  reversible  one,  with  the  maximum  efficiency
possible for the temperatures specified.

With  this  paragon  continually  in  mind  as  a  reference
standard,  let  us now turn to the historical development of
tne actual cycles used in the steam electric powerplant.  We
have observed that the cycle modifications and  developments
improved  efficiency,  usually  however,  at  the expense of
increased  plant  complexity.   We  also   note   that   the
developments  brought the actual cycle closer to some of the
features of the Carnot cycle, which being the best possible,
is not a  surprising  development.   Yet  the  Carnot  cycle
itself has great practical deficiencies.

It.  is  worth  noting  that the development of the cycle was
largely accomplished by inventive-minded engineers, and to a
areat extent at a time before  thermodynamics  was  a  fully
understood or applied science.
                              459

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Rankine Cycle

Named  after  the  engineer  W.  J.  M. Rankine (1820-1872) ,
Professor at the University of Glasgow, the  components  and
flow for this cycle are shown in Figure B-VII-7.

The  cycle has four basic components:  boiler, turbine, con-
denser and pump.   A  heat  source  furnishes  heat  to  the
boiler,  water entering the boiler is first heated up to its
saturation  temperature and then evaporated completely.  The
steam flows
to the turbine where its energy is used to  rotate  a  shaft
and generate power.  The steam leaves the turbine at a lower
temperature  and pressure, and flows to the condenser.  Here
the steam is completely condensed to liquid water by  remov-
ing  heat.   A  pump delivers the feedwater to the boiler at
the boiler pressure.  Some of  the  heat  is  added  in  the
boiler to the water, which is at a temperature lower than it
would be in the boiler in a Carnot cycle at the same maximum
temperature.   Thus the efficiency of the Rankine cycle will
be lower than that of the Carnot cycle.

Rankine Cycle with Superheat

Even at very high  pressures,  the  boiling  temperature  of
water  is  considerably  lower  than  can be achieved in the
boiler, with present technology.  Recalling  the  fact  that
the  higher  the  temperature  at which heat is added to the
plant, the greater the efficiency, this means that with  the
Rankine cycle, efficiency is unnecessarily restricted.

A  relatively simple means of improving this situation is to
superheat the  steam.   A  schematic  flow  diagram  of  the
Rankine  cycle  with  superheat  is shown in Figure B-VI1-8.
After the water has been completely evaporated, the steam is
superheated to a higher  temperature,  within  metallurgical
limits.   AS  the  average  temperature  at  which  heat  is
supplied to the plant is higher than with the simple Rankine
cycle, a higher efficiency will result.

Regenerative Cycle

Kith the Rankine cycle, water entering the boiler  is  at  a
relatively low temperature, i.e. the temperature at which it
is  condensed  in  the condenser.  As with the Carnot cycle,
the  lower  the  condensing  temperature,  the  greater  the
efficiency.   However,  with  the Rankine cycle, having this
cool water entering the boiler means that a good part of the
heat is added to the working fluid at an average temperature
considerably below the iraximum.
                             460

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cr>
                           IN
                                                                 'POWER
                                                                  OUT
                                  BOILER
                                                               POWER
                                                                 IN
                                    FIGURE B-VII-7 RANKINE CYCLE POWER PLANT

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a\
ro
                      SUPERHEATER
                               V
          I    HEAT
             SOURCE
                      HEAT
                       IN
BOILER
                                                                  POWER
                                                                  OUT
                                                TURBINE
CONDENSER  / HEAT
                                                                            OUT
                                                            POWER
                                                             IN
                         FIGURE B-VII-8  RANKINE CYCLE WITH SUPERHEAT POWER PLANT

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If the average temperature at which heat is added  could  be
increased,  the cycle efficiency would improve.   This is the
basis for the regenerative cycle.  A schematic flow  diagram
with  components  for  one version of the regenerative cycle
shown in Figure B-VII-9.

In this cycle, the boiler  feed  water  is  preheated  in  a
heater  before  entering the boiler, by means of steam at an
intermediate temperature and pressure bled  from  the  steam
turbine.   The  water  entering the boiler is therefore at a
higher temperature than it would be with the Rankine  cycle.
The heat added from the external source will now be added in
the  boiler  at  a higher average temperature, and the cycle
efficiency will be higher.

To increase the efficiency still further, a few  heaters  in
series  can  be  used,  with  steam bled from the turbine at
progressively  different   conditions.    of   course,   the
complexity  and  cost  of  the  plant  increases  with  more
heaters.

As the number of feedwater  heating  stages  increases,  the
regenerative cycle more closely approaches the Carnot cycle,
because  less  of the heat is added externally at lower than
maximum temperatures  (more is being added internally - hence
the word regenerative).  The question naturally arises as to
why the Carnot cycle itself is not used, as it has a greater
efficiency, and would avoid the complexity  and  expense  of
the feedwater heating stages.

In  actual  conditions,  the  Carnot  cycle  applied to real
equipment would have a poor efficiency.  The turbines, pumps
and compressors have  losses  due  to  mechanical  friction,
fluid  turbulence and similar phenomenae.  Thus the pump and
compressor will require more power  to  operate  than  under
ideal conditions.  It is the nature of the Carnot cycle that
the compressor is a very large power consuming device.  In a
real  plant,  the  actual  power  to operate this compressor
would reduce the actual plant efficiency considerably.   The
Rankine  cycle does not suffer from this shortcoming, as the
pump requires relatively only a small amount of power.

Reheat Cycle

As the steam expands in the  turbine,  in  addition  to  its
temperature  and  pressure  dropping, it begins to condense.
The result is that in  the  latter  stages  of  the  turbine
liquid water droplets form.  Only a small amount of moisture
can  be  tolerated,  due  to possible erosion of the turbine
blades and reduction of turbine  efficiency.   Depending  on
                             463

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             HEAT IN
CTl
                             POWER IN
                                                                      POWER OUT
	. HEAT OUT
CONDENSER/        _ /   HEAT   >

                      RESERVOIR/
                                FIGURE B-VII-9 REGENERATIVE CYCLE POWER PLANT

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the inlet temperature and pressure, if the designer attempts
to  use  the  minimum  condensing temperature available, the
moisture content in the turbine might be excessive.  In that
case, he would have to design the  Rankine  or  regenerative
cycle with a higher condensing temperature and suffer a loss
of efficiency.

A  method  of  overcoming this difficulty is with the reheat
cycle.  Figure B-VII-10 is  a  flow  diagram  of  a  typical
reheat cycle.

Steam   leaving  the  superheater  enters  a  high  pressure
turbine.  The steam does not expand in  this  turbine  to  a
temperature low enough to create excess moisture.  The steam
leaving  the  turbine is reheated at the lower pressure back
to a high temperature.  It then  flows  to  a  low  pressure
turbine  where  it  can  be  expanded  down  to  the minimum
condensing temperature without excess moisture being created
in the turbine.  The reheat cycle can be combined  with  the
regenerative cycle also, in a similar manner.

Historical Process Changes

Changes  in  existing  processes  or their conditions may be
considered as a possible way to improve plant heat rate  and
thus reduce heat rejection.  It is worthwhile to see how the
plant heat rate has already been improved by such changes up
to  the  present  time,  and  then  to view the progress for
further improvements.

By the  1920's  typical  plants  used  steam  pressures  and
temperatures  reaching  about  1,900  kN/sq  m  (275 psi) and
293°C (560°F).  The improved equipment  and  materials  that
became   available  in  the  decade  enabled  pressures  and
temperatures to be increased to the  neighborhood  of  3,792
kN/sq  m  (550 psi) and 343°C  (650°F), resulting in increased
efficiency.  Expansion in the turbine from these conditions,
however, resulted in excessive moisture in the turbine,  and
as a result these plants adopted the reheat cycle.

By  the 1930's further material improvements resulted in the
availability of steam pressures and  temperatures  of  about
6205  kN/sq  m  (900  psi)  and  482°C (900°F).  Under these
conditions, expansion in the turbine occurs down to  minimum
condensing  pressure  without  excessive  moisture, and as a
result plants were typically designed without reheat.

Further material improvements since the 1930*s  resulted  in
higher  available  steam  pressures.   A  pressure of 17,200
kN/sq m (2,500 psi) and temperature of 538°C  (1,000°F) might
                                465

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     H. P.
    TURBINE
  L. P.
TURBINE
FIGURE B-VII-10 REHEAT CYCLE POWER PLANT
                466

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be typical today.  This increase in  pressure  with  corres-
pondingly  little  increase in temperature would result in a
condition of excessive moisture if full expansion were taken
in the turbine in one pass.  Because  of  this,  reheat  has
been  adopted  again in recent decades.  In addition, higher
fuel costs justify the increase in  efficiency  gained  from
reheat.    Generally  only  one  stage  (single)   reheat  is
economical.  For plants that  are  designed  to  operate  at
supercritical  pressures 2,400 kN/sq m (3,500 psi), however,
double reheat may be justifiable.   Triple  reheat  has  not
been  found  economically  feasible  under  any  conditions.
Along with these developments, adoption of the  regenerative
cycle  had  become  standard due to its increased efficiency
over the Rankine cycle.  The efficiency increases  with  the
number (stages) of feedwater heaters used, but of course the
plant  initial  ccst  increases  correspondingly.  For large
plants, present costs justify 7 or 8 stages of heating.

Process Changes for Existing Plants

A summary of possible individual changes in existing  plants
is   shown   in   Table  B-VII-1,  Efficiency  Improvements.
Included in this table  are  approximate  estimates  of  the
improvement  resulting from the change, the work required to
effect it, estimates of outage time that the plant  will  be
down  to make changes, and approximate capital costs.  These
figures are quite approximate, because  they  actually  vary
with existing plant conditions.

Feedwater Heater Additions

Addition  of one heater improves the heat rate about 285 kJ/
kwh  (270  Btu/kwh),  perhaps  2%.   Further  heaters  would
improve  the  heat  rate  by  a succeedingly smaller amount.
Turbine modifications would probably be required.

Reduce Backpressure (Condensing Pressure)

This is accomplished by increasing the velocity of water  in
the  condenser  tubes, which results in better heat transfer
and thus lower condensing  temperature  and  pressure.   The
degree  to  which this improvement can be effected is small.
Tubes must be changed to take the higher velocities  without
erosion,  but  this  is limited.  In any case, the increased
pumping power would offset part, if not all, of the gain  in
efficiency.
                                  467

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                                   TABLE: B-VII-1
                                EFFICIENCY  IMPROVEMENTS
Modification
Add Feedwater
Heaters
Lower Back
Pressure
(Pump more
C.W.)
Increase
Steam
Temperature
c.
Ti
X>

Increase
Steam
Temperature
Add
Reheat
Improvement
in Heat Rate
270 Btu/Htr.
l%/0.5"Hg
0.8%/50°

1450-1800psig
=1.7%; 1800-
2400psig=2.0%;
2400-3500 psig
=1.7%
3-4% for units
operating at
Outage
Work Required Time Cost
Replace turbine, add 8 mos. $25/kw
heater and piping
Change condenser tubes for 2 mos. $6-8/kw
higher velocity. Add new
circulating water pumps
with new intake bays and
piping as required.
Possibility of boiler 3 mos. $6-8/kw
modification to obtain
-25°F. Some modification
.of turbine will be required.
Main steam piping will have
to be replaced.
For 50-100°F increase 8-16 mos. $35-50/kw
make extensive modifi-
cation to boiler (or replace)
and replace turbine plus
steam piping. Turbine
pedestal modifications will
also be required.
Replace boiler, turbine, 16 mos. $60-80/kw
steam and feedwater piping,
some changes to feedwater
heaters. Modify turbine
pedestal and install new
feedwater pumps .
Replace boiler, turbine 24 mos. $100/kw
and hot reheat piping,
Remarks
For same steam flow the unit output
would be reduced by 5%. Charge
required for replacement energy.
Limit of improvement is in the order
0.25"Hg and any gain would probably
be lost to increase pump power.
Practical limit for steam temperature
is 1000 F. Limitation primarily due
to boiler, however turbine also poses
problems

Increases of 3-5% possible without
modification. However, this will not
increase cycle efficiency because the
turbine is designed for maximum
efficiency at rated pressure.
Typical new reheat unit would be 75MV^
or less in size and would operate at
1800 psi and
above.
2-3% for units
operating at
1200-1450 psi
rebuild turbine pedestal,
modify boiler controls,
modify condenser and make
changes to feedwater
heating system.
1450 psi and 950°F.

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Increase Steam Temperature

Small  increases  might be accomplished with boiler and main
steam  piping  modifications.   Larger   increases   require
turbine  replacement  also.   In any case, the maximum steam
temperature practical at the present level of technology  is
about 540°C (1000 °F) .

Increase Steam Pressure

Improvements  in  efficiency  of  the  order  shown  may  be
accomplished  by  increasing  steam   pressures.    However,
extensive replacement of much of the plant is required.

Reheat

On lower pressure units, 10,000 kN/sq m (1150 psi and less) ,
the  efficiency  gain  from  reheat  is less than for higher
pressure units, 12,400 kN/sq m  (1800 psi and  higher).   The
gains  and work required are as shown in Table B-VII-1.  The
extent of work approaches  a  complete  replacement  of  the
plant.

Increase Cooling Gas Pressure

Py  increasing  the  pressure  of  the hydrogen gas used for
cooling the generator,  it  would  be  possible  to  produce
slightly more power from the generator, with higher input.

Drain Coolers

Cycle efficiency may be improved slightly by the addition of
drain  coolers  to the existing feedwater heating system, if
not already included.  Figure B-VII-11 shows  this  arrange-
ment.   The  drain  cooler takes the hot condensate from the
feedwater heater  and  uses  it  to  preheat  the  feedwater
leaving  the condenser.  In this way the cycle efficiency is
increased slightly.

Drains Pumped Forward

Cycle efficiency may be improved  slightly  by  pumping  the
feedwater drains forward, instead of draining it back to the
condenser.   Figure  B-VII-12  shows this arrangement.  Note
that an additional pump is required for pumping the drains.

Superposed Plants

A method of improving the efficiency of  older  plants  that
has  met  with some success is the superposition of a higher
pressure and temperature  system  on  top  of  the  existing
plant.   A  new boiler, turbine, feedwater heaters and pumps
                              469

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-J
o
                                 AAAA
                                HEATER
                            FIGURE B-VII-11   DRAIN COOLER ADDITION TO POWER PLANT

-------
                                                         CONDENSER
FIGURE B-VII-12  DRAINS PUMPED FORWARD IN POWER PLANT

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are added to the plant, exhausting steam to the old  turbine
at  its design conditions (Figure B-VII-13).  The new boiler
may replace the old boiler or supplement it.  The  advantage
of this procedure is that the existing turbine and condenser
are  retained,  and  made  use of.  Economical upgrades of a
number of plants were carried out in this way in the 1930•s.
It is doubtful that  this  approach  would  be  economically
justifiacl= under existing capital cost conditions.

Complete Plant Upgrading

Consider  a  typical  non-reheat unit, rated at 75 Mw, to be
upgraded to get a turbine cycle heat rate  of  approximately
8,U50  kJ/kwh  (8,000 Btu/kwh).  The following changes would
be required:

1.  Raise pressure to 16,500 kN/sq m (2,UOO psi)

2.  Increase superheat temperature to 537°C (1,000°F)

3.  Add reheat to 537° (1,000°F)

U.  Modify the regenerative feedwater heating cycle

To make these changes, the following work is required:

1.  New boiler, turbine and boiler feed pumps

2.  New steam and feedwater piping

3.  New boiler controls

U.  New feedwater heaters

5.  Add cold and hot reheat piping

6.  Rebuild the turbine pedestal

7.  Modify the condenser

8.  Modify parts of the turbine  building  and  rebuild  the
boiler building

The  cost of all this work would be at least as much as that
of a new  plant,   as  that  is  what  it  involves.   It  is
estimated that a 2-3 year plant outage would be required for
the work.
                                  472

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                               NEW PLANT ADDITION
                                   ORIGINAL PLANT
FIGURE B-VII-13  SUPERPOSED PLANT ADDITION
                   473

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Future Improvements in Present Cycles

At  the present time, maximum steam temperatures are limited
to about 537°C (1,000°F).  Temperatures above this  requires
changes  in  the type of steel used in boiler tubing, piping
and in turbines that greatly increase plant costs.  There is
a general consensus in the utility industry that significant
increases in steam temperature are not  forthcoming  in  the
immediate future.

Most  of  the  average  size  units  being  installed at the
present time, in the 300 to 600 Mw  size  range,  are  at  a
pressure  level  of  around  17,200  kN/sq m (2,500 psi).  A
significant  increase  to  supercritical  pressures,  around
2U,100  kN/sq  m   (3,500  psi) is being used for some of the
larger units.  A cycle efficiency improvement of  about  1.5
to 2.0% occurs with this pressure increase.


Gas Cycles

In  addition to the steam vapor powerplant cycle, gas cycles
may be considered  for  generating  electric  power.   These
plants  usually operate on the Brayton (Joule)  cycle or some
modification of this cycle.  Figure  B-VII-1U  indicates  an
arrangement of components, and the gas flow.

Air is drawn into the compressor.  After compression the air
flows  to  a  combustor  where  a  gaseous or liquid fuel is
burned in the air.   The  products  of . combustion  at  high
temperature  and  pressure  flow  through  the  turbine  and
generate power.   This  cycle  may  have  a  relatively  low
thermal   efficiency,   even  though  heat  is  added  at  a
relatively high temperature.   This  is  because  the  gases
discharged  from  the  turbine  are  still  at  a quite high
temperature.  To overcome this a regenerative heat exchanger
is added to the cycle, as shown in Figure B-VII-15.

The  effect  is  to  preheat  the  compressed   air   before
combustion,  utilizing  the waste gas, thus increasing cycle
efficiency.

Further refinements  can  be  made  by  adding  intercooling
between  compressor  stages and by reheating, using a second
combustion chamber.  With these refinements  the  efficiency
of the cycle may increase further.

Gas cycle power generation precludes any significant thermal
wastewater, as the main effluent is a gas.
                              474

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                              FUEL IN
POWER IN
                        COMBUSTOR
                                                POWER OUT
                                              TURBINE
  AIR IN
                                               COMBUSTION
                                                 GAS OUT
  FIGURE B-VII-14 SIMPLE BRAYTON CYCLE GAS TURBINE POWER PLANT

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                                                  FUEL
POWER IN
              AIR
                           COMBUSTION
                             GASES
                                                COMBUSTOR
                                                                                                 POWER OUT
                     FIGURE B VII-15 BRAYTON CYCLE WITH REGENERATOR GAS TURBINE POWER PLANT

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Gas Cycle Plants - Base Power

Plants  using  gas cycles are used for base power today only
in special applications.   The  cycle  efficiency  does  not
equal  that of the steam vapor cycles.  Gas turbines are not
available in sizes adequate for the larger units of  present
powerplant design.

Present  development  of turbines and other plant components
to withstand higher temperatures may make the gas cycle more
attractive in future decades.

Gas Cycle Plants - Peaking Power

The gas turbine cycle is used today for purposes of  peaking
power.   The  structure  of  some power system loads is such
that there is a base load plus short term  requirements  for
peaks  above  that  load.  A gas turbine plant addition is a
natural  consideration   for   this   use.    A   relatively
inefficient  cycle can be used, because of the short periods
of use.  The incremental capital cost of the plant  addition
is low.

The result of this arrangement is no increase in the thermal
wastewater  discharge  for  the  additional power generated.
However this holds only for the incremental power  and  only
during the short time period that the peaking equipment pro-
duces this power.

Combined Gas - Steam Plants

An  efficient  combination  can be obtained by utilizing the
high temperature at which heat is added to the plant in  the
gas  cycle and the low temperature at which heat is rejected
from the plant in the steam cycle.  An example of the  plant
component arrangement is shown in Figure B-VII-16.

The  combined  cycle  has proven advantageous as a method of
up-grading existing older steam plants.  Usually the  situa-
tion  is  one where the existing boilers need replacement or
very extensive rebuilding.  The efficiency of  the  existing
plant  is  usually  not  high, as the steam temperatures and
pressure are considerably lower than those  possible  today.
The  modernization  procedure  usually consists of replacing
existing boilers with gas turbine exhaust heat boilers which
supply steam to the existing steam  turbines.   The  overall
plant  efficiency of such an arrangement might increase 5 to
10%, thereby reducing the thermal discharge correspondingly.

Plant No. 3708 has up-graded part of its plant with  such  a
combined  system.   The  result  has been to reduce the heat
                           477

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    TO
  STACK
-J
00
~l
     r
                 EXHAUST
                   HEAT
                  BOILER

                     COMBUSTOR
 STEAM
TURBINE
                                                      HEATERS
                                      COMPRESSOR
                                                 AIR IN
                                                                                              GAS FLOW

                                                                                              STEAM FLOW
                                    FIGURE B-VII-16 COMBINED GAS-STEAM POWER PLANT

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rate on that part of the plant from  14,770  kJ/kwh  (14,000
Btu/kwh) to 11,610 kJ/kwh (11,000 Btu/kwh).

The  combined  gas-steam  cycle has also been chosen in some
new  plants  recently.   The  overall  plant  efficiency  is
approximately  the same as that which would be achieved with
a modern steam  plant.   However,  gas  turbines  that  will
withstand significantly greater temperatures are expected to
be  available  within  a few years.  Higher temperatures are
already in use in aircraft gas turbines, and the spin-off in
technology should follow as  it  has  previously.   This  is
estimated to result in cycle efficiency improvements of 5 to
10*  for  the  next  generation of combined gas-steam plants
over the best steam plants today.   The  present  design  of
steam  plants  is  not  expected  to  improve  by  a similar
increase  of  temperature.   Technological  improvements  in
boilers to match those of gas turbines are not expected.  If
such developments occured,
it  seems  likely  that  the resultant steam plant would not
economically compete with the combined plant.

Future Generation Processes

Binary Topping Cycles

With steam vapor cycles, much of the heat is  added  to  the
plant at lower temperatures than the maximum possible.  This
heat  is  largely used to evaporate the water.  Vaporization
of water cannot take place above  374°C  (705°F),  therefore
this inefficient heat addition process cannot be avoided.

To  overcome this defect, plants using two fluids, each in a
separate cycle, have been  conceived.   An  example  is  the
mercury-steam  binary cycle.  Mercury is used in the topping
cycle, steam in the bottom (lower temperature) cycle.   Heat
can  be added to the mercury at practically the highest tem-
perature metallurgically  permissible.   A  few  powerplants
have been constructed using this arrangement.

Although this cycle has an inherently higher efficiency than
with  the  steam cycle alone, serious disadvantages have led
to its demise.  Mercury is extremely  expensive  and  highly
toxic.   Seme operating problems were not satisfactorily re-
solved in the plants built.  Theoretical interest  has  been
shown  in  using  other  fluids for the topping cycle  (e.g.,
potassium) but developmental work has been limited.
                              479

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Geothermal Steam

Geological conditions in certain locations provide a natural
source of steam from the earth's heat.   The  steam  can  be
used in a conventional power turbine.  The thermal discharge
rejected  from  the  plant has less internal energy than the
steam,  so  there  is  a  net  negative  thermal  discharge.
However,  the  disposed  waste  heat  could  still  be in an
objectionable form and location.   The  use  of  this  power
source  is  practicably  confined to only a few locations on
the earth, and  thus  does  not  affect  thermal  discharges
generally.

KHD

Magnetohydrodynamics (MHD) is a principle of producing power
quite  different from the steam cycle.  An electrically con-
ducting hot gas is moved at high velocity through a magnetic
field, a procedure that directly generates electricity in  a
surrounding coil.  The present status of this phenomenon for
power production is in experimental development stages only.

Fuel Cells

The  efficiency of a fuel cell is not limited to that of the
Carnot cycle, as it does not receive its energy by means  of
conversion  of  heat  energy  to  work.  Energy is converted
directly from chemical to  electrical  energy.   Fuel  cells
have been commercially developed for certain applications in
small  power  requirements, but at the present time there is
no prospect for large units on the  scale  of  steam  power-
plants.

Waste Heat Utilization

There  are  three ways in which heat produced by powerplants
might be utilized in  an  alternate  manner  to  reduce  the
amount   of   heat  rejected  to  receiving  waters.   These
alternate heat consuming methods are as follows:

- utilization of low-grade heat

- utilization ot extraction steam

- *-otal anergy systems

Utilization of low grade heat

This process means the use of the condenser cooling water in
the condition it is in as it leaves  the  condenser.   Using
low-qrade  heat  in  this  manner  is  desirable  because no
modification  to  plant  performance   is   required.    The
                           480

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disadvantage of this type of system is that the heat content
of  the  condenser  water that is useable is small and large
volumes of water must be transported to  get  a  significant
quantity  of heat.  Of the several systems of low-grade heat
utilization  in  operation   or   in   various   stages   of
development,   most  are  agriculturally  or  aquaculturally
oriented.  The findings of some of these programs  are  dis-
cussed below.

Agricultural Uses

A  considerable  amount  of related work has been planned by
the Tennessee Valley Authority.  TVA has set aside  72.8  ha
(180  acres)  of land at a major nuclear installation (Plant
No. 0113) for the testing of various  ways  of  using  waste
heat.

The  initial effort at the TVA plant will be concentrated on
the development of greenhouse technology for the  production
of  high  value  horticultural crops utilizing the condenser
discharge  water  for  both  heating   and   cooling.    The
information  on these programs has been taken from Reference
353.  Initial tests  will  include  conventional  greenhouse
crops  such  as  lettuce, tomatoes, cucumbers, and radishes.
Later work will include such crops as strawberries  for  the
fresh  out-of-season  market.   Eventually,  a  mix of crops
which fits well in sequence during the year with  production
and   marketing  conditions  and  which  grow  well  in  the
greenhouse climate will be determined.

Preliminary calculations have been made of several crop com-
binations to obtain an estimate of the potential sale  value
per acre of greenhouse.  The data indicate gross sale poten-
tial of from $40,000 to $60,000 per 0.405 ha  (acre)  per year
is  obtainable  depending  on crop mix.  The savings in fuel
cost alone in utilizing the waste heat in this manner may be
upwards  of  $10,000  per  0.405   ha    (acre)   per   year.
Calculations show that the development of 13.0 ha (32 acres)
of  greenhouse  tomato  production and 23.5 ha (58 acres)  of
lettuce would utilize about 6% of  the  available  condenser
water  at the plant, and provide about 1.4* of the total re-
quirements for these products in the Southeast.  The lettuce
production would amount to 30 percent of  that  now  shipped
into   the   combined   Atlanta,   Memphis,  Nashville,  and
Birmingham markets.  TVA is also planning other projects for
agricultural use of waste heat for subsurface heating of the
ground, and also utilizing the greenhouse  concept  for  the
raising  of  pork  and poultry.  These programs are not very
far advanced at this point.
                          481

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A similar study of greenhouse use of  waste  heat  has  been
performed by the AEC and is reported in Reference 351.  This
study  centered  on  the  use of waste heat from a new high-
temperature  gas-cooled  reactor  located  in   the   Denver
vicinity.   The  study  concluded that the cost of equipment
required to utilize the warm water was in the range  of  the
cost of heating systems for conventional greenhouses.  Since
the  cost  of heating greenhouses in the Denver area is over
$5,000 per year, the  potential  value  of  the  heat  being
wasted is greater than $1,000,000 per year.

Aquaculture

The  use of low-grade heat to improve the yields and produc-
tivity for fish and seafood species is  called  aquaculture.
Basic  data indicate that catfish grow three times faster at
28.3°C (83°F) than  at  24.4°C   (76°F).   Similarly,  shrimp
growth is increased by about 8031 when water is maintained at
26.6°C (80°F) instead of 21.1«C  (70°F).

Several  commercial operations of this type are in existence
in the U.S. utilizing waste heat from powerplants.   A  com-
mercial  oyster  farming  operation  is in existance on Long
Island, N.Y. using the thermal effluent from powerplant  No.
3621.   Normal  growing  periods  of  four  years  have been
reduced to 2.5 years by selective breeding, spawning, larvae
growth and seeding oysters in  the  hatchery.   This  avoids
reliance on variable natural conditions and permits acceler-
ated  growth in the thermal effluent discharge lagoon over a
period of about 4-6 months when the water would otherwise be
too cold for maximum growth.  The product  is  marketed  for
$15-20/bushel (1971) which is the upper end of the wholesale
price range.

Catfish  have  been  cultured  in cages set into the thermal
discharge canal of a fossil-fueled plant   (plant  No.  4815)
located in Texas.  During the winter of 1969-70 growth rates
achieved  were  equivalent to 200,000 Ib/acre-year.  This is
comparable to the yields of rainbow trout culture in  moving
water.  The Texas operation is now on a commercial basis.

TVA  also operates a small-scale catfish raising facility at
its waste heat  complex.   Results  from  the  first  year's
operation  confirmed that the growth rate of the catfish was
significantly enhanced by the addition of the  heated  water
and  that  the  growing season was significantly lengthened.
However,  several  problems   prevented   expansion   to   a
commercial  scale  operation.  Feed loss and mortality rates
were high.  Water quality studies showed that high intensity
production of catfish generated  substantial  quantities  of
                           482

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 waste   material    and  that   the   equivalent   of   secondary
 treatment  would be necessary  before the  facilities  could  be
 expanded.

 The   major weaknesses of  low-grade heat utilization are the
 following:

 1.   Inability  to  utilize large  quantities   of  total  waste
 heat  available.    This is   due  not  only  to the capital
 requirement but   also  to  the  fact  that   the product  is
 produced  in   such  quantities  that  it may   exceed market
 demand.

 2.   Uses are seasonal which require either   the dumping  of
 waste  heat in   the off season or the building of  a cooling
 tower in addition to the waste heat utilization systems.

 3.   Inability  to  provide needed heat when plant is  shut down
 and   unadaptability  of the   cultured  organisms   to  rapid
 temperature change.

 Utilization of Extraction  Steam

 Extraction steam  utilization increases both the number and
 the  size of the potential  heat users.  Table B-VII-2 follow-
 ing  shows  the  total annual energy  demand by  several types of
 heat using processes in the United  States.   The   table  is
 taken from Reference 24.
 The   most notable extraction steam heating  system  is  located
 in downtown Manhattan,  in which approximately•300  Mw  of  heat
 is supplied from  extraction  and  back  pressure   turbines.
 This  system has been in operation for many years.  District
 heating  systems of this type are  expected   to  increase  in
 usage in those places  where it can be marketed  successfully
 for  operation of large  tonnage air conditioning  loads.

 Extraction steam heat utilization is  also   used  to   supply
 industrial  process  steam.    The classic case of  extraction
 steam utilization for industrial process steam  takes place
 at powerplant No. 3414  located in the Northeast.  This plant
 supplies  the  bulk  of the  process steam to an  adjacent oil
 refinery.  The plant was designed with  this  capability  in
"mind.   The alternate utilization scheme increases the effi-
 ciency of the generation cycle from 3451  to  54%.   This  is
 equivalent  to  reducing  the waste heat rejected  to  the en-
 vironment by 25%.
                              483

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                                    Table B-VII-2
                           ENERGY DEMAND BY HEAT USING APPLICATIONS (1970)
24
Application
Electricity
Space Heat
Domestic Hot Water
Industrial Steam
Supply Temperature, F
-
200
200
300-400
Energy Used, trillion Btu
4,000
6,000
1,000
5,000
00

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Another form of extraction steam utilization is the  use  of
steam  to  desalt  saline or sea water.  This type of use is
common in arid locations and  also  in  many  of  the  small
islands  in the Caribbean.  Unfortunately, the quantities of
heat consumed by water desalting  processes  are  relatively
small.  The largest water desalting plant in operation today
has a capacity of only 5.0 million gallons of water per day.
This  would require much less than 1% of the waste heat from
a new 1,000 Mw nuclear plant.

The major disadvantage of extraction steam  methods  is  the
necessity  of  combining  the  plant  and the adjacent steam
utilizing process to determine the  overall  performance  of
the  system.   In  addition,  it is difficult to balance the
often variable steam requirements with the power  production
process.

Total Energy Systems

The  total  energy  concept  seeks  to  overcome some of the
obvious shortcomings of the low-grade and  extraction  steam
utilization  concepts by aggregation of all energy consuming
interests in a well defined area.  Most total energy systems
in the United States are  relatively  small,  consisting  of
individual  shopping  centers, educational complexes and in-
dustrial complexes.  The total energy concept  is  practiced
more intensively in Europe.

A   major   study   conducted  by  the  Oak  Ridge  National
Laboratory,  Reference  No.   350,   tested   the   economic
feasibility  of a large energy system serving a hypothetical
new town of 389,000 people.  The climate of the new town was
similar to that of Philadelphia, Pa.  The system provided in
addition to electricity, heat for space heating, hot  water,
and  air  conditioning  for  the  commercial  buildings  and
portions  of  the  apartment  buildings.   Heat   was   also
available  for  manufacturing  processes  and  desalting  of
sewage plant effluent for reuse.  The study  concluded  that
it  would  be possible in the 1975-1980 period and beyond to
supply  low  cost  thermal  energy   from   steam   electric
powerplants   to   new   cities,  especially  those  in  the
population range of 200,000 to  400,000.   With  respect  to
climate,  the  cities  could  be  located  anywhere  in  the
continental  United  States  except  perhaps  in  the   most
southern portions.

The  use of thermal energy extracted for the turbines of the
generating plants would  be  economically  attractive.   For
example,  in  one  configuration of a 1980 city with a popu-
lation of 389,000 people and a climate similar  to  that  of
                             485

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Philadelphia, Pennsylvania, the cost of heat for space heat-
ing and domestic hot water was estimated to be approximately
$1.98/MBtu.355  This system was considered to be competitive
in  that its use would result in an approximately equal cost
compared  with  other  systems.   It  is  anticipated   that
interest  in  total  energy  systems  will  increase  as the
rapidly increasing cost of fuel will  require  corresponding
increases in the efficiency of fuel consumption.

Cooling Water Treatment

General

Steam  electric powerplants employ four types of circulating
water systems to reject the waste heat  represented  by  the
difference  between  the energy released by the fuel and the
electric energy produced by the generators.   These  systems
are  the once-through system, once-through with supplemental
cooling of the discharge, closed systems,  and  combinations
of  the three systems.  In a once-through system, the entire
waste heat is discharged to the  receiving  body  of  water.
The  applicability  of  this  system  is  dependent  on  the
availability of an adequate supply of water to carry off the
waste heat and the ability of the receiving body of water to
absorb the energy.  There is no  reduction  of  total  waste
heat  energy being discharged by the plant in a once-through
system.

A. once-through system with supplemental  cooling  removes  a
portion  of  heat  energy  discharged  by the plant from the
plant effluent and transfers this  energy  directly  to  the
atmosphere.   Various  devices  are  used  to  achieve  this
transfer.  A long discharge canal could be a cooling device.
If a sufficient surface area is not available, the  rate  of
evaporation  per  unit  area  may be increased by installing
sprays in the discharge canal.  If  sprays  do  not  provide
sufficient  evaporative  capacity,  cooling  towers  may  be
utilized in the supplemental cooling mode.   The  amount  of
heat  that  can  be  removed from the circulating water dis-
charge is a function of atmosphere conditions and  the  type
and size of the cooling device provided.

Recirculating  cooling  water systems provide a certain type
of design and operational flexibility leading to lower costs
that is not available with helper  systems.   The  costs  of
cooling  devices  are  related  to  their  size.  The use of
higher cooling water temperatures  allows  for  the  use  of
smaller,  less  costly  cooling devices to transfer the same
amount of waste heat to the environment.  The  recirculation
to  the  condensers  of all, or a part, of the cooling water
                           486

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leaving a cooling device (if its temperature exceeds  intake
cooling water temperature)  would elevate all temperatures in
the  system.   The result would be that, for a fixed system,
more waste heat would be transferred to the atmosphere,  or,
for  a  fixed  waste  heat  load,  a smaller and less costly
cooling device could be used.  In any  case,  the  added  or
reduced  costs  due  to  changes  in  the  energy conversion
efficiency  brought  about  by  the  changed   recirculation
temperatures  would  become  significant  in relation to the
extent of the temperature changes involved.  A further  cost
savings  of  recirculating  cooling  water  systems would be
attributable to the small intake and discharge structures.

A further characteristic of helper systems is that they  are
designed  primarily  to  reduce the temperature of the water
discharged and not the  amount  of  heat  discharged.   When
recirculation  of  a  portion or all of the cooling water is
practiced,  the  temperature  of  the  discharged  water  is
actually  increased  (compared  to  operating  in the helper
mode) but the effluent heat  is  reduced   (compared  to  the
helper mode) because of the reduction in discharge volume.

Closed circulating water systems are currently in common use
in  the  industry,  although  in  the  past  the  reason for
employing closed systems has seldom been the elimination  of
thermal  effects,  but  rather the lack of a source of water
supply adequate for a nonrecirculating system.

The following section describes each  of  these  systems  in
further detail.

Once-Through (Nonrecirculating) Systems

These  are  defined  as  those systems in which the water is
removed from the water source, pumped through the  condenser
in one or more passes to pick up the rejected heat, and then
returned to the water source.  These systems are arranged so
that  the  warm  water  discharged  to the receiving body of
water does not recirculate directly  to  the  intake  point.
Oncethrough  systems  have  been  the  most prevalent in the
United States to date.. In general, other systems have  been
used  only  when sufficient water for once-through operation
has not been available.  The trend has been  away  from  the
use of once-through systems.  Only about one-half of all new
units  are  committed to once-through systems, whereas about
80% of all existing systems are once-through.

The basic design of the once-through,  or  open,  system  is
shown  in  Figure  B-VII-17.   The  purpose  of  the  intake
structure has generally been to prevent trash,  fish,  grass
                            487

-------
  STEAM
   FLOW
DISCHARGE
CANAL OR
 PIPING
                                        COOLING
                                        WATER
                                        PUMPS
OO
       INTAKE
       PIPING
OO
            INTAKE
           STRUCTURE
                    GENERAL WATER FLOW


                          LAKE
                          RIVER
                          ESTUARY
                          OCEAN
    FIGURE B-VII-17 ONCE THROUGH (OPEN) CIRCULATING WATER SYSTEM
                             488

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and  other  materials from entering the condenser and either
plugging or  damaging  the  condenser  tubes,  resulting  in
decreased performance or shut down of the unit for repair of
condenser  tubes.   In  some cases skimmer walls are used to
insure drawing cooling water from deep in the supply source,
where the water is colder.  The pumps required to  circulate
the  water through the condenser are normally located at the
intake structure.  Normally there are several pumps for each
unit, due to  the  large  flows  involved  and  due  to  the
requirement  of providing a higher degree of flexibility and
safety in the operation of the cooling water system.   Flows
for  a single unit can exceed 30 cu m/sec (500,000 gpm), and
some  of  the  large  stations  require  over  60  cu  m/sec
(1,000,000  gpm).   The total annual use of cooling water by
steam electric powerplants is an amount equivalent to  about
15*  of the total flow of all rivers and streams in the U.S.
The cooling water flow rates in some plants is comparable to
the flow rates cf some rivers.

The discharge from the condenser  can  be  returned  to  the
source  via  a  canal or pipe, depending on the local condi-
tions.  The discharge structure serves  two  purposes.   The
first is to return the water in such a manner that damage to
the  stream  bank  and  bottom  in the immediate vicinity is
minimized.  The second is to promote  the  type  of  thermal
mixing  required.  On lakes or estuaries where water veloci-
ties are low, considerable separation between the intake and
outlet structures is required to  prevent  warm  water  from
recirculating directly into the intake.

When  compared  to  closed systems, the water temperature of
the circulating water in the open system tends to be  lower,
thereby  sometimes  allowing  a higher generating efficiency
for the plant with the open system.  Plant No. 3713 has  one
of  the best heat rates in the country, due, in part, to the
low inlet water temperature,  which  does  not  exceed  2«J°C
(75°F), during the summer months.  This is discussed in more
detail  under closed systems.  As a result of the above, the
best
plant efficiencies are generally obtained with  once-through
systems.

Once-Through  Systems with Supplemental Heat Removal  (Helper
Systems)

With the development of the larger generating  stations,  it
has  been  determined in some cases that the large amount of
heat rejected to the environment by cooling water discharged
from  these  stations  could  seriously  affect  the   water
environment.   Consequently,  in  those cases, the utilities
                             489

-------
have been required to re-evaluate  their  thermal  discharge
systems.   One  consideration  short  of recycling condenser
cooling  water  would   be   to   remove   heat   from   the
nonrecirculating   system   prior   to   discharge   to  the
environment.  This would be accomplished by a cooling device
placed  in  the  circuit  between  the  condenser  and   the
discharge  point, as shown in Figure B-VII-18 to divert some
heat directly to the atmosphere.  The amount  of  heat  that
could be removed by such a device operating at full capacity
would   be   dependent  upon  the  atmospheric  or  climatic
conditions, principally wet bulb and dry bulb  temperatures,
or  even  wind  velocity,  solar intensity, and cloud cover,
depending on the type of device used.

Since these heat removal  systems  are  also  applicable  to
closed systems, they will be discussed here in general terms
only.   The  design  and operation of each of the systems is
covered in detail under the closed systems section.  Special
considerations  only  are  covered  in  this  section.    In
general,  limiting climatic conditions are such that while a
majority of the heat can be removed,  the  discharge  stream
temperature  will  always be higher than the receiving water
at the discharge point.

The systems considered for this end of pipe, or helper  mode
of  thermal  discharge  control  are  cooling  towers,  both
natural draft and mechanical  draft,  and  ponds  or  canals
which  can contain floating powered spray modules to augment
the natural cooling process.  The known  installations  tend
to   be  designed  for  operation  in  any  one  of  several
alternative modes.  For example. Plant No.  2708  (Ref.  No*
108dd)  employs a mechanical draft evaporative cooling tower
system capable of  (a)  off-line,  (b)  helper,  (c)  partial
recirculating  and   (d) closed-cycle modes of operation that
is  expected  to  be  capable  of  meeting   water   quality
standards.

Diagrams  of  two  systems  presently  in  use  are shown in
Figures B-VII-19 and B-VII-20.  The system in Figure  B-VII-
19  can  be  operated  in  both  open and closed modes.  The
system shown in Figure B-VII-20 is much more complex.  Units
1 and 2 were  originally  once-through.   When  Unit  3  was
added,  a  once-through  system could not be used due to low
water availability  in  the  summmer.3*'  In- designing  the
closed  cooling  tower  system for Unit 3, it was decided to
add one additional tower, which would  permit  operation  of
all three units on an almost closed system during the summer
when  the  temperature  of the discharge to the river is se-
verely limited by environmental  protection  considerations.
The  systems  illustrated indicate the degree of flexibility
                             490

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                          BOILER
          STEAM
                              TURBINE
                      CONDENSATE
      INTAKE
      PIPING
 PUMPING
 STATION
 INTAKE
 STRUCTURE
00
                                    GENERATOR
                          		 J
                               CONDENSER
                                        DISCHARGE PIPING
                                              OR CANAL
00
                                 HEAT
                                REMOVAL
                                SYSTEM
                                                  DISCHARGE
                                                  STRUCUTRE
                            GENERAL WATER FLOW

                                 LAKE
                                 RIVER
                                 ESTUARY
                                 OCEAN
FIGURE B-VII-18 ONCE THROUGH (OPEN) SYSTEM WITH HELPER COOLING SYSTEM INSTALLED
                                  491

-------
10
K)
                                  COOLING SYSTEM  CAPABLE OP BOTH OPEN
                                       AND CLOSED MODE OPERATION
                                              '(Ref.  108z)         *
                                           FIGURE B-VII-19

-------
           •	 ^&—"\—V"
       .CONDENSER^n^  \ \
PLANT LAYOUT AT PLANT No.  2119

     'From Refei-fijico 359)


       FT'.URE B--Vri-20
                493

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which can be built  into  a  once-through  system  by  using
supplemental heat removal systems.

The  seasonal  variability  of  the  performance of a helper
system is shown in Figure B-VII-21.  This  curve  shows  the
average  monthly performance of a tower located in the East,
and designed to remove 100% of the heat in  September.   The
circulating  water  temperature  rise was assumed to be 11°C
(20°F).  With a stream temperature  of  27.2°C  (81°F),  the
approach was U.5°C (8°F).  During the month of March, with a
stream  temperature  of 5.6°C  (42°F) and a wet bulb of 7.8°C
(46°F) the same tower removes only 22.5% of the  heat,  even
though the approach has increased to 6.U°C (11.5°F).

This  decrease  is  due to the variation in relationship be-
tween stream temperature and wet bulb temperature.   In  the
summer  the  stream  temperature  is well above the wet bulb
temperature.  In winter, in this location, the  stream  tem-
perature drops below the wet bulb temperature.  In addition,
tower performance is lower at the lower winter temperatures.

This  obviously  poses a problem in the design of towers for
"helper" use.  In the case shown, a tower designed to remove
100% of effluent  heat  under  the  worst  winter  condition
(March)  would be over-sized by a factor of 4 during most of
the summer.

There is a relatively simple solution to  this  dilema,  and
that  is  to  partially  close  the system during the winter
months.  Part of the warm circulating water would be  recir-
culated  into the intake stream, increasing its temperature.
This  would  increase   the   discharge   temperature,   and
consequently  the  water temperatures in the tower.  This in
turn would increase the difference between the water and the
wet  bulb  temperature  and  increase  the  amount  of  heat
removed.  The water not recirculated would be discharged.  A
problem  then arises in that the water discharged would have
a temperature significantly above  the  stream  temperature.
This temperature might not meet applicable stream standards,
which . would  mean operation of the tower in two modes: open
in summer and closed in winter.  The tower would be designed
to handle the heat load under the more difficult of the  two
operating conditions.

All   evaporative  type  cooling  systems  would  have  this
decrease in heat removal performance  during  winter  months
when operated in the "helper" mode.

One  other system should be mentioned in this section.  This
is the dilution system to limit the  temperature  effect  of
                             494

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    100
     90
     80
     70
  (3
  LU

  O
     ,60
     50
     40
                                                             TO TOWER
JANUARY
FEBRUAR
MARCH
APRIL
>
5
                                               V)
                                          D
                                          -j
DC
LU
CO

LU
L.
£
LU
00

CC
LU
CO
0
O
O
cc
LU
00
*5»
LU
O
Z
DC
LU
CO
5>
LU
O
LU
Q
        3?

        £
             in
in
p>i
CM
in
(O
in
cvi
oo
                 LO
                                    O)
                       g
in

oi
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                                                                in
LO

(O
FIGURE B-VII-21  SEASONAL VARIATION OF "HELPER" COOLING TOWER (FROM REFERENCE 74)
                                     495

-------
the  discharge  on  the water to which it is discharged.   In
this method an excess of water, above the quantity  required
in  the  condenser is pumped through the intake system, with
the excess being mixed with the hot condenser effluent prior
to discharge into the receiving water.  While this  dilution
reduces the combined discharge water temperature, the amount
of  total  heat  discharged to the water is slightly greater
due to the added generation (and heat rejection)  required to
power the dilution pumps.

Closed or Recirculating Systems

Closed systems recirculate water first through the condenser
for heat removal, and then through a  cooling  device  where
this heat is released to the atmosphere, and finally back to
the  condenser.   Three  basic methods of heat rejection are
used.  The one of most commercial significance in the  power
industry  is  wet,  or  evaporative  cooling  using  cooling
towers, or spray augmented ponds.  Evaporation at  5  x  10s
j/kg (1,000 Btu/lb) is the principal means of heat transfer.
There  is also some sensible heat transfer.  A second method
of closed system cooling commonly employed  is  the  use  of
cooling lakes, which are similar in principal to open, once-
through  systems,  but  which  are  closed  inasmuch  as  no
significant thermal discharge occurs beyond the confines  of
the  lake.  Dry cooling towers, in which heat is transferred
by conduction and convection, have found very limited use.

The following subsections describe the available  technology
for  achieving waste heat removal in closed or recirculation
cooling systems.

1.  Cooling ponds or lakes

2.  Spray augmented ponds

3.  Canals with powered spray modules

4.  Rotating spray system

5.  Wet tower, natural draft - crossflow

6.  Wet tower, natural draft - counterflow

7.  Wet tower, mechanical forced draft

8.  Wet tower, mechanical induced draft, crossflow

9.  Wet tower, mechanical induced draft, counterflow
                           496

-------
10.  Dry tower, direct

11.  Dry tower, indirect

12.  Combined wet-dry mechanical draft tower

The effects of the number of cycles cf concentration in  the
operation  of closed-cycle (recirculating)  cooling towers on
the percentage reduction of effluent heat compared to  once-
through  cooling  is  given in Table B-VII-7 and compared to
once-through "helper" assisted systems in Table B-VII-8.

Cooling Ponds

Cooling ponds are normally artificial lakes constructed  for
the  purpose  of rejecting the waste heat from a powerplant.
A secondary purpose for which the pond is  utilized  is  the
storage  of  water for plant operation during periods of low
natural availability of water.  This dual usage makes  cool-
ing  ponds economical in the more arid areas of the country.
There are also a significant number of cooling ponds in  use
in  the  southern  part of the United States.  While cooling
towers could be used to provide cooling in conjunction  with
a  storage pond, the consumptive use of water in the cooling
tower, plus the losses from the water storage pond, is  gen-
erally greater than the losses from a dual purpose pond.

Two  distinct types of ponds can be identified, based on the
legal means in which discharge is defined.  The first  is  a
pond  located  where there is little or no natural drainage,
or where the water rights on the watershed belong solely  to
the  utility company, and there is no thermal discharge from
the pond.  In this case, the cooling pond is  considered  to
be  completely under the control of the utility company, and
the pond is operated solely to give the best  plant  perfor-
mance.   The cooling pond at plant No. 3514 is an example of
this type.  While the pond itself may not come under thermal
discharge regulations, any  chemical  discharges   (blowdown)
from  the  pond will.  In addition, any other effects of the
cooling lake on the environment would also have to be  taken
into account.

The second case is where the pond is constructed on a water-
shed  having  significant runoff, and where the utility does
not  own  the  pond  and  the  total  water  rights  on  the
watershed.   In this case, the pond is legally considered to
be external  to  the  plant,  and  control  of  the  thermal
discharge  is  subject  to  state  and  federal regulations.
Plant No. 3713 in North Carolina is an example of this type.
                             497

-------
Cooling ponds are normally formed by construction of  a  dam
at  a  suitable location in a natural watershed.  Soil under
the pond must be relatively impervious  to  avoid  excessive
loss  of water.  Ponds may be constructed by excavation, but
generally the cost would be much higher than  for  a  dammed
watershed.  The size of the pond is primarily related to the
plant generating capacity, and rough approximations of 4000-
8000  sq  m  (1  to 2 acres)  per Mw, are found in the liter-
ature.  At 0.8 ha (2 acres) per Mw, the pond for a 1,000  Mw
plant would be 800 ha (2,000 acres) in size.  Thus, the pond
size  for  such  a  plant  would normally be large enough to
serve as a recreational site  in  addition  to  its  primary
function.

When a watershed is dammed to form a cooling pond, the shape
is  determined  by  the topography of the area.  The station
intake and discharge structures are placed  on  the  cooling
pond  so  that  maximum  use  is derived from the pond, i.e.
widely separated, if not at opposite ends of the pond.  With
excavated ponds, the shape is not  totally  limited  by  the
topography.   One  station currently uses a pond with a dike
separating the intake and outfall structures, and  extending
almost  across the lake to provide a U-shaped pond.  Another
station, plant No. 1209, utilizes a series of  canals  as  a
"cooling  pond"  as  shown  in Figure B-VTI-22.  The land is
flat, and the dikes between the canals provide a  convenient
place to pile the material dredged from the canal.

Considerable  research  on  thermal aspects of cooling ponds
has been undertaken.  Likewise some of the research  on  the
discharge  of  condenser  water into lakes and rivers may be
applicable.  References 32, 84, and 120 are part of a series
of five reports dealing  with  cooling  ponds,  and  a  more
comprehensive study is described in Reference 246.

The  performance  of  a cooling pond is dependent to a large
extent on its physical features, as indicated below.

1.  Ponds have been arbitrarily categorized in a  number  of
    ways,  such  as  shallow  or  deep,  stratified  or non-
    stratified, and plug flow or completely mixed ponds.  In
    terms of the above, the ideal pond is a deep, stratified
    pond in which the hot water flows through  the  pond  on
    the  pond  surface  with no longitudinal mixing, and the
    cool water is removed from a deep portion of the lake.

2.  The  configuration  of  the  discharge   structure   for
    discharging  the  hot water from the plant, particularly
    in the case  of  shallow  ponds,  greatly  affects  pond
    performance.  The discharge structure should be designed
                            498

-------
              I


              iSPS**-'1*

-
           COOLING CANAL
            PLANT NO. 1209
             Figure B-VII-22
                    499

-------
    to  spread  the  hot water in a thin layer over the lake
    surface  thus  preventing   mixing   with   the   cooler
    subsurface  water,  and  sustaining  a high pond surface
    temperature  to  promote  rapid  heat  transfer  to  the
    atmosphere.   The suitability of the discharge structure
    is sometimes evaluated in terms of  the  Froude  No.,  a
    ratio   of  the  fluid  momentum  forces  to  the  fluid
    gravitational forces and which relates the  velocity  of
    discharge  to  a characteristic length of the structure,
    normally the width of the channel.

                      Froude No. = V*/Lg

    where V = Velocity of discharge, m/s (ft/sec)

          L = Width of discharge channel, m (ft)

          g = Gravitational constant, 9.82 m/sec* (32.2 ft/
              sec 2)

    Discharge structures are generally  considered  adequate
    for use in relation to cooling ponds when the Froude No.
    is less than 1.0.

3.   The  intake  structure is normally located well beneath
    the pond surface, if not at the bottom.  Its position in
    relation  to  the  discharge  structure  is   important.
    Currents  within  the  pond, particularly wind currents,
    must be considered in placing the structure to  get  the
    best performance out of the pond.

H.   The  pond  shape  has  some effect on performance.  The
    extent of the effect is dependent on the degree to which
    density currents exist within the pond.  For those ponds
    with strong density currents, the pond shape is  usually
    insignificant.

5.   The temperature of the discharge into the pond sets the
    driving forces for  loss  of  heat  to  the  atmosphere.
    Other important considerations include climatic factors,
    particularly wind speed, gross solar radiation, dewpoint
    temperature, and other factors which affect the equilib-
    rium  temperature  of  the pcnd.  The pond size required
    for a particular plant depends on  the  climatic  condi-
    tions  in  the  immediate  vicinity  of  the pond.  Pond
    design is usually based on conditions which approach the
    most  unfavorable   conditions   expected.    The   more
    accurate, reliable, and extensive the available data is,
    the  more  confidence can be placed in a design based on
    these data.  The  importance  of  the  climatic  factors
                             500

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outlined   above   is   demonstrated  in  the  following
equations which describe  the  relationships  among  the
principal factors involved in sizing a cooling pond.  At
steady state conditions, the net heat loss from the pond
is  equal  to  the  waste heat from the powerplant.  The
steady net heat loss from the lake surface  is  normally
expressed as:

                  Heat loss = KA (Ts -TE)

where K  = Heat Exchange Coefficient, J/sq m-day-°C
           (Btu/sq ft-day-°F)

      A  = Area of Lake, sq m (sq ft)

      Ts = Average Surface Temperature, °C (°F)

      TE = Equilibrium Temperature, °C  (°F)

The equilibrium temperature  (TE) can be estimated by
the following equation:

                  TE = Td + Hs/K

where Td = Dewpoint Temperature, °C  (°F)

      Hs = Gross Solar Radiation, J/sq m-day (Btu/sq ft-day)

      K  = Heat Exchange Coefficient, J/sq m-day-°C
           (Btu/sq ft-day-°F)

The heat exchange coefficient (K) is closely related to
windspeed as shown in Figure B-VTI-23, which permits
determination cf K in terms of windspeed and the temper-
ature T = Td * Ts  where an initiate value of Ts must be
             2
assumed.

The  estimation  of the average pond surface temperature
is  an  important  part  of  the  analysis.   Parameters
necessary   for  this  determination  are  the  expected
temperature rise and circulating water flow  rate.   The
degree  of  mixing in the pond must be estimated.  Where
there is little  mixing   (slug  flow),  the  temperature
decrease occurs during the entire transit of the pond by
a  typical slug of circulating water.  The other extreme
is where complete mixing  occurs,  and  the  temperature
throughout  the  pond is the same.  The actual degree of
mixing in any particular case would  lie  between  these
two extremes.
                        501

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    35
                                                                                        \
  in


  + cv







C-1  Q)
•P
(0
t-l
0)
0)
en
a)
     30
     25
     20
        15
        10
                                                          \
                                                      v    :\.  -\_..
                                                      4          5
                                      Windspeed  (m/s)
                CHART FOR ESTIMATING COOLING POND SURFACE HEAT EXCHANGE COEFFICIENT

                                      (From Reference 32)

                                        FIGURE B-VII-23

-------
The  first  step in the procedure for estimating the average
pond surface temperature is to determine the discharge  tem-
perature  to the cooling pond.  This is done by first deter-
mining the quantity:
where K  = Heat exchange coefficient estimated from Figure
           B-VII-23, J/sq m-day-°C  (Btu/sq ft-day-°F)

      A  = Assumed pond area, sq m  (sq ft)

      p  = Density water, kg/cu m (lb/ft3)

      C£ = Heat capacity, J/kg-°C (Btu/lb-°F)

      Qg = condenser flow, cu m/day (ft3/day)


Figure B-VII-2'J can be used  to  determine  the  approximate
area  A.   With  the condenser rise, from Figure B-VII-25, 9
(excess of discharge temperature, TE, over  the  equilibrium
temperature,  TE)  is determined.  Note that curves for slug
flow and complete mixing are given.  Then the discharge tem-
perature, TJD, and the inlet temperature, Tc, can  be  deter-
mined.

      Tp = TE + 9r

      Tc = TJD - Condenser rise
From  Figure  B-VII-26,  using  9  and KA/pcQjD, 9 average is
determined, since 9 is Ts_ -  TE,  Ts  is  determined.   This
value  of  Ts  will  normally  not correspond to the assumed
value used to  determine  K.   The  correct  value  is  then
determined by iteration, i.e., new values for Ts are assumed
and the process repeated until the two values of Ts agree to
the degree of accuracy desired.

Once  Ts has been estimated, the pond area can be determined
from Figure B-VII-24, which determines the area required for
each million kJ (million Btu) of heat to  be  rejected.   If
the  cost  per  acre  of pond surface is known, the cost per
million kJ (million Btu) of heat rejected can be  determined
from Figure B-VII-27.

Costs for cooling ponds are very dependent on local terrain.
In general, costs would include the following:
                             503

-------
    3.0 _
o
,H

X
o
rH
    2.5
    2.0
    1.5
m
0)
S-l
o   i.o
Cn
C
•H
•H
0
o
o
    0.5
                                      T  = Surface Temperature  ( C)
                                       s

                                      T-  = Equilibrium Temperature  ( C)
                                       e
           180200220240260280300320340360380400

                     Heat Exchange Coefficient, k, J/m - C,-day
          COOLING POND SURFACE AREA VERSUS HEAT EXCHANGE COEFFICIENT

                               FIGURF B-VII-24       504

-------
   35
   30
   25
   20  L
u

-------
    25
    20
-l
3
en
0)
    15
    10
          T  - T
           P    e
          27.5 J
          22
16.5
                                Completely Mixed  Pond


                                Once Through Pond
                               1.0
                                  1.5
2.0
                         K A/  P C  Q   (dimensionless)
                                 P  P
      DETERMINATION OF AVERAGE SURFACE TEMPERATURE INCREASE,  8,

            RESULTING FROM  THERMAL DISCHARGE OF STATION

                        FIGURE B-VII-26
2.5

-------
      3.0
                               Cost per Hectare of Pond Surface
                            $2,500
                                                             $7,500
n
I
 X
%
 »•-*•

 ,C
 b
 o
  %
 <
      2.5
      2.0
      1.5
      1.0
      0.5
                                                                         000
                                   j_
             200  400   600   800  1000 1200  1400  1600 1800 2000  2200  2400 2600
                              Capital Cost  ($/10   kJ/hr)
                   ESTIMATION OF CAPITAL COST  OF COOLING POND
                                FIGURE B-VII-27
                                     507

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  I.  Preliminary
      1.  Soil surveys
      2.  Topographical mapping

 II.  Construction
      1.  Dam or basin
      2.  Discharge structure
      3.  Intake structure
      4.  Canals or pipelines associated with 2 and 3
      5.  Makeup water system (pipelines, canals, pumps, etc.),
          if required.
      6.  Auxiliary equipment for above, roads, fencing, etc.

III.  Maintenance
      1.  Canal, pipeline maintenance
      2.  Intake and discharge structures


Spray Ponds

The  total  use  of spray cooling in power generation in not
easily compiled.  Ceramic Cooling Tower Company reports  645
modules  in operation, shipped or in manufacture.   Richards
of Rockford Inc., has 365 units in similar stages for  large
and  small  applications.   Cherne  Industrial reports small
volume sales to  three  customers,  primarily  for  testing.
Ashbrook   Corporation   has   supplied   14  units  to  ten
customers.40S

Spray systems can be utilized to reduce the large  area  re-
quired by cooling ponds by up to a factor of ten.  Two types
of  spray  systems  are available.  In a fixed system, which
essentially operates in a once-through mode, the  hot  water
is  pumped through a grid of piping, into which nozzles have
been placed at regular intervals.  The water is sprayed out,
and cools by evaporation and sensible heat transfer  to  the
air  as  it falls to the pond below,  water from the pond is
pumped directly to the condenser.  To obtain adequate  cool-
ing  on  this  once-through  basis,  the spray must be fine.
This factor, coupled with wind factors, can  lead  to  large
drift  losses and associated problems in the vicinity of the
pond.  The relatively high pumping losses and lengthy piping
required for such a fixed system would  make  this  type  of
design relatively costly for a medium-sized power station.

The  second  type  of  spray pond is commonly called a spray
canal due to its flow-through  hydraulics  and  shape  which
makes  full  use of prevailing winds to enhance cooling per-
formance.  The spray is produced by modules moored at inter-
vals in the canal and floating on the  water  surface.   Two
                              503

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types  currently  in use are illustrated in Figures B-VII-28
and B-VII-29.  The module in Figure B-VII-28 is  a  unitized
pump  and spray module.  The module in Figure B-VII-29 has a
central pump supplying four nozzles.  Both units are powered
by 56,000 watt (75 hp) motors and spray 0.631  cu  m/sec  to
0.789 cu m/sec (10,000 to 12,500 gpm).  Two characteristics
of  this  system are important.  The first is that each slug
of water can be sprayed in repetitive steps, thus minimizing
the need for small droplets required by  the  fixed  system.
The  droplet size can be larger, reducing the drift problem.
Secondly, not all the water need be sprayed, but  enough  to
provide  the  required  cooling.  This permits adjustment of
the number of modules operating to. the  climatic  conditions
and generating level of the plant.

The  use  of  these  modules  in  the  utility  industry  is
relatively new, although tests have been underway  for  some
years.   Plant No. 330U and Plant No.  5105 are using, or are
installing powered spray modules.  The largest  installation
in use is at Plant No. 0610.  The canal of plant no. 0610 is
U-shaped  as  shown  in  Figure  B-VII-30.   The  intake and
discharge structures are at the same end of the  pond.   The
power and control systems for the modules are located on the
central   dike.    Figure  B-VII-31  shows  the  modules  in
operation.  The diameter of the spray pattern  is  about  15
meters  (50 feet).

Plant  No. 1723 is installing a large number of each design.
Spray modules are being used primarily for helper systems on
existing plants when additional units are added to a plant.

The design of the cooling canal is more complex than that of
a cooling tower, and computer programs are often  used.   To
make  the best use of climatic conditions, these systems are
designed as canals where all the modules are exposed insofar
as possible to the ambient air conditions, reducing  adverse
interference  of  performance  due  to  proximity  to  other
modules.  The canals can be circular in shape, or  straight,
as  required.  The canals should be aligned perpendicular to
the prevailing winds for maximum ambient air  exposure,  and
therefore maximum module efficiency.

Design  of  the  system involves determining the incremental
contribution to cooling of each set of  modules  in  series.
The  first  module's inlet temperature is the condenser dis-
charge temperature.  The cooled spray from the first  module
remixes  with the water in the canal, and the resulting tem-
perature of the canal is the temperature at the inlet to the
second set of modules.  This procedure  is  continued  until
the desired temperature is reached, or the increase in over-
                              -.09

-------
                    c->
              ~^
->

->
in

r"
O
                                             UNITIZED SPRAY MODULE


                                               (From Reference  365)


                                                FIGURE B-VII-28

-------
                    40 H MMIM1L
 FOUR SPRAY MODULE
(From Reference  366)
  FIGURE B-VII-29

-------

 SPRAY CANAL
PLANT NO. 0610
 Figure B-VH-30
       512

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                                      •
II-    .

                   £"
                                  ' r



            SPRAY MODULES


            PLANT NO. 0610


             Figure B-VII-31
                     513

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all   performance   with  additional  modules  is  not  cost
effective.  Using seme general data  on  one  manufacturer's
units.  Figure  B-VII-32  was  developed to give a pictorial
representation of the process.  The initial  temperature  is
the inlet temperature to the first set of modules (condenser
discharge  temperature).   The  wet bulb temperature is then
used to determine the expected temperature decrease  of  the
sprayed  water.   From  the percentage of water sprayed, the
change in canal temperature  can  be  determined,  and  this
translated  into  a  new  exit temperature from the modules.
This then becomes the initial temperature for the second set
of modules.  The number of modules in parallel at any  point
in the canal can also be optimized.

The   retrofit   installation   at   plant   no.   1723   is
representative.  The two generating units at the  plant  are
rated  at  809 Mw each.  The cooling canal will encircle the
plant and will be 4.1 km (2.5 miles) long.  The  canal  will
contain  176 units from one manufacturer, and 152 units from
another manufacturer.  The number of modules, or  blocks  of
them  operating at any one time will be adjusted to give the
amount of cooling required.  The installed power for the 328
units is 18,300 kw (2U,600 hp).   At  90%  efficiency,  this
amounts  to 20.4 megawatts, or 1.26% of the plant's previous
output using once-through  cooling.   Since  higher  cooling
water temperatures are expected, thereby reducing the plants
gross  generating  capacity, the combined reduction in plant
generating capacity will be greater than 1.26%.

For the past several years, another  manufacturer  has  been
testing  a rotating disc design for producing sprays.  Their
current design is shown in Figure B-VII-33.  This design  is
currently  undergoing  field  evaluation at a station in the
United States.  A cross section of a  proposed  installation
is shown in Figure B-VII-34.  The spray droplets produced by
these  rotating  discs  are about 1 mm in size.  As with the
fixed spray systems, this size is required to  get  adequate
cooling  performance.   With  this  size  drop,  drift  is a
problem, and adequate provision  to  minimize  drift  losses
must be made.

Insufficient  data  has  been  published  to  make  reliable
performance or cost estimates.  From  some  of  the  limited
performance data the curves in Figures B-VTI-35 and B-VTI-36
were developed.
                                514

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        100  90  80  70  60  50 40  30  20 10  8
Initial Temperature
                                                                                      Wet Bulb Temp.
                                                                                             17.8°C
                                                        Initial Temperature  ( C)
           GRAPHIC REPRESENTATION OF DESIGN OF SPRAY AUGMENTED COOLING POND
                                   Figure B-VII-32

-------
Ul
M
CTi
                                   THERMAL ROTOR SYSTEM

                                      FIGURE B-VII-33

                                   (From Reference 389)

-------
r
                 COOLED WATER CHANNEL
                             tOTORS
                                 ^
                    SPRAY
                                               \U*>~r-	—/-'-
                                               -T-J•---' 24 INLET PIPE y
                                                        PLAN
                                                        ~~~~~~"
                                                    —S~
                                                                                       HOT WATER CHANNEL
                                                                                             .ROIOJS
                                                                    COOLED WATER       ^-HOI WATER

                                                                           SECTION THaU ROTORS
                                                                            --S--
^6 G7.V'«l
~6" SAND
-POLTVINTi
                                          SECTION THRU  CHANNELS
                                                                                  HOT WATER
                                                                      Stale: 1/16 =1'-0
                               DOUBLE SPRAY  FIXED  THERMAL ROTOR
                                      (From Reference 360)
                                        FIGURE B-VII-34

-------
+J
c

-------
X

cn

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Wet Type Cooling Towers

A  number  of  different types of evaporative cooling towers
have been, and are currently, in use.  The basic  types  are
as follows:

                              Natural Draft
Mechanical Draft:             (Hyperbolic):      Dry Type:

Counterflow-Induced Draft     Counterflow        Direct
Crossflow-Induced Draft       Crossflow          Indirect
Counterflow-Forced Draft      Counterflow-
Crossflow-Forced Draft          Fan Assisted
wet-Dry—Any of the above

The  terms  crossflow and counterflow refer to the relation-
ship between the air flow and the water flow.   In  counter-
flow,  the  water flows downward through the packing and the
air flows upward (Figure B-VII-37).  In crossflow, the water
still flows downward, but the  air  flows  horizontally   (or
perpendicularly  to  the  water)  from  outside to inside as
shown in Figure B-VII-38.  Induced draft refers to the means
for developing the air flow by a fan mounted on top  of  the
tower  which pulls the air through the tower  (Figures B-VII-
37 and B-VII-38).  In the  older,  and  little  used  today,
forced draft system fans are mounted around the periphery of
the  tower  at ground level and force the air upward through
the tower.

Drift eliminators, common to all towers except the dry-type,
are used to remove most of the entrained water droplets from
the air stream prior to its leaving the tower.

The wet-dry tower is a relatively new development.  It  con-
sists  of  an  upper  section of dry tower emitting warm air
heated solely by conduction, and a lower wet  section  emit-
ting  the  nearly  saturated  air  which  has a high fogging
potential.  These two air streams are mixed  in  the  tower,
significantly reducing the fogging potential.

Natural  draft  towers  are  commonly  known  as  hyperbolic
towers, since the chimneys are hyperbolic in shape  to  take
advantage  of  the  excellent stress characteristics of this
shape.  The chimneys are normally constructed of  reinforced
concrete.   A  crossflow  tower is shown in Figure B-VTI-39.
The tower shown in Figure B-VII-40, takes up less land space
than the crossflow tower.  The chimneys on these towers  are
tall,  ranging from 90 to over 150 m (300 to over 500 feet).
The tower height has the advantage that the plume is emitted
high enough above the ground that if fog develops,  it  will
normally not create a ground level hazard.
                               520

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                  I AIR I
                  I OUTLET I
                         -FAN
COUNTERFLOW  MECHANTCAL DRAF1  TCWER
              FIGURE B-VII-37
                       AIR
                      OUTLET
                              FAN
                          lll'IV    WATER
                                 INLET\
         CROSSFLOW MECHANICAL DR^JT TOWER
               FIGURE  B-VII-38

-------
           WATER OUTLET
    CROSSFLOW NATURAL DRAFT TOWER

           FIGURE  B-VII-39
      DRIFT   /  HOT-WATER
    ELIMINATOR / DISTRIBUTION
                       •^•* COLD-WATER BASIN
COUNTERFLOW NATURAL-DRAFT COOLING TOWER

            FIGURE E-VII-40
                     522

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A recent modification to the natural draft tower is the fan-
assisted hyperbolic.  In this design, fans are placed at the
periphery  of  the  tower, along the bottom to force the air
through the tower.  The required tower height is diminished,
since air flow does not depend solely on the  difference  in
air   density  inside  and  outside  the  tower  as  in  the
unassisted tower.  Several of these fan-assisted towers  are
in use in Europe, and have been proposed for use in specific
cases in this country.

The  dry-type cooling towers rely solely upon conductive and
convective heat transfer  for  their  cooling  effect.   Two
types  of  systems  are  used.   In the "direct" system, the
steam condenses directly in the tubes of the heat  exchanger
in  the  tower.  This type is restricted to relatively small
plants due to the size  of  the  steam  piping  required  to
circulate   the   relatively  low  density  steam.   In  the
"indirect" sytem, cold water  from  the  tower  is  used  to
condense  the steam from the turbine and the warmed water is
circulated  through  the  tower.   Since   the   system   is
completely  closed,  a direct contact condenser can be used,
greatly  reducing   the   condenser   terminal   temperature
difference  (TTD) .   With  the direct contact condenser, the
circulating water must be of the same quality as the  boiler
makeup water, however direct contact condensers are less ex-
pensive  than shell and tube condensers.  The air system for
the tower may be either induced, forced, or natural draft.

Wet Mechanical Draft Towers

The wet tower cools the water by bringing  it  into  contact
with  unsaturated  air  and  allowing  evaporation to occur.
Heat is removed from the water as latent  heat  required  to
evaporate part of the water.  Approximately 7538 of the total
heat   transferred  is  by  evaporation,  the  remainder  by
sensible heat transfer to the air.

In addition to the thermodynamic potentials,  several  other
factors  influence  the  actual  rate  of heat transfer, and
ultimately, the temperatrue range of  the  tower.   A  large
water  surface  area promotes evaporation, and sensible heat
transfer rates are proportional to the  water  surface  area
provided.   Packing  (an internal lattice work) is often used
to produce small droplets of water and thus  increasing  the
total  surface  area  per  unit  of throughput.  For a given
water flow, increasing the air flow increases the amount  of
heat removed by maintaining higher thermodynamic potentials.
The  packing  height  in  the tower should be high enough so
that the air leaving the tower is close to saturation.
                              523

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The mechanical draft tower consists of the following  essen-
tial functional components:

1.  Inlet (hot) water distribution

2.  Packing (film)

3.  Air moving fans

H.  Inlet-air louvers

5.  Drift or carry over eliminators

6.  Cooled water storage basin
Although  the  principal construction material in mechanical
draft towers is wood, other materials are used  extensively.
In  the interest of long life and minimum maintance, wood is
generally pressure treated with a water-borne  preservative.
Although  the  tower  structure  is  still generally treated
redwood, a reasonable amount of treated fir has been used in
this and other  portions  of  the  tower  in  recent  years.
Sheathing  and louvers are generally of asbestos cement, and
fan stacks of fiber glass.  The trend in fill  is  to  fire-
resistant  extruded  PVC  which, at little or no increase in
cost, offers the advantage of unlimited life  to  its  fire-
resistant properties.  Some asbestos cement is also used for
fill.  Even the trend in drift eliminators is away from wood
to either PVC or asbestos cement.

Two problems arise from the use of wood: decay, and its sus-
ceptibility  to  fire.   On multi-celled towers, the cost of
fire prevention system can run into several hundred thousand
dollars or more,  constant  exposure  to  water  results  in
leaching of the lignin from the wood, reducing its strength.
Steel   construction   is   occasionally   used,   but   not
extensively,  if  at  all,  for  units  in  the   powerplant
industry.

Concrete  construction,  never popular because of relatively
high labor costs, is actively  being  considered  for  large
units   of  the  type  used  in  steam  electric  generating
stations.  The savings in fire protection costs and extended
life make this alternative attractive in many cases.

Inlet water distribution systems are operated at  low  pres-
sure  and  wood  stave  pipe, plastic and metallic pipe have
been used.  The blades on the fans must be reasonably light-
weight, and corrosion resistant.  Both cast aluminum and GRP
                              524

-------
(glass reinforced plastic), are generally used  -today.    For
large  towers  mounted  on the ground, concrete cooled-water
storage basins  are  used  almost  exclusively.   For  other
applications,  both  wood  and  sheet metal basins have been
used.

Reference   6   discusses   the   primary   advantages   and
disadvantages  of  various  types  of  wet  mechanical draft
cooling towers as described below.


Wet Mechanical Draft Tower - Induced Draft - Crossflow

Currently one of the most widely used wet  mechanical  draft
towers  in  the  larger sizes is the induced draft crossflow
tower illustrated in Figure  B-VII-38.   Primary  advantages
for this tower are:

1.  Lower pumping head as a result of lower packing.

2.  Lower pressure drop through the packing.

3.  Higher water loadings for a given height.

U.  Lesser overall tower height.

Compared to the counterflow tower, crossflow towers have the
following disadvantages:

1.  A substantial correction factor must be applied to the
    driving force to take into account the reduced thermo-
    dynamic potentials in parts of the fill.  This is par-
    ticularly true at wide ranges and close approaches.
    More ground area and more fan horsepower may be required
    in some cases.

2.  The packing is not as efficient, and more air flow is
    required for an equivalent capacity tower.


Despite  these  disadvantages, the crossflow tower is widely
used.  With proper louver design, ice  buildup  is  minimal.
The design is much more versatile, with a tower available to
meet almost every need.

Sizing  and costing of mechanical draft towers are dependent
on  climatic  or  operating  conditions.   Basic  parameters
controlling size and cost include:

1.  Climatic conditions, particularly wet bulb temperatures
                             525

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    during the summer months.

2.  Heat load from the powerplant.

3.  Cooling water flow rate (or temperature range).

4.  Approach temperature.

Two of the major cooling tower manufacturers use proprietary
factors for estimating the cost of cooling towers.   Wet bulb
temperature,  approach  temperature  and cooling tower range
are used to determine the factor.  Then, the factor and  the
circulating water flow are used to determine the tower cost.
Tables illustrating use of the factor by one of the manufac-
turers  are shown in Figure B-VTI-41.  The rating factor ob-
tained from these curves is inserted into the following
equation:

Tower Units = Rating Factor x Cooling Flow (gpm)

A set of simple calculations then provides Figure  B-VII-42;
where  cost/10*  Btu is shown as a function of Rating Factor
and cooling tower range.  The cost factor used was $8.11 for
the cost of a tower unit.

The other manufacturer mentioned uses a  slightly  different
technique.   Using  the cooling range, wet bulb temperature,
and approach temperature, a "K" factor is determined.   (Fig-
ure B-VTI-43).  The "K" factor is multiplied by the  cooling
water  flow  rate.   Another chart gives a "C" factor, which
multiplied by the flow through the tower gives an  estimated
capital  cost.  The graph for the "C" factor also has curves
for determining fan horsepower and basin area.  A comparison
between the rating factor of Manufacturer A and the K-Factor
of Manufacturer B is shown in Figure  B-VTI-44.   The  rela-
tionship between the two factors is essentially linear.

The  curves in Figure B-VTI-43 take into account a size fac-
tor, something that the other procedure omits.   Some  costs
for  various K-Factors and ranges are shown in Figure B-VII-
45.

In addition to water lost by evaporation, a small percentage
of the water is lost as drift, or small droplets carried out
of the tower with  the  air  flow.   Drift  eliminators  are
generally  used  in  the  tower to reduce this to a minimum.
Current designs reduce these losses to a small percentage of
the throughput.  This drift  contains  salts  and  chemicals
added  to  the water for treatment.  These droplets fall out
                             526

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       70° WET BULB
         40
         30
         20
           • 5 0-6 0-7  0-6 0-9 1-0  1-1 1-2 1»3  1-4 1-5 1-6
                         RATING FACTOR
TYPICAL CHART FOR  DETERMINING  RATING  FACTOR

               (From Reference 74)
                Figure B-VII-41
                        527

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    3000
    2500
 cc
 I
    2000
 cc
 Ul

 o
 H 1500
 CC
 O
 u

 z

 I  1000
 u
 UJ
 5
 u.
 O

 CO

 8

    500
                           COST BASIS $8.11/TOWER UNIT
                           COST INCLUDES TOWER AND BASIN
                                                       RANGE 10°F
             0.5   0.6    0.7   0.8    0.9   1.0    1.1   1.2   1.3   1.4   1.5


                               RATING FACTOR




FIGURE B-VII-42 COST VS RATING FACTOR MECHANICAL DRAFT TOWER (FROM REFERENCE 74)
                                     528

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APPROACH  5  6  7  8 910 12
                                  COST = CX$100,000
                                  BASIN AREA = CX 100 FT2
                                  FAN HORSEPOWER =C X 100
                                  PUMP HORSEPOWER = GPM X
                                  0.012
  / 10.0
/
    9.0


    8.0


    7.0


    6-°«
        O

    5.0 §
        LL
        O
                                                                     ,1.0
                                                                     10.5
                                   0.5  1.0   1.5   2.0  2.5  3.0  3.5   4.0
                                               K X GPM X 106
        FIGURE B-VII-43 COOLING TOWER PERFORMANCE CURVES
                                                         (57)
                           529

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150




140




J 30




120




1.10




100





 90
 10
        .5
.7   .8
.°   .1.0  1.1  1.2  1.3   1.4   1.5  1.6

 Rating Factor
                                57                    74
         COMPARISON OF K-FACTOR    AND  RATING FACTOR

    FOR  THE PERFORMANCE OF MECHANICAL  DRAFT COOLING TOWERS

                        FIGURE B-VII-44
                              530

-------
 A!

kO
 o
 4J
 U)
 O
 U
 m
 -P
 •H
 ft
 m
 u
1400



1300



1200


1100



1000



 900



 800



 700



 600



 500



 400



 300



 200



 100
                                                             16.7°C
                0.1
                    0.2
0.3
0.4
0.5
0.6
0.7
                                                      3
                          Water Flow Through Tower (m"/s)
0.8
      GRAPH SHOWING  VARIATION OF COST OF MECHANICAL DRAFT COOLING TOWERS

                       WITH WATER FLOW (from Reference  57)
                                FIGURE B-VI1-45

                                      531

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in the surrounding area and  could  result  in  problems  of
corrosion to equipment or damage to plants and trees.

In  addition  to  losses from drift, a certain amount of the
water is intentionally removed from the system  as  blowdown
to control the concentration of salts and chemical additives
in  the  cooling  water.  The amount of blowdown varies with
the quality of the makeup water.  The amount of heat in this
blowdown stream is relatively small.

Aside from the appearance  of  the  physical  structure,  an
additional  visual  result of usage of cooling towers is the
formation of visible plumes of condensed water  vapor  under
appropriate  weather  conditions.   These  plumes are formed
when the temperature of the moisture-laden air  leaving  the
tower  drops  below  the  dew  point.  With mechanical draft
cooling towers, these plumes are close to the ground due  to
the  low  tower  height,  and  will drop to the ground under
certain wind conditions.  With their tall chimneys,  natural
draft  towers  produce  plumes  at  300-500  feet  above the
ground.  Further discussion  of  plumes  is  provided  in  a
subsequent section of the report.

Wet Mechanical Draft Towers - Induced Draft - Counterflow

This  type  of  tower,  pictured  in Figure B-VII-37 is only
slightly different from the crossflow type.  The air flow is
counter to the water flow.  This makes the tower taller than
the  crossflow  tower,  because  additional  space  must  be
allowed at the bottom of the tower for the air to enter.

Some advantages of this system are:

1.  The coldest water contacts the driest air.  The air, as
    it travels up through the water, contacts progressively
    warmer water, maintaining the potential for evaporation.

2.  The fan forces the air straight up, minimizing air recir-
    culation.

3.  Larger fans can be used (up to 18.3 meters (60 feet)).

U.  Closer approaches and large cooling ranges are possible.

There are a number of disadvantages also:

1.  The small air opening at the bottom of the tower leads
    to high pressure drops, and subsequently, higher fan
    horsepower requirements.
                             532

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2.  A more sophisticated air distribution system is required
    to maintain uniform air flow through the packing.

3.  Since the top of the packing is higher above the ground,
    the required pumping head is higher.

Wet Mechanical Draft Tower - Forced Draft

This  tower design, pictured in Figure B-VII-46, is not cur-
rently being used to any extent, particularly in  the  steam
electric utility industry.  Its principal advantages are:

1.  Noise levels and vibration are reduced, since fans are
    mounted at the base of the tower.

2.  Blade erosion is non-existent and condensation in gear
    boxes is greatly reduced.

3.  Fan units are slightly more efficient than induced draft
    type, since development of static pressure in tower per-
    mits some recovery of work.

Disadvantages of the forced draft tower:

1.  Fan size is limited to about 3.6 m  (12 ft), necessitating
    multiple fan installations.

2.  Baffles are necessary for air distribution.

3.  Recirculation of the hot, humid discharge air is a prob-
    lem, as it can flow back to the low pressure intake.

4.  During cold weather, ice may form on the fan blades,
    causing damage and reducing air flow.

A modern adaptation of the type of tower is the fan-assisted
natural draft tower, which is discussed under the section on
natural draft towers.

Wet-Dry Cooling Towers

A  fairly recent development in the mechanical draft cooling
tower is the wet-dry system.  This design combines  the  wet
and  dry tower principles, as shown in Figure B-VII-47.  The
concept was originally developed to reduce or eliminate  the
plumes from mechanical draft towers.

The  principles  of operation are shown in the psychrometric
chart in Figure B-VII-U7.  The air passing through  the  dry
section  is  heated along line 1-3.  The air passing through
                             533

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          MECHANICAL-FORCED DRAFT COOLING

                  FIGURE B-VII-46
                  \ !-*	-DPV S£CTION
                                     O
tt
O

s
3
Z

u
ui
Q.
                                         SUPER SATURATION
                                            (Fog) AREA
                                                              SUPER HEAT
                                                             (Nan-Fog) AREA
                                             'DRY STREAM —•
                                            DRY BULB TEMPERATURE (°F)
PARALLEL  PATH WET DRY COOLING TOWER PSYCHROMETRICS

                 .  FIGURE B-VII-47

                  (From  Reference 128)
                            534

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the wet section is heated and  humidified  along  line  1-2.
When  the  air  from  these two sections is mixed in the fan
plenum, the condition of the mixture lies along line 2-3, at
some point U.  The position of this point  is  dependent  on
the  relative  amount  of  the  two  air streams mixed.  The
relative size of the dry section is dependent on  the  local
climatic  conditions  as  related  to the probability of fog
formation.

The details of construction of the tower for plume abatement
are shown in Figure B-VII-48.  Note the summer  damper  door
used  to  shut  off  most  of  the  air flow through the dry
section during  the  summer  when  plume  abatement  is  not
required.   This  shunts  the  air  flow  to the wet section
during the summer when increased cooling is necessary.

While plume reduction itself can be beneficial, the  concept
of combining the wet and dry sections opens up possibilities
for  applications where water consumption considerations are
important.  By enlarging the dry section, as shown in Figure
B-VII-U9, the principal cooling occurs in  the  dry  system,
with  the wet section used only as required.  The tower per-
formance in such a situation is indicated  on  the  psychro-
metric chart in Figure B-VII-49.  A contract has been signed
for  the  installation  of  four wet-dry towers at plant No.
2416.  The towers will cool 472,000 gpm of  brackish  water.
Details are given in Reference 391.

Natural Draft Cooling Towers

The  natural draft tower, or hyperbolic tower, as it is com-
monly known, has the advantage that no mechanical energy  is
required  to  circulate the air through the tower.  The tall
chimney is used to develop sufficient driving force  between
the  hot, humid air from the fill and the cooler air outside
the  chimney.   This  force  difference  must  overcome  the
internal resistance to air flow.

       (pa - pt) g  X h = Pressure drop through packing +
                go       tower friction loss + kinetic energy
                         of air leaving the tower.

where pa = density of air entering the tower

      pt = density of humid air in the tower

      g  = gravitational constant at elevation of tower

      go * reference gravitational constant

      h  = height of tower
                               535

-------
                            SUB-SATURATED AIR MIXTURE
AIR COOLED
  HEAT
EXCHANGERS
 HINGED SUMMER
 DAMPER DOOR
             SUMMER
  HOT WATER   FUOWONLY
  INLET PIPE
INTERMEDIATE
   WATER
   NORMAL
   AMBIENT
   AIR INLET
 COLD WATER
   BASIN
           PARALLEL-PATH  WET  DRY COOLING TOWER FOR PLUME ABATEMENT
                                    FIGURE B-VII-48
                                 (Froi? Reference  128)
                                   536

-------
                               StCTION
o

en
mJ

ei
O


D
X

u
ui
O.
                                               SUPER SATURATION
                                                  (Fog) AREA
                                                       STUEAM
                                                                      DIMENSIONS INDICATE
                                                                      RELATIVE FlOW RATE
                                                                      SUPER HEAT
                                                                     (Non-Fog) AREA '
                                                                WET STIEAM MASS HOW
                                                 DRY BULB TEMPERATURE (=F)
       COlO WATER
PARALLEL-PATH  WET  DRY  COOLING TOWER  (ENLARGED DRY SECTION)


                            FIGURE  B-VII-49                (Fr°m  Reference 128>

-------
Approximately  a  tenth  of the tower height is utilized for
the air-water contact section, the  remaining  90S  is  used
solely  to  develop  the required driving force for adequate
air circulation.  A typical installation, in plant No. 4217,
is shown in Figure B-VII-50.

The economical use of natural draft towers is restricted  to
regions  with  moderate temperatures and average humidities.
In areas such as the Southwest, with high  temperatures  and
low  humidities,  the  potentials for favorable density dif-
ferences are decreased, resulting in an  impractically  high
chimney  to  provide  circulation  for  the  cooling  tower.
Climatic conditions in the Southeast and Gulf Coast areas do
not favor natural draft towers  because  of  the  high  wind
design loadings.

One  of the benefits of the natural draft tower, and perhaps
the reason it has become so popular, is that the  fog  plume
is  released  several  hundred feet in the air, and does not
create any local hazards  due  to  fogging.   However,  care
should be taken to assure that the stack gases and the tower
plume do not intermix, as any SO2 that may be present in the
stack  gases may tend to combine with the water in the plume
to form damaging acids.

The  tower  may  be  constructed  for   crossflow   or   for
counterflow,  with  both  types in use.  The crossflow takes
slightly more area, as the fill is located outside the tower
proper.  Both types may utilize fireproof construction.  The
fill material employed is asbestos cement.

One manufacturer gives some curves for budget  estimates  of
the  capital costs of their crossflow towers (see Figures B-
VII-51 and B-VII-52).  The costs are shown in 1970  dollars,
and correspond to the relative humidity, range, approach and
wet bulb temperature.

The  fan-assisted  tower,  pictured  in Figure B-VTI-53 is a
modification of the basic natural draft tower which makes it
more versatile by combining some features of  natural  draft
towers  and mechanical draft towers.  The tower looks like a
truncated  natural  draft  tower.   Forced  draft  fans  are
installed  in  place  of the normally large openings for the
entrance of air around the bottom of the  tower.   with  the
forced  draft fans, dependence on the natural chimney effect
is removed, considerably increasing the versatility  of  the
tower.   The shortened natural draft chimney retains some of
                                538

-------
         j$0*f
TYPICAL NATURAL DRAFT
   COOLING TOWERS
   PLANT NO. 4217
    Figure B-VII-50

-------
15° RANGE
10096 RH
           APPROACHES
  0123

      TOWER COST - DOLLARS PER THOUSAND BTU/HR.
25° RANGE
100% RH
                                                        APPROACHES
                                               50 -
  0123

      TOWER COST - DOLLARS PER THOUSAND BTU/HR
   15° RANGE.

   50% RH   APPROACHES
  0123

      TOWER COST - DOLLARS PER THOUSAND BTU/HR.
25° RANGE
50?6  RH
                                                        APPROACHES
  0                  23
      TOWER COST - DOLLARS PER THOUSAND BTU/HR.
   15° RANGE
   25 96RH   APPROACHES
            I         2        .3

      TOWER COST - DOLLARS PER THOUSAND BTU/HR
25°RANGE
2556 RH   APPROACHES
                                                     TOWER COST - DOLLARS PER THOUSAND BTU/HR.
        HYPERBOLIC NATURAL  DRAFT CROSSFLOW WATER COOLING  TOWERS

         TYPICAL COST-PERFORMANCE CURVES  FOR BUDGET  ESTIMATES

                              (From Reference 74)

                                Figure B-VII-51

-------
35° RANGE
10096 RH
         APDRCACHES
    0123
        TOWER COST - DOLLARS PER THOUSAND 8TU/HR
                                               45° RANGE
                                               10096 RH
                                                         APPROACHES
                                                               I         2         3
                                                         TOWER COST - DOLLARS PER THOUSAND BTU/HR
35° RANGE
5036 RH
    0123
        TOWER COST - DOLLARS PER THOUSAND BTU/HR
                                               45° RANGE
                                               5096 RH „
                                                               I         2         3
                                                         TOWER COST - DOLLARS PER THOUSAND BTU/HR
35°RANGE
35%  RH
         ACPP CiC HE S
  80  |	1
  60
              I          2
        TOWER COST - DOLLARS PER THOUSAND BTU/HR
                                                45° RANGE
                                                35%  RH
                                                         APPROACHES

                                                         1111
                                                               I         2         3
                                                         TOWER COST - DOLLARS PER THOUSAND BTU/HR
              HYPERBOLIC  NATURAL  DRAFT CROSSFLOTC WATER COOLING TOWERS
                TYPICAL COST-PERFORMANCE CURVES  FOR  BUDGET ESTIMATES
                                    (From  Reference  74)
                                      Fiaure B-VII-52

-------
Reinforced-concrete veil
based on same design prin-
ciples as Research-Cottrell
hyperbolic natural  draft
towers. Creates natural
draft, reducing fan power
requirement. No need for
orientation with respect to
prevailing wind, or wide
spacing between multiple
units.
Forced-draft fans assist
natural draft, reducing
required tower height.
Tower height can be
just enough to  avoid
problems of vapor
plume downdraft to
ground level, and of
moist air reclrcula-
tlon.
Counterflow design
locates the fill inside the
tower, minimizing pump-
ing head. Fill can with-
stand ice load, if it should
ever accidentally occur,
without  destruction. Veil
and-fill are constructed
entirely  of fireproof, rot-
proof materials—essen-
tially maintenance free.
             FAN-ASSISTED  NATURAL  DRAFT  COOLING  TOWER

                                 FIGURE  B-VII-53

                              (From  Reference 358)
                                    542

-------
the driving force, reducing fan requirements.   The  height,
intermediate  between the mechanical draft and natural draft
tower, reduces the chance of local hazards  from  fog.   The
possibility of recalculation is also reduced.  While no fan-
assisted natural draft towers are currently operating in the
U.S., several towers are operating in Europe.


Dry-Type Cooling Towers

The  dry-type  cooling  tower  is used more in the petroleum
processing industry  than  the  electric  utility  industry.
Being  a  closed system, the bulk of the heat is transferred
from the petroleum products to air directly, with the  final
cooling  to  ambient  temperatures  being  accomplished with
evaporative-type towers.  The temperatures  obtainable  with
dry-type  cooling  towers are higher than those economically
useful  in  the  electric  utility   industry.    Since   no
evaporation  is  involved, the dry bulb temperature governs,
not the wet bulb temperature.  In spite of this, the utility
industry is considering this type  of  system  for  specific
installations  where insufficient water is available for wet
towers.  There are  approximately  six  electric  generating
stations  using  dry-type  cooling  towers,  principally  in
Europe.  The one operating facility in the U.S. is a  20  Mw
unit.   This  is  a "direct" unit, with the steam condensing
directly in the coils.  Construction of a 330 Mw unit at the
same site utilizing a dry tower -is  contemplated.   The  two
types  of  dry  towers,  direct  and  indirect, are shown in
Figures B-VTI-54 and B-VII-55.

The principal drawback to the use of this type of  tower  is
the  higher turbine exhaust pressures which result.  Current
turbine designs would have to *be changed, as  most  turbines
are  designed  for a maximum turbine exhaust pressure of 127
mm Hg  (5 in.  of  Hg  abs)  whereas  with  dry-type  cooling
towers,  the  maximum  turbine  exhaust pressure would range
from 200 to 380 mm Hg   (8  to  15  in.  of  Hg) .   Dry  bulb
temperatures range from 5.5° to 20°C  (10° to 35°F) above the
wet  bulb  temperature.   Due  to  the  higher heat transfer
equipment  costs,  dry-type  towers   optimize   at   higher
approaches  than  wet  towers,  additionally  increasing the
turbine exhaust pressure.

A temperature diagram for an indirect, dry cooling tower  is
shown in Figure B-VII-56.  In dry cooling towers the initial
temperature  difference  (ITD) is used as a design parameter.
The ITD  is  the  difference  between  the  saturated  steam
temperature  of  the  turbine exhaust and the temperature of
ambient air entering the cooling tower.   The  corresponding
                             543

-------
   CONDENSATE
   HEADER
TO FEEDWATER
  CIRCUIT
                                      EXHAUST  STEAM
                 STEAM
                 HEADER
        AIR FLOW
          \   /
         X
          FAN

          -*-
                           CONDENSATE
                           HEADER
                                                    STEAM TURBINE
          STEAM SUPPLY
CONDENSATE
RECEIVER
            CONDENSATE
            PUMP
EXHAUST
STEAM
TRUNK
I
                                                              EXHAUST
                                                              STEAM
 CONDENSATE
 POLISHERS
          Figure B-VII-54
           DIRECT,  DRY-TYPE  COOLING  TOWER  CONDENSING  SYSTEM
                      WITH  MECHANICAL  DRAFT  TOWER
                                                           241

-------
ui
                                        DRAFT TOWER
                                                              STEAM
                                                              TURBINE
                      EXHAUST
                      STEAM
	t  COOLING COILS
                                                                            DIRECT-CONTACT
                                                                              CONDENSER
                                            WATER RECOVERY
                                              TURBINE
                                                                                      STEAM SUPPLY
                                                     CONDENSATE POLISHERS
                                           CIRCULATING PUMP
                                              •MOTOR
                                        CIRCULATING
                                        VMTER PUMP

                                               CONDENSATE TO
                                               REACTOR FEEDWATER
                                               CIRCUIT
                                             Figure B-VII-55
                                INDIRECT, DRY-TYPE  COOLING  TOWER
                        CONDENSING  SYSTEM  WITH  NATURAL-DRAFT TOWER  241

-------
DIRECT-CONTACT
CONDENSER
                 TURBINE EXHAUST
                 STEAM
                                           COOLING COILS
Tsl
r
                          TRANSFER OF HOT CIRCULATING
                          WATER FROM CONDENSER
                          TO TOWER
             1
             u
             cr
             ui
             (L

             UJ
 ^-TRANSFER OF COLD CIRCULATING WATER
  FROM TOWER TO CONDENSER
                (I)
                 I
                                                               AMBIENT
                                                                        tu
                 (2)
                  I
        (3)
         I
(4)
 I
                                                                 AIR
                              (I)   WATER AND STEAM ENTERING CONDENSER

                              (2)   WATER LEAVING CONDENSER

                              (3)   WATER ENTERING TOWER AND AIR LEAVING TOWER

                              (4)   AIR ENTERING TOWER AND WATER LEAVING TOWER
                                      Figure B-VII-56

                           TEMPERATURE  DIAGRAM  OF
                         INDIRECT  DRY COOLING TOWER

                            HEAT-TRANSFER SYSTEM  24°
                                          546

-------
temperature difference in the wet tower system is the sum of
the  approach  to  wet  bulb,  cooling  range  and  terminal
temperature difference (TTD).

Assuming the design parameters typical of  an  eastern  U.S.
location  (dry bulb temperature equal to 32°C (90°F) and wet
bulb temperature of 25°C (76°F)), the turbine exhaust  pres-
sures  corresponding  to a wet system and corresponding to a
dry system can be compared.   For  the  wet  tower,  typical
values   of   the  cooling  range,  approach,  and  terminal
temperature difference are 12, 11 and 5.5°C, respectively.

The sum of these is 29°C (52°F), which yields  a  condensing
temperature  of 53.5°C (128°F) with a corresponding pressure
of 14.5 kN/sq m (4.3 in.  of Hg abs) in the wet system.

A corresponding dry-type tower with an ITD  of  29°C  (52°F)
with  the ambient temperature of 32.2°C (90°F), gives a con-
densing temperature of 61.1°C  (142°F) with  a  corresponding
pressure  of  20.4  kN/sq  m   (6.2  in. of Hg abs).  This is
almost 50% higher than the condensing pressure  in  the  wet
system.

A  number  of  economic studies have been made comparing the
cost and benefits of dry-type towers with wet towers.   Some
data  from  one of these has been used to calculate the cost
curves shown in Figure B-VII-57.  The  curves  are  for  the
cooling  tower  only.   The  variation  in cost shown is due
primarily to the variation  in  construction  costs  in  the
different  locations.  Northeast, West, and Southeast rather
than to  variations  in  the  design  dry  bulb  temperature
indicated on the figure.

The  direct  contact  condenser is considerably cheaper than
the normal shell and tube condenser, as it does not  require
expensive  alloy  tubes.   A typical direct contact condenser
is shown in Figure B-VII-58.  The lower condenser costs par-
ticularly make up for the  greatly  increased  cost  of  the
cooling tower.

There are a number of other benefits from the dry-type cool-
ing tower.

1.  No water usage, thus no large makeup requirements and no
    buildup  of  solids,  chemicals, etc., in the water as in
    an evaporative tower.

2.  There is no possibility of  fogging  and  there  are  no
    drift  losses  to  deposit  minerals  on the surrounding
    territory.
                              547

-------
        10,000  _
o
.-!
\
4-1
in
0
O
ro
•P
•H
0-
flj
CJ
         9,000  _
        8,000
         7,000
        5,000
        5,000
4,000
        3,000
        2,000
        1,000
                          Natural  Draft

                              Towers
                ir
                       Average Design

                      Dry Bulb Temperature
                         18
                 20
25       30

 ITD (°C)
35
                                                       40
45
          REPRESENTATIVE COST OF HEAT REMOVAL WITH  DRY TOWER SYSTEMS

                     (from Ref.  240) FOR NUCLEAR PLANTS

                             FIGURE B-VII-57
                                    548

-------
Ul
it*
          WATER INLET
          AIR VAPOR
         •OFFTAKE
          CASCADE
          PLATES
          CONOENSATE
          OUTLETS
                        STEAM INLET
                       EXPANSION JOINT
                                               STEAM INLET FROM
                                                TURBINE EXHAUST
                                                       WATER DISTRIBUTION
                                                           PLATE
                                        Figure B-VII-58
                                       STREAM TYPE
                             DIRECT CONTACT  CONDENSER240

-------
On the other side of the ledger, there is a significant loss
in plant efficiency due to the higher turbine exhaust  pres-
sures.  Figure B-VII-59 gives the expected increases in fuel
consumption  and  decrease in power output for a nuclear and
fossil-fueled plant, provided the turbine could  operate  at
the higher pressures indicated.  Not only is there a loss in
efficiency, but the maximum plant capacity is also reduced.

Other Tower Types Used Outside the D.S.

Conventional  multicell evaporative mechanical draft cooling
towers and evaporative natural draft cooling towers are used
outside the U.S.,  as  are  several  types  of  dry  cooling
towers.   Another type of tower widely used outside the U.S.
is the circular base evaporative  mechanical  draft  cooling
towers.   The basic design of this type of tower is shown is
Figure B-VII-60.  One firm has supplied  hundreds  of  these
towers,  in sizes up to approximately 40,000 metric tons per
hour circulating water rate.   A  tower  at  the  Staudinger
plant  handing  40,000  metric  tons/per  hour  has  a  base
diameter of 61 meters and a height of 50 meters.  This  firm
has  supplied one circular based mechanical draft tower to a
U.S.  utility for plant no.'4210.*°°  Figure B-VII-61  shows
the  use  of  34  circular  mechanical draft towers with fan
diameter up to 21 meters and one natural draft cooling tower
of 115 meters height for units sized  between  100  and  300
megawatts at the Frimmersdorf plant.*o»

Mechanical draft cooling towers of circular base with forced
draft  fans  have  been supplied by the firm discussed above
for 5 powerplants.  The largest of these are 2 towers at the
Biblis plant where 105,000 metric tons per hour  of  cooling
water  is  circulated  in  each  tower.  The towers are 80.5
meters in diameter and 80 meters in height.*00

A novel cooling tower is being constructed  under  financing
of  the West German government.  This tower, shown in Figure
B-VII-62, consists of a center mast 575 feet tall,  with  an
upper ring 290 feet in diameter and a lower ring 490 feet in
diameter.   These  rings  are  connected by cables to give a
hyperbolic shape as shown, with a minimum  diameter  of  260
feet.    The network of cables will be covered with aluminum
panels to complete the tower.  It is hoped that this  method
of  construction will eliminate the size constraints imposed
by the present reinforced-concrete construction.  The  first
tower  is being designed and constructed by two large German
cooling tower firms, Balke-Durr and GEA,  working  together.
The  unit  will be at the Schmehausen station, cooling a 300
Mw unit, but will  be  designed  to  accommodate  a  500  Mw
unit.3««
                               550

-------
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         4    5    6    7    8     9    10   11



          TURBINE EXHAUST PRESSURE - INCHES Hg ABS
                                                              12    13   14
FIGURE B-VII-59 EFFECT OF TURBINE EXHAUST PRESSURE ON FUEL CONSUMPTION AND POWER OUTPUT


             (FROM REFERENCE 269)
                                         551

-------
                 1  Fan
                 2  Tower shell
                . 3  Central shaft concrete housing
                 4  Water distribution system and
                   drift eliminator
                 5  Cooling fill material
                 6  Vertical driving shaft
                 7  Dry chamber for mechanical
                   equipment
                 8  Drive gear with motor and
                   turbo coupling
Figure  B-VII-60   Section  Across a  Circular
                     Mechanical Draft  Cooling Tower
400
                         552

-------
Ul
LTI
L-J
                                                                                      Nr. 1B/BO/173J Met) -Pras Dusselciorl
                        Figure E-VII-61    Frimmersdorf  Power  Station
                                                                             401

-------
  \     /.  \ •.
.   V  v" \' "'•'
       "   '
               -  ^  ••" ^  x
               . . / -  - 'v /••: \/\ .'
.-•••  • i-  ••• •.   "',-.->
      Figure B-VII-62   Cable Tower
                         554

-------
Balcke-Durr  has  also  supplied  large  cooling towers with
noise suppression.  At Bewag's Lichterfelde plant in Berlin,
3 circular forced draft  towers  circulating  12,000  metric
tons  per hour (150 megawatts) each of water were built from
1972 to 1974.  Noise level guarantees were 60,  55,  and  50
db(A)  at  5 meters, respectively, for the first, second and
third towers constructed.   The  towers  are  35  meters  in
diameter  and 50 meters in height.  See Figure B-VTI-63.  At
Kkw's  Biblis  plant,   2   circular   forced-draft   towers
circulating  105,000  metric  tons  per hour each of cooling
water are planned for installation in 1975 to 1976.  A noise
level is guaranteed of 19 db(A) at 1,000 meters.  The towers
are 65 meters  in diameter and  80  meters  in  height.   At
Stadtw.*s  Duisburg  plant,  1  circular  forced-draft tower
circulating 48,000 metric tons per hour of cooling water  is
plannned  for  installation  in 1975/1976.  A noise level is
guaranteed of 25 db(A) at  500  meters.   The  tower  is  55
meters in diameter and 48 meters in height.

In  the  case of the Lichterfelde plant in Berlin, the noise
levels of the towers were based on a noise regulation  which
limited  noise  to  35  db(A)  at night at a distance of 130
meters from the plant.  This plant was constructed at a site
in close proximity to a high-density residential area.  Site
selection was limited by the unique territorial  constraints
of West Berlin.*o«
Survey of Existing Cooling Water Systems

The  FPC  Form 67 Summary Report for 1970 summarizes the use
of once-through cooling, cooling ponds, cooling towers,  and
combined  systems  by  number  of  plants  and  by installed
capacity (Table B-VII-3).  In 1970 about 23% of  the  plants
(1851)  of  installed capacity) used cooling ponds or towers.
Data submitted to the FPC by Regional  Reliability  Councils
indicates  that  cooling ponds or cooling towers are already
committed for over 50* of the total capacity of units to  be
installed  1974  through 1980.  See Table B-VII-4.  Table B-
VII-5 gives the total installed capacity, fossil-fueled  and
nuclear,  which is committed to cooling towers, supplemental
cooling, or once-through cooling,  for  plants  300  Mw  and
larger under construction as of April 1, 1974.

Site  visits were made to a number of steam electric genera-
ting plants.  One purpose of these  visits  was  to  observe
actual  operations  of  cooling water systems and to discuss
operating experiences  with  plant  personnel.   Design  and
operating  data  were  obtained  for these plants, including
basic   plant   information,   type   of   cooling   system,
                           555

-------
Figure B-VII-63   Cooling Tower with
                  Lichterfelde Plant
                       Control  at
556

-------
                                     Table B-VII-3


                        USES OF VARIOUS TYPES OF COOLING SYSTEMS       233
                                   Based on FPC Form 67 for 1969,  1970
Type of Cooling

Once-through, fresh
Once- through, saline
Cooling ponds
Cooling towers
Combined systems
Number
% t
1969
49.8
18.9
5.4
17.2
8.7
of Plants,
otal
1970
49.4
18.5
5.7
17.5
8.9
Installe
% 0
1969
50.5
23.5
5.9
10.9
9.2
d Capacity,
f total
1970
50.!
22.8
6.7
11.2
9.2
Ui

-------
                                     Table B-VII-4
                       EXTENT TO WHICH STEAM ELECTRIC POWERPLANTS ARE
                        ALREADY COMMITTED TO THE APPLICATION OF
                           THERMAL CONTROL TECHNOLOGIES  61
              CONTROL TECHNOLOGY
                                       ASSOCIATED GENERATING CAPACITY,  THOUS,  MW
                                            IN ACTUAL USE
                                               IN 1973
                                                      COMMITTED FOR UNITS INSTALLED
                                                           1974 THROUGH 1980
ui
Ul
00
No Control (Once-Through)
Controlled
   • Cooling Towers
   • Cooling Ponds
   • Combinations
Unknown
                                                  230
                                                  110
 60
130
                                                      50
                                                      30
                                                      30
    80
    40
    10
                                                                            30

-------
                                        Table B-VII-5
                COOLING  SYSTEMS  FOR PLANTS 300 Mw AND LARGER UNDER CONSTRUCTION
                                     (April 1,  1974)*
TYPE OF COOLING

Cooling Towers
Supplemental Cooling
Once-Through
Total
FOSSIL-FUELED
MW
46,276
6,466
56,334
109,076
NUCLEAR
Mw
30,428
8,518
52,587
91,533
TOTAL
Mw
76,704
14,984
108,921
200,609
% Total
38.3
7.5
54.2

Ul
Ul
VD
         * Source: May,  1972  FPC printout of utility responses to FPC Order No. 303-2

-------
quantitative  data  such  as  flow  rate,  temperatures, and
approximate cost data.

Plants visited were  chosen  to  result  in  a  spectrum  of
fossil-fueled  and  nuclear  units,  geographical locations,
sizes, and types of cooling systems.  Table B-VII-6 presents
a list of plants visited in the U.S. and the  basic  cooling
water  data  collected.   A few plants that were visited are
not included in this list as a result of incomplete data.

Many of these plants have  once-through  or  open  condenser
cooling  water systems.  Sources of cooling water for plants
visited  include  lakes,  wells,  rivers,   and   estuaries.
Generally,  the  water  in these plants is discharged at the
temperature at which  it  leaves  the  condenser.   However,
several  "helper"  systems were observed, where the water is
cooled before being returned to the source, using a  cooling
tower  or  other device.  One plant discharged cooling water
to a municipal water system.

Some of the plants that have been designed with or have used
once-through cooling systems are installing  closed  cooling
systems  as  a result of environmental regulations.  In most
instances, a small loss of plant capacity and efficiency has
resulted when this change has been made.

Other plants visited have  closed  condenser  cooling  water
systems,  where  the  cooling water is not discharged to the
receiving water, in order to avoid a thermal impact, but  is
recirculated utilizing cooling ponds and cooling towers.

A  number of plants use cooling ponds.  These may be artifi-
cially constructed lakes, or may be canal shaped.  If avail-
able land is limited, a smaller pond may be  constructed  by
utilizing spray modules.  Among the plants visited with con-
ventional cooling ponds, operation generally appeared satis-
factory,  and  as predicted.  Some plants using spray ponds,
however, seem  to  be  having  difficulties  in  maintaining
satisfactory operation with these units.

Cooling  towers  are  also  used  in  a  number of cases for
cooling the condenser cooling water in closed  recirculating
systems.  Both mechanical draft and natural draft wet towers
were  observed.   Natural  draft  towers  seem  to have been
specified in cases where there  was  concern  over  possible
fogging  effects  from mechanical draft towers.  Performance
of  plants  with  cooling  towers  appears  to   have   been
satisfactory in all cases.
                           560

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        Table  B-VII-   6




COOLING WATER SYSTEMS DATA



      PLANTS VISITED
Plant ID
Code Ho.
0640
Type Of
Fuel
NUCLEAR
Plant
Capacity Type
Mw
Hafjral
916 Draft
Coolinq
He idh t
Ft. Meters
425 129.5
Tower
Diameter
Ft. M
325 99.6

Water _,
BF of Pond
28
Cooliii'j Pond
Surface Area
Acres H* (10J )

or Like
Volume
Acre Ft. MJ(10J)


Ave rage
Time
Once -Throuql
Length of Pipe
Ft. M

System
Diameter of Pipe
Ft. M


Discharge
Type Comments

1201
1201

5105
2525

0801
1209

1209

2612

4217

4B46

3713

3626
1723

2512
3115

3117
2527

0610

2119
.OIL & GAS
OIL S GAS

OIL
OIL

COAL & GAS
COAL S GAS

NUCLEAR

' NUCLEAR
•I
COAL

COAL

COAL

COAL
NUCLEAR

OIL
OIL S, GAS

NUCLEAR
OIL

OIL 6 GAS

COAL
139.8
792

1386
1165

300
820

1456
Mechanical
700 Draft 62
Natural
1640 Draft 323

1150

2137

290
1618

542.5
644.7

457
28

750
Natural
2534 Draft 437

Artifical 1100 4460 9350 11556
Spray
Canal 7.35 29.8
SSnal 14'1 57'17 132 163"'5
Natural
Lakes 536.63 2176 11234.3 13885

Artif ical
Canal 3a60 15652 20,000 24719

18.89 48 14.63 30

98.45 247 75.28 28
Artif ical
Lake 2353 9541 50600 62541
Art if ical
Reservoir 32510 131830 1093600 135167
.Natural
Lake







Spray
Pond 2S 113.54 171 211.35

133.2 311 94.8 27.7
850 250 4 1.22 Gravity
100

6(Inlet) 1.828 9 mos.once thr
2 lO(Outlet) 3.048 wavity 3 mos .spr .canal

Gravity once through
units 162
canal will be
100 useunttsa|11 4
Length of tower
3300 1005 11 3.352 Gravity 650 ft.
two towers
are used





356 108.5 0.75 0.228 Gravity
Hultiple spr canal will
Ditruser Be installed
3619 1103 16 4.876 Systems to replace dlf
250(Inlet) 76.2 5.5IIN) 1.676 plujrietv SyS '
235(Outlet) 71.62 7.5(OUT) 2.28 OutTall

40(Inlet) 12.19 5.5UN) 1.676 Gravity Concrete
IS(OUT) 4.57 7.5(OUT) 2.28 Type Tunnel
80 24.38 4.5 1.51


3 such towers
for 3 Units

-------
Effluent Heat Reduction for Closed-Cycle Systems

The  effluent  heat  reduction  achievable  by  closed-cycle
evaporative cooling systems, as a fuction of the  cycles  of
concentration  is  given in Tables B-VII-7, 8, compared to a
once-through system and a helper tower system, respectively.
                            562

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                                                  Table  B-VII-7
              EFFECT OF  CYCLES OF CONCENTRATION  ON COOLING SYSTEM LOSSES, MAKEUP REQUIRED,
                                 REDUCTION IN EFFLUENT HEAT  Reference 389( 1,000 megawatt  unit)
Cycles of
Concentration
(a)
1.5
2.0
3.0
4oO
6.0
8.0
10.0
Evaporation
Rate, m /hour
n rate is 86,260 mVliv. ' Heat duty  is 3.81 bill I.on .RTU/lir and
             U-capei-rtUirc ranj;e is ll.l°C (20.0°F).
         (:>)  Ar,t;i.iir.j-.! hoai; t r
-------
                                    Table  B-VII-8

                                 liffcet of Cycles ol  Concentration
                                 on Heat IHscliarge Kate
                              From ;i 1,000 raw Power Station 389
Cycles of
Concent rat i on^a'
1.5
-i.U
3.0
4 . 0
d.il
8.0
10. 0
li 1 owdown
Rate, m3/hr(t>,c)
2460
1230
615
410
246
176
137
Heat Discharge for Temperature
Differences Between Receiving
and 1U owdown, million BTU/hr
AT=1°C AT=5°C £1=10° C
9.37 48.66 97.33
4.87 24.33 48.66
2.43 12.16 24.33
1.62 8.11 16.22
0.97 4.87 9.73
0.70 3.48 6.95
0.54 2.70 5.41
Percent Reduction Over
Helper Tower Assisted
Once-Through System* i: '
96.2
98.1
99.0
99.3
99.6
99.7
99.8
(a)   Power plant thermal  efficiency assumed to be 40 percent.   Heat duty
     is :).H1  billion IViT/hr and cooling tower temperature range is 11.1°C (20"F)
(h;   Assumed  lieal  transfer is  75 percent evaporative
(<•)   ni'/lir x  4.4 = gpm
(d)   Based on the  operation of  a 65,150 m3/hr  "helper tower"  in which warm water
     from the coiulenser(s) passes through the cooling tower and then directly  to
     a renei vi iij', body.
                                      564

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                           PART B

                     THERMAL DISCHARGES

                        SECTION VIII

         COST, ENERGY AND NON-WATER QUALITY ASPECT

Cost and Energy

The evaluation  of  the  additional  costs  to  be  assessed
against  the  power generated in a unit to which a helper or
closed cooling system has been added are of prime importance
to a utility.  This provides a basis for determining the re-
quired rate increases.  In addition, the capacity of a  unit
is reduced by the amount of power used in the cooling system
plus any penalties that iray be incurred by required shifting
of unit operating parameters, primarily, the increase in the
turbine  exhaust  pressure.   This  lost  capacity  must  be
replaced, either by new  capacity,  or  operation  of  other
units more intensively.

The  cost  of installation of cooling towers can be signifi-
cantly higher at sites with adverse local conditions.   Land
with  insufficient bearing strength would require piling, or
use of mechanical draft towers instead of natural draft,  or
both.    conversely,   in   hilly  terrain,  extensive,  and
expensive, excavation into  hard  rock  might  be  required.
Even  if only piping has to be excavated into rock, the cost
is  increased  significantly.   Reference  250  contains   a
detailed  study  of  tower  installations  at  such  a site.
Proximity of stations to earthquake faults means  additional
structural   strength  will  be  required,  particularly  in
natural-draft towers.  Towers in Florida and  the  Southeast
require  hurricane-resistant  design.   Other  factors  of a
specific local nature at other sites will increase the  cost
of installation of cooling towers.

Addition  of  a cooling system to an existing plant will re-
quire breaking into existing structures, piping or  tunnels.
Suitability  of  existing  structures used in the new system
will have to be evaluated.  Will  the  structures  withstand
the  new  pressures?   Will  it be easier to modify the con-
densers for increased pressures,  and  connect  directly  to
them,  or  should  the  cooling  system  be connected at the
present intake and outfall?  These are questions  that  must
be  answered  during  design  of  the  cooling  system.  The
current layout,  pump  size,  and  location  of  intake  and
outfall structures will influence the required decisions.
                             565

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The  plant or unit will be shut down during the final period
of installation when the new  system  is  connected  to  the
unit.   The  unit's  generating capacity is lost during this
period.  In some cases the connections can  be  made  during
the  annual  scheduled  overhaul.   In  other cases extended
downtime may be required, maybe as much  as  three  or  four
months.   Costs would vary accordingly.  The dollar value of
these costs will vary from plant to plant.

The economic  analysis  of  adding  a  supplemental  cooling
system  to an existing unit consists of evaluating the costs
of the following:

1.  Installing the cooling system

2.  Operating and maintenance costs of cooling systems

3.  Providing  additional  generation  capacity  to  replace
power used or capacity lost

4.  Operating and maintenance costs for replacement capacity

5.   Additional cost of generation of remaining power due to
a decrease in plant heat rate

Once these individual costs are determined, the  total  cost
for  the  addition  of a cooling system to an existing plant
can be developed.

There are a number of methods in  which  the  costs  can  be
evaluated.   These  methods  include  annual  costs, present
worth, and capitalized cost.

Probably the most popular  method  of  comparing  investment
alternatives  for  return  on  capital  is the present worth
method.  The result  of  this  type  of  analysis,  and  the
capitalized   cost  method,  is  a  dollar  value  for  each
alternative.

In this study, the  interest  is  primarily  in  incremental
costs,  i.e.,  how  many  mills/kwh  will  the addition of a
cooling system add to the cost of generation  of  each  fcwh?
Since  generation  costs are normally expressed in mills per
kilowatt hour, this was chosen as the  cost  basis  for  the
addition  of cooling systems.  This cost was developed using
the method of annual costs.  The additional  costs  for  the
year were totaled and divided by the power generated to give
an additional generation cost.
                                566

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The  capital  investment  involved  in the addition of a new
cooling system to a once-through plant can be split into two
parts.  The first is the installed cost of the tower and its
necessary auxiliaries.  These include new  pumps,  controls,
power  system,  motor starters, and modifications to the ex-
isting condenser and piping system.  The second part is  the
capital  cost  of the replacement generation capability.  It
is normally assumed that gas turbine units will be installed
to provide the power to replace that no longer available due
to installation of the cooling  system.   Once  these  costs
have  been  determined, the annual cost is determined by use
of the fixed charge  rate.   The  fixed  charge  rate  is  a
percentage, which when multiplied by the capital investment,
gives the annual expenses incurred for the capital invested.
Included  in  the  fixed  charge  rate  are interest on this
capital, depreciation or amortization, taxes, and insurance.
The actual fixed charge rates vary  for  each  utility,  but
generally   they   average  around  15%  for  investor-owned
utilities.   The  fixed  charge  rate   for   publicly-owned
utilities is normally several percent lower, with a 11% rate
corresponding to the 15% for the investor-owned utility.

Of  the  four  items  included in the fixed charge rate, in-
terest on  the  capital  and  depreciation  or  amortization
account  for  the largest portion of the total.  Interest on
the capital varies with the current cost of money.  Depreci-
ation or amortization rates depend primarily on the life  of
the  equipment  to be built.  An installation with a life of
25 years would be depreciated at U%, while  an  installation
with a life of 5 years would be depreciated at 20%.

When  the complete plant is built at the same time, one rate
is normally used to cover  the  entire  installation.   When
adding  a  cooling  system onto an existing unit, the period
over  which  the  cooling  system  is  depreciated  is   the
remaining  life  of  the  unit,  not the life of the cooling
system.  Whether the cooling system will  have  any  salvage
value when the unit is shut down depends on the location and
type  of  system used.  Obviously, if the cooling system can
be switched to another unit, it  will  have  salvage  value.
For  evaporative  type  towers, switching to another unit is
generally not possible, and the tower will therefore have no
salvage value.  It will usually be uneconomical to move  the
tower  due to the high construction costs involved.  Powered
spray modules will have salvage  value,  as  they  could  be
moved  to  other  sites.   If the cooling system will have a
salvage value when the unit  is  retired,  the  amount  upon
which  the depreciation is figured is the difference between
the installed cost and the salvage value.
                                567

-------
The operating and maintenance costs  for  a  cooling  system
include the incremental power required by the pumps and fans
(if  mechanical  draft  is  used),  maintenance  and  annual
overhaul labor and parts and associated overhead.  Both  the
pumps  and fans are low maintenance items, so the major cost
is the energy to operate  the  system.   One  cooling  tower
manufacturer  gives  a figure of about $200 per year per fan
cell as a tower maintenance  cost.   The  circulating  pumps
would  normally  be  overhauled  once a year, which is a two
week job en the average.

The amount of replacement generation  capacity  required  is
determined by adding the capacity penalty on the unit due to
increased turbine backpressures to the power required by the
cooling  system.  The unit capacity rating is normally given
for  a  stated  steam  inlet   condition   and   flow,   and
corresponding  turbine  exhaust  pressure.   If  the cooling
system can be added without  changing  the  turbine  exhaust
pressure, there is no backpressure penalty.  However, if the
turbine exhaust pressure is increased, which normally occurs
with  a closed cooling system, the output of the unit is de-
creased by up to several percent, depending on the  increase
in  turbine  backpressure.  Turbine manufacturers supply the
curves necessary to determine this decrease in capacity with
the turbine.  The backpressure cannot be  increased  without
limit,  without necessitating redesigns of the turbine.  For
current condensing turbines,  the  maximum  turbine  exhaust
pressures  are 17 to 18.5 kN/sq m(5.0 to 5.5 in. of Hg abs).
The limiting factor is the design of the last stages in  the
turbine.   Once the amount of replacement capacity is deter-
mined, its cost can be calculated.  If new capacity  is  in-
stalled,  it would be completely separate from the unit, and
would be depreciated independently of the unit for which the
capacity was required.

The operating cost of this replacement power must be charged
against the cooling system.  The total operating cost  would
depend  upon how many hours a year the additional generation
was required.  Throughout most of the  United  States,  peak
loads - come  during the summer months.  Thus the replacement
power would probably only be  required  during  the  summer.
The remainder of the year, the units with backfitted cooling
systems  should  be  capable of handling the demand, even at
the reduced capacity.  The annual operating hours for  which
replacement  power would be required and the associated cost
would depend on the particular utility involved.

Associated with any capacity penalty is an increase in  unit
heat  rate.   The  Joules  (Btu)  heat  input to the unit is
changed by adding the cooling  system,  but  less  power  is
                              568

-------
generated  due to the higher turbine exhaust pressure.  This
means that  more  Joules  (Btu)   are  being  used  per  Kwhr
generated.   Again,  by making use of the turbine curve, the
corresponding magnitude of the change in generation cost can
be determined.  Here again, the penalty will apply only part
of the year.  Only when the  climatic  conditions  are  such
that  the  design  turbine exhaust pressure is exceeded will
this increased  generation  cost  exist.   Furthermore,  the
operation of the fans in mechanical draft towers need not be
continuous  throughout  the  year.   Figure  B-VIII-1  is an
example of how the  net  power  output  of  a  unit  can  be
optimized by reducing fan power.  This is again dependent on
the specific unit in question.

Once  the  annual cos»ts for the above items have been deter-
mined, they can be totaled to give an annual  cost  for  the
addition  of  the  cooling  system  for the unit.  The total
generation expected to be delivered to the bus bar  is  then
determined,  and the additional generation cost due to addi-
tion of the cooling system can then be determined directly.

Cost Data - Plant Visits

Cost  data 'were  obtained  from  the  U.S.  steam  electric
generating  plants  which  were visited during the course of
this study. The utilities involved were very  helpful,  with
seventeen providing the requested information.

Nuclear  plants  and all three types of fossil-fueled plants
(coal, oil, and gas) were visited.  The size of  the  plants
visited  ranged  from 28 Mw to the largest in the country at
approximately 2,500 Mw.  One plant had a unit constructed in
192U.  In the remaining plants, all units  were  constructed
after 1952, with 12 plants being constructed after 1960.  Of
the  total  number of plants visited, 5 were nuclear.  Seven
of  the  plants  had  once-through  cooling   systems,   the
remaining  were  on, or in the process of installing, closed
or helper cooling systems.

The types of closed systems  involved  were  mechanical  and
natural  draft  cooling  towers,  spray canals, and man-made
cooling ponds.  One of  the  two  helper  systems  inspected
utilized  natural  draft  cooling  towers,  the  other spray
modules in the discharge canal.

Two types of information were requested, the first  involved
the  physical  description  of  the plant and its operation.
The second was concerned with the cost of the plant, and the
cooling system in  particular.   In  addition,  by  visiting
                             569

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                    100%
OPTIMUM COOLING
TOWER FAN
CAPACITY IN
SERVICE
                     50%
                                     WET BULB TEMPERATURE
                                Figure  B-VIII-1
         EXAMPLE  OF OPTIMIZATION OF NET UNIT POWER OUTPUT BY REDUCTION OF
                            COOLING TOWER FANS
                                               362

-------
plants  throughout  the country, a great deal of information
about regional problems and their solutions was collected.

A compilation of the cost data is shown in  Table  B-VIII-1.
Probably  the  most  important  feature of this table is the
great variation of costs involved.  The land for  plant  No.
5105,  a 1,157 Mw station, cost $172,000.  The land at plant
No. 0610, for a 750 Mw unit, cost $3,335,000, most of  which
was  for  a spray canal.  In the table, the unit cost ($/kw)
varies from a low of $68/kw to a high of $387/kw,  with  the
higher values being those for the nuclear plants.  The costs
also  vary  with  year of installation, with the older units
having lower costs.  The highest unit  cost  for  a  fossil-
fueled  plant  is  plant  No.  2527  at $155/Jcw, for a 28 Mw
plant.  Larger plants tend to have lower unit costs.   Plant
No. 2525 at 1,165 Mw and a unit cost of $142/kw, seems to be
an exception.

Operating  and maintenance cost data for cooling systems are
sketchy.  In general, operating and maintenance costs appear
to be a small  part  of  the  total  operating  cost  for  a
station.   In  only  one case was the reported operation and
maintenance cost of the cooling system greater  than  1%  of
the  capital  cost  of  the cooling system  (Plant no. 3626).
Energy required to operate the cooling systems, as reported,
was 2% or less of  the  rated  station  capacity.   Loss  in
capacity due to higher turbine exhaust pressures varied from
O.tt% to 2.5%.

Of  the  five plants reporting increases in heat rate, three
reported increases of 105 kJ/kwh  (100 Btu/kwh)(roughly IX of
gross plant heat rate) or greater,  fthen a specific plant is
considered for a cooling system other than once-through, the
plant cooling system design  is  normally  optimized.   This
means  some increase in turbine exhaust pressure, and conse-
quently higher circulating water temperatures.  This permits
use of smaller cooling towers, and the savings  realized  on
smaller towers more than offset the increase in costs due to
the  higher turbine exhaust pressure.  Thus part of the heat
rate increase is intentional, and results in  lower  overall
costs.

The  last  two  columns  of  the  table describe the-cooling
system currently in use or being installed  and  the  reason
for its installation.  Stations employing different types of
closed  cooling systems were included in the plants visited.
In the table, a lake is differentiated from a  cooling  pond
in that the lake in question was created by damming a stream
in  which  the  water  rights  did  not  belong to the power
                             571

-------
                                                  TABLE B-VIII-1
                                         COOLINC rfATER SYSTEMS - COST DATA
                                                  PLANTS VISITED
Plant Cost Data
ID
Olj.'.O
1201

1201

5105

2525

0801


1209

1209

2612

4217
u,
M 3713
3626

1723
2512
3115
•117
2527

U610
2119
Type of capacity
Fue 1 Mw
HUCLEAR
OIL & GAS

OIL & GAS

OIL

OIL

COrtL f. GAS


COAL & GAS

NUCLEAR

NUCLEAR

COAL

COAL
COAL

NUCLEAR

OIL & GAS
NUCLEAR
OIL

OIL & GAS
COAL
'1C
139.8

792

1157

1165

300


820

1486

700

1640

2137
290

1618

644.7
457
28

750
2534
Date of
Const.
:-,-is-7.:
1956T59

1969-72

1958-69

1961-69

1924-64


1964-67

1967-73

1966-70

1965-68

1962-70
1952-55

1966-72

1954
1967-73
1964-66

1968-72
1969
Land structure Equip.
(1000) (1000) (1000)
-
1960

1958 26000

172 8638

605 20915

408 5858



2213


2393 37735

3692 19502

781 30163
69.58 4609

1062 34833

844 13806
213 165480
45 1072

3335 4036
-
12130

85000

116255

138127

29288






106856

158783

174913
18511

110542
55283
71233

3283

97681
Co<
slino System Cost Energy Cost
•rotalCap- unit Date of Land StructureEquip. Total Cap-% of MPerating^ooiing
italcost Cost Const. , $ $ ital Cost plant ^ Main. System
Rcquiro-
$ (1000) g/fc,., (1000) (1000) (1000) 5(1000) Cost $(1000) Bents
355,
14,

112

125

159

35


59

252

146

181

205
23

146
63
85
165
4

105
003
090

,958

,065

,648

,554


,175

,381

,984

,977

,857
,190

,437
, 513
,883
,693
,400

,052
(1)
125,000
.1Q7 ly69-7L 111
88.06 1956-59

134.8 1969-72 1544

110.29 1970-71 109

142 1971-74

118.5 1924-64 (3)


68.5 1964-67 (3)

170.0 1971-74

210 1972-74

105 196S-68
(2)
102.9 11524
153.12 1952-55

118
117 1963-68 20
143
344
155

143 1971-72 2496
109 1969
13,021 205 11,337 3.76 - -
3i6 825 1,141 B.I 11

6,^50 4,045 11,939 10.6 13

I,o82 1,349 2,540 - -

8,000 .. 4Mrf

1,K20 261 2,081 7.04


1, 62 2,146 3,908 4.5 10

37,858

19,600 14Mrf

15,750 36
(2) (2) (2)
25, .17 16,243 53,284
.;58 585 844 3.67 48.5

23,~)00 16.0 28.5
;68 568 856 1.35
4818 8.03 4.632



6975 9471 9
8036 - - 12
IncreasedLoss of
Heat capacity
Rate TyP6 °* Cooling
jlCU/Kwn *^W System
Natural Draft W«t
Tower
Once Through Flow

89 6-8 Cooling Pond

Helper Spray Canal1
Helper Spray Canal
31 4 Closed Spray Canal
Cooling Ponds
(three)


Once Through Flow

vfhen Installed
in Station
Original Design
Original Design
1 unit
Oricinal Design
2 units
Backfitted to
neet stream stds
3 units
Bckfttd to meet
Str Stds launits )
Orig.Des.llunit}

Orininal Design
Or iainal Design
(to pe added tO
cooling canal)
Backfitted to
Cooling Canal close system
Mechanical Draft '
10o 9 "et Tower
Natural Draft Wet


Cooling Lake
Once Through Flow
Spray Canal
267 41.4 (in process)
Once Through Flow
(seawater)
Once Through Flow
Or.ce Through Flow
Once Through Flow

Spray Canal
Nat.Prf "-."flt Twr
Bckfttd to close
cooling system

Original Design

Oriyinal Design
Original Design
Bckfttd to close
cooling system
Original Design
Original Design
Original Design
Original Design
Change from once
throdtjh during
constr.
Bckfttd on 2 uniti
156 42 Hlpr&Closed Modes0^'008 • * unit
(1)   for Unit 3 only
(2)   Only fraction of this cost allocatable
     to station 3713, breakdown not given in date.
(3)   Not given included in plant cost

-------
company.  In a cooling pond the water rights belong  to  the
utility involved.

The  last  column  designates  whether  the  current cooling
system is the original design or has  been  backfitted.   Of
the twenty stations visited, six are backfitted.   Two of the
stations  visited  were  backfitting  for the second time to
meet increasingly stringent stream water quality  standards.
Several  of  the  plants backfitting with closed systems are
doing so as a result of legal action.  In  these  cases  the
trend  has  been to go to a closed system.  The necessity of
getting additional generating capacity "on line" has been an
important factor in determining the course of action taken.

It was evident from the visits that the spray canal with the
powered spray modules is used primarily as a  helper  system
to  cool  the  circulating  water  to meet stream standards.
This technology  is  relatively  new,  and  some  ancilliary
problems  remain to be solved before this technology becomes
sufficiently reliable for extensive utility use.

Cost Studies for Specific Plants

Preliminary studies ***, 46S have been completed to indicate
the feasibility, cost, and time required for construction of
facilities to bring Pacific Gas and Electric Company's  Moss
Landing  and  Pittsburgh  power  plants into compliance with
EPA*S proposed effluent guidelines and standards  for  steam
electric power plants (Federal Register March 4, 1974).  All
units  at  both  plants would have been required to retrofit
closed-cycle  cooling  systems  by  the  proposed   effluent
limitations on heat.

Generating units at Moss Landing are as follows:

Unit No.    Capacity. Mw    Utilization   Initial Service Year

    1           114           Peaking         1950
    2           113           Peaking         1950
    3           115           Peaking         1952
    4           122           Cyclic          1952
    5           122           Cyclic          1952
    6           750           Baseload        1968
    7           750           Baseload        1968

All units are fossil-fueled.

Conclusions  of the study are as follows.  It was shown that
wet mechanical  draft  saltwater  cooling  towers  could  be
retrofit  to  the  Moss  Landing  Power  Plant  without  the
                              573

-------
production of prohibitively high turbine  backpressures  for
most  of the anticipated operation.  It should be noted that
installation of  these  cooling  towers  would  require  the
acquisition of additional property.  The plant site property
currently owned by PG6E is not adequate for the placement of
the  cooling  towers  required.   The  area selected for the
installation of cooling towers is not  well  suited  to  the
existing  plant  because  of  the  length of the circulating
water lines.  This area is well suited, however, in terms of
its effect on plant  operation  because  the  cooling  tower
plume  would be carried away from the plant for most periods
of operation.  The increase in any  operating  cost  of  the
units  at  the  Moss Landing Power Plant would be consistent
with the increase normally associated with the. addition  of
cooling  towers.   The capital costs of these cooling towers
and the associated equipment are higher than  normal,  which
is   usually   the  case  with  retrofit  designs.   Special
considerations or design problems particular to  this  plant
(i.e.,  the  long  circulating  water lines required) induce
even higher capital costs.  The overall  capital  costs  are
estimated to be $28,186,000 at current prices (approximately
$14/kilowatt).    Allowance   for  engineering,  taxes,  and
interest  during  construction,  etc.,  and  providing   for
reasonable  contingency, increase these costs to $42,520,000
or $21/kilowatt.  One of  the  largest  cost  items  is  the
escalation,  for serious inflation can be anticipated during
the  intervening  years.   The  final  escalated  costs  are
$63,260,000 or $31/kilowatt.

Generating units at Pittsburg are as follows:


                                           Initial Service
Unit No.    Capacity, Mw    Utilization           Year

  1             160          Cyclic               1956
  2             170          Cyclic               1956
  3             160          Cyclic               1956
  4             170          Cyclic               1956
  5             330          Baseload             1961
  6             330          Baseload             1961
  7             740          Baseload             1966

All units are fossil-fueled.

Conclusions  of the study are as follows.  It has been shown
that wet mechanical draft cooling towers could be fitted  to
the   Pittsburg  Power  Plant  without  the  acquisition  of
additional land, and without the production of prohibitively
high turbine  backpressures  for  most  of  the  anticipated
                            574

-------
operation.   It should be noted, however, that the available
land is net well suited for towers because of  its  location
with  respect  to the plant and that no other suitable lands
are  available  because  of  other  facilities  and   nearby
residential  patterns.   The  annual  operating costs of the
units at the Pittsburg Power Plant would be increased  by  a
normal amount due to the addition of cooling towers, but the
capital  costs  of  these  cooling towers and the associated
equipment are abnormally high.   Higher-than-normal  capital
costs  are always associated with retrofit designs.  Special
considerations at this site,  such  as  the  length  of  the
circulating   water   lines,   result  in  capital  cost  of
approximately $32 million at current  prices  (approximately
$24/kw).    Allowance   for   engineering,  interest  during
construction, taxes, etc., and providing  for  a  reasonable
contingency  increase this cost to approximately $19 million
or $37/kw.  One of  the  largest  cost  items,  however,  is
escalation,  for serious inflation can be anticipated during
the intervening years.  The final escalated cost is over $75
million or $57/kw.

A number of problems were  encountered  in  the  layout  and
preliminary  design  of  the mechanical draft cooling system
for the Pittsburg Power Plant.   Basically,  most  of  these
problems  can  be  attributed  to  the  lack  of space at an
appropriate loaction for the layout of  the  cooling  towers
systems.  These problems include:

    •    Distance and routing of the circulating water lines
         to the cooling towers.

    •    Access to the existing pumphouse.

    •    Placement of the towers with  respect  to  downwind
         effects on the plant and switchyard.

    •    Placement  of  the  towers  with  respect  ot   the
         subsurface conditions encountered in the foundation
         design.

There  is  adequate  space on the property owned by PG&E for
the cooling towers required for Units 1-6, as  well  as  for
towers  for a proposed Unit 8 and for towers for replacement
of the spray canal of Unit  7  should  this  replacement  be
desired.   All  of  these  towers would fit in the available
area  with  sufficient  spacing  to  minimize   the   mutual
interference caused by placing such a large number of towers
in  one location.  The major problem is that this space is a
considerable distance from the plant itself, especially from
Dnits 1-6.  In addition, layout of  the  existing  equipment
                             575

-------
and  facilities  in  the  area  between  the  plant  and the
available space for locating the towers was made without any
allowance for the later  addition  of  closed-cycle  cooling
towers.   Thus, the routing of circulating water lines would
be extremely long, difficult to construct, and expensive.

When cooling towers are  retrofitted  to  existing  stations
based  on  once-through  cooling,  certain  difficulties are
normally  encountered.    Problems   associated   with   the
interface  between the existing circulating water system and
the new equipment  required  for  the  cooling  towers  vary
considerably  from  plant  to  plant.   In  the  case of the
Pittsburg Power  Plant,  access  to  the  circulating  water
pumphouse    has   proven   to   be   extremely   difficult.
Construction of offshore  diking  or  sheet  piling  jetties
might resolve this problem.  However, this study has assumed
that  such  construction  would  not be allowed.  Therefore,
construction of a new forebay behind the existing  pumphouse
would  be  required.   This  construction  would prove to be
extremely slow,  inefficient,  and  costly  because  of  the
difficulty in avoiding damage to the surrounding structures.
The  only  available  space  for the installation of cooling
towers on PG6E property at the Pittsburg Power Plant is near
the existing spray canal to the west  of  the  plant.   This
location  is  not  good  with  respect  to  the  power plant
operations because prevailing winds would  carry  the  tower
plume  back over the plant and switchyard during much of the
year.  Although damage  due  to  drift  is  expected  to  be
considerably  less  than  past  experience  because  of  the
improved performance of cooling tower drift eliminators, the
highly  humid  plume  in  the  transmission   corridor   and
switchyard  area  is  still  likely  to cause some operating
difficulties.  The space available for the cooling towers is
in an area of very poor soil condition and high groundwater.
The porous nature of the peat soil causes the water table to
be frequently at or near the surface.   Special  designs  to
prevent flotation and special designs for foundation in this
type  of  peat  material would be required, leading to extra
costs. **5

Sargent and  Lundy  **7  presented  a  summary  of  previous
estimates  they  had made of the cost of backfitting some of
their clients* units.  The summary, shown in Table B-VIII-2,
also describes the cost influencing items for each of the 13
plants covered.

A preliminary study 23Z has been  completed  to  assess  the
feasibility  of backfitting closed-cycle cooling system with
natural draft cooling towers at two TVA powerplants.   Plant
No. U704 has four units with a total capacity of 823 Mw, has
                              576

-------
                                                                        Table  B-VIII-2

                                                             Batiaatrt Coat* of Typical Installation* of Backflttlaf
                                                             ClOMd Cycla Coolln* Sy»t«M to One* Ttaw Cycle Plant*    447

                                                                (Eatiaatcd Coat* Arc Adjusted to Mid-1973 LercU)
STATJCW
-1
2
3
U
5
6
7
8
9
10
11
12
13
•0. OF
OBITS
b
2
b
b
b
2
b
1
2
b
b
3
2
TOTAL
m
i.tti
1,160
905
90b
630
b*
Itf
107
2.260
90S
901.
6b9
52b
TTfl
FURL
Co»l
CoU
Coal
Coal
Oil
Coal
Coal
Coal
•ttelaar
Coal
Coal
Coal
Coal
BO. A
TTfl
Towns
3-H.D.
3-H.D.
>«.D.
b-H.D.
Bybrld
2-M.D.
1-H.D.
i-H.r.
^Hybrid
1-*.D.
2-I.B.
1-B.D.
1-V.D. •
TOTAL tO.
COLS Oil
Dmxsion
27
27
JO
10
21)'B z b7$'Dla.
12
S
b
250-1 z 390'nu.
SOO'I z SOO'BU.
bSO'B z bSO'Bla.
370'B z bbO'Dla.
350'H z 350'W«.
sravm
FUN
900,000
916,000
720,000
JUS, ooo
(00,000
390,000
95,600
110,000
1.U53.000
720,000
914,000
570,000
376,000
.% Of
FUN TO
TOV^KS
66%
66%
loan
vx>H
66%
66%
66%
100%
100%
100%
100%
66%
66%
BACOTT
COST
*Aw
120.50
lib. 37
118.21
t3b.68
130.58
$17.78
131.90
137.62
$36.65
|2b.98
Ib9.f*\
118.09
•27.95
KSCRIPTIOII or COST ufuiPtuu rrots
CRIB BOOSE ALTEBATIOIS AID EADTB WORK FOB CUCTUTPS UA7E> tO
BTPASS PIPUC.
COST OF CIRCULATDC WATER PIPIK m COOLIBC VMOG OD EAE! TEX
Dl IXTAKE CBAJfflEL.
COPFERDAK, EARTH FILL, AID RIP UP SLOPES RNPIRED Di COOLm tM-X
AREA.
tmXWK COFFERDAM WORK AKD EAJTH FTU FOR CODING TWER AHEA
REQUIRED.
TOmXHC BELOW SAITTART D13TSICT SMX, CITT SEVER, AID iAUJtOAD
TUCKS.
COST OF CDtOIUTDC WATER PIPDC FOR COOLIBC TOWERS.
COST OP COOLDB TOWER IKSTALLATIOB FOR LOW GEIEUTIBC OOTPVT.
COST Or COOLDC TCUER DIS7ALUTIOH FOR C5LT 1 OTTT Or CEffiSATSIC
OOTFOT.
NODinCATIOH OF CIRCOLATIRG WATER ATO SEH7IC1 WATER STSTDS AROTOB
TEE PLAIT SITE.
COFFERDAM, EABTH FILL, ABD RIP KAP SLOPES BEQUBD IB COOLDB TOVER
AREA.
EXTUSHt COFFERDAM WORK AID EABTH PILL FOB COOLIBC TOWER ABU
REQUIRED.
TDKBELIBC BELOW CITT STREET IBTO BOCK STRATA ABD CORLKCTE LDB TBS
ROCK SURFACE.
COST OF CIRCULATDIC WATER TOBBELS ABD TEBTICAL SBAFTS.
U1

-------
a  capacity  factor  between  0.2  and 0.6, and will have 12
years useful service life after 1983.  Plant  No.  0112  has
eight  units  with  a  total capacity of 1978 Mw.  Units 1-6
have a capacity factor between 0.2 and  0.6,  and  a  useful
life  of  9 years after 1983.  Units 7 and 8 have a capacity
factor near 0.6 and a useful life of 29  years  after  1977.
The pertinent results of the study are as follows:

    1)  the conversions are feasible

    2)  cost for plant No. 4704 is $16,5 million;

    cost  for  units 1-6 of plant No. 0112 is $18.6 million;
and

    cost for units 7, 8 of plant No. 0112 is $15.0 million

    3)  scheduled plant outage for any of the  three  is  2-3
months

In  each case the cost of the towet including foundations is
about 40%  of  the  total  cost,  civil  work   (dikes,  pump
station, earthwork, etc.) about 40-50%, electrical work less
than  3%, and mechanical work (pump, piping, etc.) about 10-
15%.

Other Cost Estimates

Reference 385 collected estimates from other sources of  the
incremental  costs  of  various  alternative cooling systems
compared to once-through fresh water systems for new plants.
These cost  estimates  are  summarized  in  Tables  B-VIII-3
(fossil-fueled  plants) and B-VIII-4 (nuclear plants).  Also
given in Reference 385  are  estimates  of  the  incremental
costs  of  retrofit cooling systems for specific plants (See
Table B-VIII-5) and new cooling systems for specific  plants
(See Table B-VIII-6).

Reference  385  estimated  the effect of salinity on cooling
tower costs.  See Figure B-VTII-la.

Reference 389 collected data on the capital costs of cooling
ponds.   See Table B-VIII-7.  The cost of the cooling  system
as  a percentage of total plant cost varied from 1.35% for a
once-through system to 9% for a  spray  canal  system.   The
costs  depend a great deal on local conditions.  In addition
to varying land costs, foundation problems vary as  well  as
length  of  intake and discharge channels, etc.  Of the data
collected, costs for cooling systems averaged less than  10%
of the plant cost.
                              578

-------
                                                        Table B-VIIX-3

                                             COMPARATIVE COST  ESTIMATES  OF NEW NUCLEAR-FUELED
                                                  PLANT COOLING  SYSTEMS
                                                                         385
                                      (Cost Estimates  in Excess  of  Once-Through Fresh Water Systems)


Cooling .Pond
Spray Canal
Wet Towers
Mechanical Draft

Natural Draft
Dry Towers

Mechanical Draft

Natural Draft

Once-Through
Salt
Unit Capacity
**WOODSON
$ mills
kW kWh
3.4 0.07


4.7 0.10

10.6 0.22


31.0 0,96

61.4 1.57


800 MWe
**ORNL
$ mills
. kW kWh
5.6


0.02
11.9(a>
14.3
0.27


1.37
59.5*«>
71.4
1.57


Not Available
^ROSSIE
$ mills
kW kWh








25.8

"30.2


800 MWfi
JAMISON &
«.*ADKINS
$ mills
kW kWh
3.4-4.5


5.6-6.7

6.7-9.0


25.8 '
28.0-

30.2

600 MW
and larger
OLESON &
BOYLE
$ mills
kW kWh
0.11


0.22 (a)




0.90(a3




1132 MWfi
^BATTELLE
$ mills
kW kWh
5.9 0.17


7.0 0.37

12.8 0.43


24.1 0.95

37.3 1.10

6.6 0.14
1000 MWC
FRANKLIN
^INSTITUTE
$ mills $
kW kWh kW
6.3


6.9

9.5


25.2




1000 MWe
**FWQA
mills
kWh
0.02-0.07


0.10-0.17

0.17-0.26







000 MWe
,AAEC
$ mills
kW kWh







33.4- 0.87-
34.3 1.25
0.92-

42.2 1.32


860-928 MWe
(Jl
            Expressed in 1973 dollars.   The dollar base year
            for each study was inflated or deflated,  depending
            on the base year of the study, using a 67. per year
            inflation rate.

            Includes capability replacement costs.
         ^a'Costs for mechanical and natural draft

-------
                                                              Table B-VIII- 4

                                           COMPARATIVE  COST ESTIMATES OF. NEW FOSSIL-FUELED PLANT

                                                     COOuING  SYSTEMS*   385
                                       (Cost Estimates  in Excess of Once-Through Fresh Water Systems)


Cooling Pond

Spray Car.ui
Wet Towers

Mechanical Draft

Natural Draft
Dry Towers

Mechanical Draft

Natural D-aft
Unit Capacity
^WOODSON
$/KW mills /kWh

2.6 0.07



2.8 0.09

6.2 0.16

17.6 0.76

37.3 1.10
800 MWe
**ORNL
$/kW mills/kWh
3.6-
6.0



0.05
8.3
17.9
0.24

41.7- 1.13

59.5 1.42
Not Available
^OSSIE
$/kW mills/kWh





1.12x



19.0 1.12x+
0.54
22.4
eOO MWe
JAMISON &
**ADKINS
$/kW mills/kWh
2.2-
3.6


3.6-
6.0
4.5-
6.7
17.9-
19.0
20.2-
23.5
600 MW
on<4 1 a^»*kt»
FRANKLIN
^INSTITUTE
$/kW mills/kWh

_4_.4 	 _



3.8

5.7

20.2


1000 MW
**FWQ*
S/kW mills/kWh
1.9- 0.01-
3.0_ 0.05
3.8- 0.06-
ft.O 0.08
4.2- 0.10-
4.5 0.14
8.1- 0.17-
8.2 0.26
22.6- 0.55-
23.0 0.83
24.8- 0.51-
25.0 0.76
1000 MWe '
00
o
        (a)
Expressed in 1973 dollars.   The dollar base year
for each study was inflated or deflated,  depend-
ing on the base year of the study, using a 67. per
year inflation rate.

Includes capability replacement costs.

Costs for mechanical and natural draft towers.

-------
                                                                    Table  B-vril-5

                                              COST ESTIMATES OF RETROFITTED PLANT COOLING SYSTEMS FOR SPECIFIC
                                                            GENERATING STATIONS   385
                                          (Cost Estimates In Excess of Once-Through Cooling System-1973 Dollar Value)
Nuclear Fossil
Plant
San Onofre
01









Zlon 1 & 2








Quad-Cities
1 & 2







Dresden
2 & 3
Slze-MW
1-450


1-450

1-650

1-450
i
1-450

2-1100

2-1100

2-1100


2-1100

2-809
2-809

2-809

2-809

2-809

2-809

Cooling System
Evaluated
Dlffuser


Mechanical Draft Tower
Saltwater-Open Cycle
Mechanical Draft Tower
Saltwater-Closed Cycle
Mechanical Draft Tower.
Freshwater-Closed Cycle
Spray Pond Cooling
Saltwater-Open Cycle
High Velocity Jet Dlschg.
Off-Shore Intake
Round Mechanical Draft
Tower-Closed Cycle
Natural Draft Cooling
Tower-Closed Cycle

Dry Mechanical Draft
Cooling Tower-Closed
Cycle
Dlffuser
Spray Canal Cooling
Tower-Closed Cycle

Mechanical Draft Tower
Closed Cycle
Natural Draft Cooling
Tc..^r-Closed Cycle
Cooling Pond
Closed Cycle
Cooling Pond and Spray
System-Closed Cycle
Capacity
Factor
80*


80T.

sen

607.

em.

72%

111

721


721

72%
721

721

721

727.

72%

Cost
S/kW Imllls/ktfh5
15l


26l

391

100 l

44l

82

543

643

\
2083

6.3*
28*

26*

36*

30*

2i4

0.48


1.14

1.17

2.22

V.34

0.20

1.53

1.73


5.75

0.16
0.78

0.72

0.97

0.78

0.64

Plant
Jollet (Old)
Units 566







Jollet (New)
Units 7 & 8




Slze-MW
461


461

461

461

1,234

1,234

1,234

Cooling System
Evaluated
Natural Draft Cool-
Ing Towers-Closed
Cycle
Mechanical Draft
Towers-Closed Cycle
Cooling Pond
Closed Cycle
Spray Canal
Closed Cycle
Natural Draft Cool-
Ing Towers-Closed
Cycle
Mechanical Draft
Towers-Closed Cycle
Spray Canal
Closed Cycle
Capacity
Factor
351


357.

35%

351

55%

55%

55%

Cost
$/kW
304


214

7 16

604

23*

IS4

236

mllls/kWh'
l.SJ


1.36

4.67

3.82

0.81

0.64

0.81



NOTES :

1. Base Is considered as once-through single point ocean.
2. Base Is considered as once- through on shore Intake-discharge lake.
3. Base Is considered as once-through with high velocity Jet discharge
off shore Intake lake.
4. Base Is considered as once- through river.
5. Includes Investment, capability loss charges, and operating and
maintenance costs.








Ul
00

-------
                                                  Table B-VIII- 6


                              COST ESTIMATES OF NEW PLANT COOLING SYSTEMS FOR

                               SPECIFIC GENERATING STATIONS
385
                (Cost  Estimates in Excess of Once-Through Cooling Systems»-1973 Dollar Value)
?!ent
San Onofre,
2&3




Perry
1&2




Davis-Besse





Notes: 1 - Base Is (
Slze-MW
2-1140


2-1140

2-1140
2-1200

2-1200

2-1200

1-872

1-872



:onsldered as ocean-(deei
Coollnq System Evaluated
Mechanical Draft Cooling Towers - Saltwater
Closed Cycle

Mechanical Draft Cooling Towers - Salt Water
Open Cycle
Multi-Point Dlffusor
Natural Draft Cooling Towers - Fresh Water
Closed Cycle
Mechanical Draft Cooling Towers - Fresh Water
Closed Cycle
Spray Canal Cooling - Fresh Water
Closed Cycle
Natural Draft Cooling Towers - Fresh Water
Closed Cycle
Mechanical Draft Cooling Towers - Fresh Water
Open Cycle
Spray Canal Cooling - Fresh Water
Open Cycle
) Intake - deep discharge)
Capacity
Factor
80%


80%

80%
80%

80%

80%

80%

80%

80%

•
, Cost ...
$ mills
kW )c\Vh 3
231 0.75

i
32 1.01

6 0.17
11..32 0.2S

IS. I2 0.33

12. 72 0.58

25. 22 0.62

32. 82 0.81

1S.62 0.38


2 - Sase Is considered as once-through lake
3 - Includes Investment, capability losses, and operating •
and maintenance costs
01
00
to

-------
                                             O HEIGHT
                                             A DIAMETER
                                             O COST
               20
               SALT CONCENTRATION, (ports/million)x 10
                                                -3
F:;.gure  B-VIII-la  Salinity Effects pn  Cooling Tower
                   Size and Costs
                       583

-------
                                                       Table B-VIII-7

                                                Capital Costs of  Selected Cooling Ponds  (c)  389
PLANT
H. B. ROBINSON
ROXBORO (a>
BRAUNIG
KINCAID
MT. CREEK
NORTH LAKE
BALDWIN (a>
VALLEY
YT. STORM (a)
1970
CAPACITY
(MW)
906
1067
885
1319
99O
7O9
584 •
725
1140
SURFACE. AREA
( ACRES )(b)
2145
3750
1250
2400
2710
800

1000
1120
CAPITAL COST
OF COOLING POND ($)
4,800,000
4,831,000
4,717,000
3,819,000
4,333,000
3 , 555 , 000
3,000,000
918,209
6,523,000
UNIT COST
$/M»
5,298
4,528
5,330
2,895
4,377
5,014
5,137
.1,266
5,722
$/ACRE
2238
1288
.3774
1591
1599
4444

918
5824
COMMENTS
1971 Capacity








Ul
CO
        u    Future expansion at site contemplated.
        b    One  acre equals 4047m2.
        c    Covers land and land rights costs only.

-------
Based  on  the  FPC  Form 67 data for the year 1970 ««,. the
capital costs reported for once-through (fresh)  cooling  is
$4.03 per kw, once-through (saline)  is $4.63 per kw, cooling
ponds  is  $5.43 per kw, and cooling towers is $6/25 per kw.
The  incremental  cost  shown   of   cooling   towers  ' over
once-through systems is about $1.6 - $2.2 per kw.

Sargent and Lundy Engineers444 estimated costs of mechanical
and  natural  draft  cooling towers compared to once-through
cooling  for  new  plants  as  shown  in   Table'   B-VIII-8.
Incremental capital costs of mechanical draft cooling towers
over  the  cost  of  once-through  system  capital costs are
$3.09/kw for a 1150 Mw nuclear unit and $4.46/kw for  a  550
Mw fossil-fired unit based on 1974 dollars.

Reference   368   presents   nomographs   which  permit  the
estimation of cooling system.performance and costs.  » .

In general, it seems possible to distinguish three groups of
economic factors that could affect  the  relative  costs  of
open  and  closed  cycle  cooling  systems.  The first group
consists of the cost elements of  the  plant  cooling  water
system itself.  These include the intake structure, screens,
pumps,  piping,  condenser,  discharge facilities, and water
and wastewater treatment 'plant.

The second group of-cost factors concerns  itself  with  the
limitations  on  the  location  of  the plant imposed by the
once-through cooling system.  A once-through cooling  system
plant  must  be  located  at  or near the level of the water
supply.   This  frequently  results  in   high   costs   for
dewatering the site, and high foundation costs for piling or"
concrete  mats  to  protect  the  plant  against settlement,
flotation during periods of high groundwater,  or  flooding.
Even  if  a  site  has  already been committed, there may be
alternate locations, on  the  site  or  alternate  foundation
arrangements and floor elevations which are less costly than
those  dictated  by  the  limitations  imposed  by the orice-
trhough circulating water system.

The third group of cost factors apply only if the  site  has
not been selected, and generally only to coal-fueled plants.
These   relate  to  the  fact  that  it  is  generally  more
economical to transmit electricity than to ship coal and the
location of the source of the fuel has a greater  impact  on
economics  of  generating  electricity  than availability of
sufficient quantity  of  water  than  once-trhough  cooling.
There  are  also  cost  savings  which result from generally
better foundation  conditions  and  lower  requirements  for
architectural and other aesthetic aspects.  The magnitude of
                           585

-------
                         Table B-VIII-3
            Thermal Control Costs for New Plants
                                                 448
 Cooling System
Capital Cost, 1974 (exclusive of escalation,
allowance for funds used during construction,
or allowance for indirect costs
                             550  Mw
                          Fossil-Fired
                              1150  Mw
                              Nuclear
Once-through

Mechanical-draft
  cooling tower

Natural-draft
  cooling tower
     $2,646,000

      5,096,000


      8,047,000
$10,052,000

 13,599,000


 17,458,000
Incremental
  (mechanical draft
   less once-through)
     $2,450,000
     ($4.46/kw)
$ 3,547,000
 ($3.09/kw)
                            586

-------
•this  factor  may  be  approximated  by the cost of shipping
coal, which is of the order of $10 per ton for a haul of 250
miles.  This is equivalent to 0.5* per Ib. of  coal  or  per
kwh of electricity generated.
                               »
Costs Analyses

The  initial  part  of this work consisted of preparing cost
estimates for  placing  the  various  types  of  evaporative
cooling  in  a  number  of  hypothetical  plants  in various
representative locations in the United States.

Four typical plants were chosen:

    100 Mw fossil-fueled unit

    300 Mw fossil-fueled unit

    600 Mw fossil-fueled unit

    1,000 Mw nuclear-fueled unit

Two condenser temperature rises were  chosen,  6.7°C  (12°F)
and  11.1°C  (20°F).   These  represent  the lower and upper
design averages in plants currently operating in  the  once-
through  mode,  or  plants  that  would  be  considered  for
backfitting with closed cooling systems.  A turbine  exhaust
pressure  of 8.45 kN/sq m  (2.5 in. of Hg) abs. was chosen as
being an average of the units in this group.  This pressure,
plus the climatic conditions, permitted design of  a  closed
cooling system.

The  four  locations  chosen for this analysis were Seattle,
Washington  (cool), Phoenix, Arizona (hot and dry), Richmond,
Virginia (average), and Pensacola, Florida  (hot and  humid).
The  wet  bulb  temperatures used were those listed as being
equaled or exceeded only 5% of  the  time,  on  the  average
during  the  four months of June through September. **  This
amounts to 110 hours for this period.

The necessary information was  submitted  to  three  cooling
tower   manufacturers   and   two   powered   spray   module
manufacturers for cost estimates.  These conditions  assumed
100%  heat  removal  in  the  tower  and  no  change  to the
generating unit, i.e., cooling  water  temperature  was  the
same.  Of the total of 32 separate plants resulting from the
matrix  of  conditions,  20 were capable of being backfitted
with mechanical draft cooling towers, and  16  with  natural
draft  cooling  towers.   Use  of  natural  draft  towers in
Phoenix were not practical due to low humidity.
                             587

-------
One powered spray module manufacturer proposed  systems  for
28  of  the 32 cases, while the other proposed for 16 of the
32 cases.  The costs of the equipment only is shown in Table
B-VIII-9.  The mechanical draft tower  (wood  construction) ,
and the natural draft tower (concrete construction), are the
two  types  of  cooling  towers  most  widely  used  in this
industry.   These  are  considered   available   technology.
Powered  spray  modules  are  being  used for backfitting to
reduce  circulating  water  temperatures  to   meet   stream
standards.   As such, they are available technology.  At one
major plant the powered spray modules are being installed in
a closed system.

Table B-VIII-9 illustrates a number of points.  The first is
that under the conditions specified, natural  draft  cooling
towers are considerably more expensive to buy than the other
types. .This is particularly true for smaller plant sizes in
which  the  natural  draft tower would not be expected to be
competitive.  However, operating costs are less, which makes
their overall cost lower than the tower cost would  seem  to
indicate.   For  mechanical  draft  towers,  it appears that
concrete construction is  more  expensive  than  wood  by  a
factor  of  l.U.   The cost of all the systems, exclusive of
the  natural  draft  tower  is  about  the  same.   Thus  if
mechanical  tcwers  are  used as a technology to investigate
the costs of their application, use  of  the  other  systems
would  result  in  similar  costs.   This leaves a number of
options open to utilities for about  the  same  cost.   Each
plant  would  have to be evaluated on an individual basis to
determine the  most  economical  system  for  that  station.
Cooling  pcnds were not covered in detail since their use is
not dependent upon equipment  supplied  by  a  manufacturer.
Their  cost is almost entirely composed of land cost and the
cost of the retrofit.  This option is available for use  and
considered  as  a  lower cost available technology for those
plants where suitable land is available.

For the overall costs' analysis,  the  additional  cost  (in
mills/kwh) to install and operate a mechanical draft cooling
tower  as a function of the percent of heat removed from the
circulating water is generally representative of the overall
cost  of  the  application  of   effluent   heat   reduction
technology,   due  to  general  similarity  of  costs  among
available technologies.  Due to the broad spectrum  of  unit
sizes  and  conditions  throughout  the  United  States, the
number of cases  studied  had  to  be  strictly  limited  to
provide   a   manageable  number  of  analyses.   The  first
restrictions were made on the basis of the categorization of
the industry.  Fossil-fueled plants only were considered, as
these make up the bulk of existing  facilities  at  present.
                             588

-------
         TABLE B-VIII- 9




COST OF COOLING SYSTEM EQUIPMENT
Unit
Size
(MW)

100



.



300







600







1000






	
Unit
Location

Seattle

Phoenix

Richmond

Pensacola

Seattle

Phoenix

Richmond

Pensacola

Seattle

Phoenix

Richmond

Pensacola

Seattle

Phoenix

Richmond

Pensacola

Circulating
Water Rise (F)

12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20
12
20

Mech. Draft
Wood Constr .
.400
.459
.612

.567

.728

1.050
1.195
1.768

1.640

2.025

1.815
2.154
3.102

2.648

3.497

4.275
4.840
7.281

6.765

8.337

Cost For Systam (.$ x 10 ~
. Mech. Draft
Concrete Contr.
Mfr. A (Mfr. B
.550 •
.648 ' .650
.857 : .825

.798 ' 0.800

1.019 i 0.955

1.442
1.665 • 1.490
2.478 • 2.232

2.300 ' 2.010

2.835 • 2.530

2.491
'3.014 . 2.640
4.332 > 3.825

3.705 ; 3.525

4.897 ; 4.470

5.867
6.780 ' 6.000
10.191 9.050

9.465 ! 8.250

11.677 9.900

Natural
Draft
2.5
2.8
*

4.1

4.3

3.9
4.7


8.0

8.3

5.5
6.8


14.6

15.1

10.1
14.7


30.8

31.9

&•)
Powered Spray
Module
Mfr. A
.380
.532
.684
1.596
.684
1.293
.836

1.064
1.293
1.824
4.180
1.748
3.345
2.05

1.748
2.200
3.118
7.22
2.965
5.700
3.57

4.180
4.940
7-. 3 80
16.040
6.920
12.700
8.51

Mfr. B
.364
.401
.765

.656



.875
1.130
1.933

1.695



1.531
1.763
3.390

2.984



3.255
3.933
8.070

6.984



             589

-------
The next break came on the basis of unit use.  A statistical
analysis  of the plants reporting to FPC on Form 67 resulted
in the statistics shown in Table B-VTII-10.  Based on  these
figures,  the  figures shown in Table B-VIII-11 were used in
the analysis.  The only adjustment, other than rounding off,
were made in the heat rate.  These heat rates are  based  on
total fuel burned and total kwh's generated during the year.
Since  by  definition  a  base  unit is operating at or near
capacity  most  of  the  year,  this  heat  rate  is  fairly
representative  of  the  actual heat rate while operating at
near full capacity.  The same is not true of the  other  two
cases.  The cyclic unit, operates for longer periods of time
at  lower  loads,  where efficiency is lower.  This unit may
act as spinning or standby reserve where the boiler is up to
pressure, but little power is  being  generated.   Thus  the
heat  rate  is  higher  than that actually existing when the
plant is operating at near  full  capacity,  the  heat  rate
desired  for  this  analysis.  The cyclic unit heat rate was
reduced to 12,000 kJ/kwh (11,500 Btu/kwh), considered to  be
more truly representative of the actual unit heat rate.  The
same  factors  influence  the heat rate of the peaking unit,
even to a greater degree.  The heat rate  of  peaking  units
was  reduced  to  13,200  kJ/kwh (12,500 Btu/kwh) as being a
more realistic figure.  Mote that when a unit is being  held
in  a warm standby condition it is normally not connected to
the circulating water system.  Thus, most of  the  increased
heat  is  discharged  to  the stack and not to the receiving
water.  Since the purpose of the analysis was  to  determine
the range of costs involved in installing wet cooling towers
on  existing  units, three wet bulb temperatures were chosen
as the worst, near average and best wet  bulb  temperatures,
for  cooling  tower  design  purposes, in the United States.
The worst, or highest wet bulb temperature was 28°C  (83°F).
This  was  at the IX level, exceeded only one percent of the
time during June through September.  An average  chosen  was
2H°C   (75°F), and the lowest summer wet bulb at the 1% level
was 1U0C  (57°F).

The remaining factor was unit age, and this was  taken  into
consideration  as  unit remaining life, assuming a unit life
of 36 years.  The median ages of the three  age  categories,
6,  Id,  and  30 years, were used.  This gives a total of 27
cases, 3 types of units multiplied by 3  wet  bulb  tempera-
tures multiplied by 3 ages.

Some  additional  information on the unit must be specified.
The plant size chosen was 300 Mw. By using a  300  Mw  unit,
some  idea  of  the  magnitude of the various costs could be
made.  Since parameters and costs used varied linearly  with
unit  size,  the  costs,  in terms of mills/per kwh, will be
                             590

-------
            TABLE B-VIII- 10
HYPOTHETICAL PLANT OPERATING PARAMETERS
Type
of Unit
Base
Cyclic
Peaking
Hours Up
per Year
7685
4475
1155
Heat Rate
kJ/kwh
11,231
13,192
16,677
Btu/kwh
10,636
12,493
15,793
Capacity
Factor
0.77
0.44
0.09
Bus Bar Cost
miUsVkwh
6.24
8.35
12.50
            TABLE B-VIII-11
   REVISED PLANT OPERATION PARAMETERS
Type
of Unit
Base
Cyclic
Peaking
Hours Up
per Year
7690
4500
1200
Heat Rate
kJ/kwh
11,088
12,144
13,200
Btn/kwh
10,500
11,500
12,500
Capacity
Factor
0.77
0 . 4<
0.09
Bus Bar Cost
mills /kwh
6.34
8.35
12.50
                591

-------
applicable to any unit for which the basic  assumptions  are
valid   and  operating  parameters  fall  within  the  range
indicated.  It was further assumed  that  operation  of  the
unit  at a turbine exhaust pressure of 8.45 kN/sq m (2,5 in.
of Hg abs) would incur no operating penalty other  than  the
power  requirements of the tower and pumps.  Any increase in
pressure above this  would  result  in  both  an  additional
capacity penalty and a fuel penalty.

A  circulating  water  temperature rise of 16.7°C (30°F) was
chosen as being the highest to be found in the  units  being
considered  for  backfitting.   Due  to  the restrictions on
approach and cold water temperature to the  condenser,  this
is  the  most  restrictive  set  of temperature criteria for
tower design.  The other extreme of circulating  water  rise
is about 6.7°C (12°F).  For the same size plant, the cooling
water  flow would be increased by a factor of 2.5.  This has
a significant effect on  tower  cost,  but  the  temperature
criteria  are  much less restrictive.  This permits, as will
be explained later, modification of the  cooling  system  to
significantly  reduce  the  cost  for  the case with a 6.7°C
(12°F) temperature rise.


Two additional parameters  were  chosen,  the  first  was  a
terminal  temperature  difference  of  5.5°C  (10°F)  in the
condenser.  The second was to establish 6.7°C (12°F) as  the
minimum approach to be used in tower design.  This value was
determined    through   conferences   with   cooling   tower
manufacturers.

The above plant characteristics are summarized in  table  B-
VII-12.

A  number of additional assumptions related to the economics
of the utility  industry  were  necessary  to  complete  the
analysis.   Since  the  pumps  required  to  circulate water
through the cooling tower are not included in  the  cost  of
the  tower,  these were priced using a total dynamic head of
24 meters  (80») , of this 24 meters  (80»),  18  meters   (60«)
was  required in the tower, and the remaining 6 meters  (20')
was for pipe losses and  additional  lift  required.   Since
most  once-through  condensers make use of the siphon effect
to lower pumping requirements, the original  pumps  are  low
head,  and  would not be suitable for cooling tower service.
There are a number of ways in which the cooling tower  could
be  connected,  but  all include new pumps, either to handle
the entire system or to be placed  in  series  with  current
pumps.   The cost of the pumps was estimated at $100/hp, and
an overall pump-motor efficiency of 80%  was  assumed.   The
                              592

-------
                 TABLE B-VIII- 12
          TYPICAL PLANT CHARACTERISTICS
Unit Size - 300 Mw
Unit Types - Base, Cyclic, and Peaking
Wet Bulb Temperatures - 83°F, 75°F, 57°F
Median Remaining Unit Life - 6, 18, and 30 years
Circulating Water Rise - 30°F  (Upper Limit)
Condenser TTD - 10°F
Cooling Tower Approach - 12°F minimum
                       593

-------
cost  of  connecting  the  cooling  tower  into the existing
circulating water system is site dependent and is  therefore
extremely  variable.  Factors that influence the cost of the
tower installation include the relative locations  of  tower
and  plant, the type of terrain and soil conditions, and the
site, type and locations of connections that must be  broken
into.    Indirect   costs   for   engineering,   legal,  and
contingencies must also be included.

Table B-VIII-1 shows the  cost  of  installing  the  cooling
systems at the plants visited during the study.  The average
value   for   retrofitted   closed   cooling   systems   was
approximately $17/kw.  For a 300 Mw unit,  this  amounts  to
approximately  $5  million  for  the  complete  installation
including tower, pumps,  installation  and  indirect  costs.
The  cost of the tower and pumps alone for this installation
would be approximately $1.25 million.  Therefore, the  tptal
installed  cost  is  approximately  400%  of the cost of the
major equipment involved.  The basis for  this  estimate  of
the  costs of tower and pumps was a base-load unit installed
at a location where the  design  wet  bulb  temperature  was
75°F.   The  cost  will vary for other wet bulb temperatures
with a range of about $13/kw to $25/kw.

For the purposes of the economic analysis a  markup  of  300
percent above the the base cost of the major equipment items
was  allowed  to  cover  the installation costs and indirect
costs mentioned above.  This allowance is considered  to  be
conservative for most cases.

To  determine  the  tower  costs,  the  cost  information on
mechanical draft towers from  Table  E-VIII-9  was  used  to
develop  a  linear relationship between the tower parameters
(approach, range, flow, and wet bulb) and cost.   The  vari-
ation  in  cost was less than 5% at the 28°C  (75°F) wet bulb
temperatures, and averaged less than 15X for the 1U°C  (57°F)
wet bulb temperature.  Land cost was  not  included  in  the
tower  capital  cost  due  to  wide variation throughout the
country.

Fan power requirements were also  determined  in  a  similar
manner, with less than 10% variation.  The operating cost of
the  towers  was  assumed  to  be  primarily the cost of the
electricity to run the fans and pumps, and  was  charged  at
the average rate for the particular type of unit,  except in
the  case  of  the  peaking  unit.  In this case the average
power cost was 2.5 mills/kwh higher than the operating  cost
of  replacement  gas  turbines,  assumed to be 10 mills/kwh.
Thus in this case, it was assumed that the power required to
operate the tower cost 10 mills/kwh.   Ten  percent  of  the
                            594

-------
operating  cost  of  the  fans  and pumps was added to cover
maintenance and parts for this equipment.

Since there were three remaining life spans considered,  and
since  the  tower had essentially no salvage value, the cost
of the tower had to be absorbed during the  remaining  plant
life.   To  account  for this, three fixed charge rates were
used, one for each of the  three  remaining  life  spans  as
follows: 6 years - 30X, 18 years - 19X, and 30 years - 15X.

These are rates for investor-owned utilities; public utility
rates would be lower.

It was assumed that the energy required by the cooling tower
system  was  replaced with energy produced by a gas turbine.
In addition, any capability loss due to operation at  higher
turbine  exhaust  pressures  was  replaced  with gas turbine
generating capacity.  It was assumed that the installed cost
of these gas turbines  was  $90/kw.   1970  costs  are  used
throughout this analysis.  Since the life of these units was
independent  of  the unit whose power they were replacing, a
30 year life was assumed  and  the  fixed  charge  rate  was
accordingly  15%.   If base load capacity were used in place
of turbines to replace the capability loss, the annual costs
of replacement capacity would be less.

Any increase in turbine exhaust pressure results in a higher
heat rate, and consequently a higher generation  cost.   The
following  changes  in  heat  rate  were assumed.  They were
taken from a typical curve for a turbine with initial  steam
conditions  in  the superheat region.  Values used are shown
in Table B-VIII-13.

This increase in generating cost was based  on  the  average
generating  cost  for  the  type  of  unit being considered.
These factors and assumptions are  summarized  in  Table  B-
VIII-14.

Several  additional assumptions were made about each type of
unit, base, cyclic, and peaking.   These  were  mainly  con-
cerned  with  the  number  of  hours  the  gas turbine would
operate and the fuel penalty that would be assessed.   Since
the  peak  load normally comes in the summer months and this
period  is  the  critical  one  for  tower  operation,   the
penalties  normally  apply during this period.  For the base
units,  it  was  assumed  that  they  would  operate   under
penalties  equivalent  to  full  penalty for one half of the
average number of hours per year.  Cyclic units were assumed
to operate under full penalties for 2,000  hours  per  year.
Since  peaking  units  average 1,800 hours per the penalties
                             595

-------
                     Table B-VIII- 13
ASSUMED INCREASE IN HEAT RATE COMPARED TO BASE HEAT RATE AS A FUNCTION
                  OF THE TURBINE  EXHAUST PRESSURE





Ul
vr>

Turbine Exhaust Pressure, in. Hg
2.5
3.0
3.5
4.0
4.5
5.0
5.5
Increase in Heat Rate, % of base
Base
0.4
0.8
1.4
2.0
2.8
3.6
>

-------
                                     Table B-VIII-
                                   COST ASSUMPTIONS
Ul
vo
Pumps  required  for  tower

Tower  cost
Fan power
Pump power
Fan and pump  operating  cost

-Fixed  charge  rates
  6 yr remaining  life
  18 yr remaining life
  30 yr remaining life
Replacement power

Replacement power fixed charge rate
Fuel penalty
$100/HP @ 80 ft of head,
80% overall efficiency
Interpolation from Table B-VIII-2
Interpolation from Table B-VIII-2
80 ft of head, 80% efficiency
Electrical energy at average for type
of unit, plus 20% for maintenance

30%
19%
15%
Combustion gas turbines @ 90$/ kw
and 10 mills/kwh
15%
Assessed at cost of generation for type
of unit considered except for peaking
units, where cost is 10 mills/ kwh

-------
would apply during the full 1,800 hours of operation.  These
values are considered  near  the  maximum,  and  the  actual
values  will  vary from unit to unit.  Shut down of the unit
is required during the time required to connect the  cooling
tower  into the existing circulating water system.  The time
required to make this connection will depend on  the  layout
and  accessibility  of  the  existing  cooling  water system
compments.  It  is  estimated  that  the  time  required  to
perform this work will vary from 2 to 5 months, depending on
these  conditions,  with  an  average time of 3 months.  One
month of this  requirement  can  normally  be  scheduled  to
coincide with the annual maintenance period when the unit is
down  in  any  case.   Therefore,  additional  cost  will be
incurred to supply the power normally generated by the  unit
for  a  period  of  two  months.  It is further assumed that
shutdowns to allow these modifications to  be  made  can  be
scheduled  to  coincide  with  periods of low system demand.
Therefore, replacement  power  can  be  obtained  by  higher
utilization  of other equipment in the system rather than by
wholesale import of power from other sources.


It may not be possible to  have  the  tie-in  coincide  with
scheduled  maintenance  outages  in  some  cases.   In  some
instances several units at a site may of necessity be  taken
out of service concurrently to accomplish the tie-ins.**3

Replacement  power  for  base-land  units  undergoing  these
modificiations will be supplied by operating  cycling  units
more  intensively.   The  utilities  will  incur  additional
operating costs  because  these  units  are  typically  less
efficient than the base-loaded units.  A differential energy
cost  of 3 mills/kwh was assumed to be representative of the
increased operating costs of  these  types  of  units.   The
total costs associated with loss of the unit was obtained by
multiplying  the capacity of the unit by the number of hours
affected,  the  units  annual  capacity   factor   and   the
differential  operating  cost.  The decreased utilization of
cycling and peaking units will generally allow  them  to  be
modified  without  incurring  downtime  costs as high as the
base-load units.  However for the purposes of consistancy of
the analysis, similar penalties were assessed against  these
units as well.

In order to extend this cost to the remaining units of power
production,  the  total  cost  was  considered  to  be money
borrowed at an annual interest rate of 8* compounded.   This
loan  was  then assumed to be repaid over the remaining life
of the unit and the annual costs obtained were  spread  over
the average annual generation.
                             598

-------
A  sample  calculation for a peaking tin it with a 2U°C (75°F)
wet bulb design temperature, is shown  in  Table  B-VIII-15.
The procedure was to assume 8.45 kN/sq m (2.5 in. of Hg abs)
turbine  exhaust  pressure  with  its corresponding 99?F hot
water temperature.  With a minimum approach of 6.7°C (12°F),
the maximum range of  the  tower  is  6.7°C   (12°F)  or  the
percentage of heat removed is 12/30 or 40%.  Using a minimum
range  at  5.5°C  (10°F) the % of water flow through a tower
for heat removals below 40% were  determined.   The  turbine
exhaust pressure was then increased to 10.1 kN/sq m (3.0 in.
of  Hg  abs),  the maximum heat removal determined  (60%) and
conditions  for  removal  of  from  H0%   to   6OX   removal
determined.   The same procedure was used at 11.8, 13.5, and
15.2 kN/sq m  (3.5, U.O, and U.5 in. of Hg  abs)  until  100%
removal  was  obtained.   The  analysis then proceeded in an
orderly fashion as shown in Table B-VIII-15.  The  other  26
cases were treated in a similar manner, and the result was a
set  of  nine graphs showing the range of additional genera-
tion costs involved in backfitting the hypothetical  300  Mw
unit  with  mechanical  draft  cooling  towers.   Since  all
factors  were  linear  with  size,  these  costs   will   be
applicable  to any size plant in which the basic assumptions
are still  applicable.   Conversations  with  cooling  tower
manufacturers indicate that for mechanical draft towers only
a  small variation in cost would be expected in the range of
units involved, including a 1  Mw  plant.   Pump  costs  may
increase in the smaller size units.

The  first  three graphs. Figures B-VIII-l, B-VIII-3, and B-
VIII-4, cover base-load units.  Additional generation  costs
ranged  from  a low of 0.60 mills/kwh at a 13.9°C  (57°F) wet
bulb temperature and 30 year remaining life  to  a  high  of
0.65  mills/kwh  at a 28.3°C wet bulb temperature and 6 year
remaining life.  These are for  100X   (actually  about  98%)
heat  removal.  As indicated on the graphs, it was necessary
to increase  turbine  exhaust  pressure  in  every  case  to
achieve  100%  heat removal within the limitations placed on
the hypothetical unit.  At an  average  generation  cost  of
6.24   mills/kwh,   the  maximum  additional  cost  of  1.10
mills/kwh is an increase of about 17%, with the minimum  for
100% heat removal of about 10%.

To   evaluate  the  effect  of  circulating  water  rise  on
additional generation cost, additional  calculations  for  a
6.7°C   (12°F)  circulating  water  rise were made for the 30
year and 18 year  remaining  life  categories  at  a  23.9°C
(75°F)   wet   bulb  temperature.   The  6.7°C   (12°F)  rise
approximates the lowest value found in current plants.   The
results are shown in Figures B-VIII-5 and B-VIII-6.  At heat
removal fractions above 50%, costs are significantly higher.
                             599

-------
                                                                                                        TABLB B-VIII. 15
                                                                                               COOLING TOUER ECONOMIC ANALYSIS
                                                                                   (300 Mwe Unit, Making Service, <*at Bulb Twaperature 75°D
Turbine
Exhaust
Pressure
•P' figifa
 Percent  Percent    Tower   Tower     Tower   Pusq>      Total
 o* Ueat  of Mater   R«nge  Approach   Cost    Cost      plus    « Year
^*gr*l_thr¥TtlT*g  fo'     <°r)        »       s	2Si    mf
                 Annual    Annual   Total
               _?anOper-  Puap ^par-plus 10%   Fan
18 Year  30 Year  ing Cos*,  ing iost for Main.  Power
                                                                      Annual  Coat
                                                                                                                                                                                                         generating
                         Capital    Annual            puel    Aflg^
Pump   Capacity   Total  Cost of    Cost   Operating Penalty  6 Year   18 Year
Power   9*n*Lty  Penalty Gas Turbine  15%     Cost      Cost   Attaining
      30 Year
ining Ramaining
              40       100      12       12      760,700 354,200 1,393,600  416,100  2&'.,aOO  20'j.OOO   8,500  31,700   44,200

              30        90      10       14      531,200 318,800 1,062,500  316,800  201,900  159,400   6,000  28,600   38,100

              20        60      10       14      354,400 212,500    7O8.6OO  212.600  134,600  106,300   4,000  19.0CO   25,300

              10        30      10       14      176,600 106,300    353,800  106,100   67,200   53.100   2,000   9,500   12,6OO

              60       1OO      IB       12    1,067,300 354.200 1,776,900  533,100  337,600  266,500  12,000  31,7rQ   48,000

              SO       1OO      15       IS      749,400 354,200 1,379,500  413,800  262,100  207,000   8,400  31,700   44,100

              40        95      13       17      561,200 336,500 1,122,100  336,600  213,200  166,300   6,200  31,700   41,700

              77       100  ,    23       12    |1,214,90Q 354,20O [1,961,400,  588,400  372,700  294,200  13,700, 31,700  I 49,900  .

              70       100  '    21       14      965,100 354,200 1,649,100  494,700  313,300  247,400  10,BOO  31,700   46,600

              60       100      18       17      760,700 354,200 1,393,600  416,100  264,800  209,000   8,500  31,700   44,200

              93       100      28       12    1,351,100 354,200 2,131,600  639,500  405,000  319,700  15,100  31,700   51,500

              90       100      27       13    1,203,500 354,200 1,947,100  584,100  369,900  292,100  13,600  31,700   49,800

              80       100      24       16      931,000 354,200 1,606,500  482,000  305,200  241,000  10,400  31,700   46,400

              70       100      22       18      772,100 354,200 1,707,900  422,400  267,500  211,200   8,600  31,/uU   44,400

             1OO       1OO      30       15    1,112,700 354,200 1,833.600  550,100  348,400  275,000  12,500  31,700   48,600

              90       100      27       18      874,300 354,200 1,535,600  460,700  291,800  230,300   9,800  31,700  , 45,700
                                                                                                                          .7      2.6      0        3.3     301,500  45,200   40,200     0       2-90     2.14

                                                                                                                          .5      2.4      0        2.9     259,200  38,900   34,bOO     0       2.34     1.70

                                                                                                                          .3      1.6      0        1.9     171,900  25,800   22,900     0       1.56     1.13

                                                                                                                          .2       .8      0        1.0      85,500  12,600   11,400     0        .77      .56

                                                                                                                        1.0      2.6      1.4      5.0     435,600  65,300   56,000  18,000     3.93     2.86

                                                                                                                          .7      2.6      1.4      4.7     408,600  61,300   54,500  18,000     3.22     2.39

                                                                                                                          .5      2.5      1.4      4.4     380,700  57,100   50,300  18,000     2.74     2.07

                                                                                                                        1.2      2.6      2.7      6.5     556,200  63,400   74,200  35.800     4.80     3.62
                                                                                                                                       <                           I
                                                                                                                          .9      2.6      2.7      6.2     534,600  80,200   71,300  35,800     3.96     2.98

                                                                                                                          .7      2.6      2.7      6.0     517,500  77,600   69,000  35,600     3.50     2.67

                                                                                                                        1.3      2.6      4.7      8.6     729.000  109,400  9/.200  65,100     5.23     3.96

                                                                                                                        1.1      2.6      4.7      8.4     717,300  107,600  95,600  65,100     4.90     3.74

                                                                                                                          .9      2.6      4.7      8.2     693,900  104,100  92,500  65,100     4.29     3.33

                                                                                                                          .7      2.6      4.7      6.0     680,400  102,100  90,700  65,100     3.94     3.10

                                                                                                                        1.0      2.6      6.8      10.4     871,200  130,700  116,200  88,200     5.08     3.98

                                                                                                                          .6      2.6      6.8      10.2   t  851,400  127,700  113,500  88,200     4.54  (   3.62
                                                                                                                                        1.84

                                                                                                                                        1.47

                                                                                                                                          .98

                                                                                                                                          .49

                                                                                                                                        2.48

                                                                                                                                        2.09

                                                                                                                                        1.83

                                                                                                                                        3.20

                                                                                                                                        2.62

                                                                                                                                        2.37

                                                                                                                                        3.49

                                                                                                                                        3.32

                                                                                                                                        2.98

                                                                                                                                        2.79

                                                                                                                                        3.58

                                                                                                                                        3.29

-------
                                                                                                                         S.S'Hq
                10 F Temperature  Rise


                    _1	L-
                                                                         10   20   JO   40   50   60    70    BO   90   100
                                                                                         iPercnnt Heat  Removed
                                                                                                                                                           30  YEAR REMAINING LIFE
                                                                                                                                                                  B-VIII-J
                                                                                                                                                                                                          5.5-H,
                                                                                                                                                                                                                «.9°C  75°r


                                                                                                                                                                                                                13.9°C  57°F

                                                                                                                                                                                                       I*-5VX'^ «et Bulb
                                                                                                                                                                                                                Tewv rafirea
                                                                                                                                                               3.0-Hg
                                                                                                                                                                                                       J.5'H
-------
These higher costs are deceptive, because a simple change to
the  system can reduce the cost to approximately that at the
16.7°C (30°F) rise case.  This  change  involves  increasing
the  turbine  exhaust pressure and then cooling only part of
the circulating water to a level below that  required.   The
required  temperature  is  obtained when the two streams are
remixed.   This is possible due  to  the  larger  temperature
difference  between the wet bulb and cold water temperatures
than in the 16.7°C (30°F) rise  case.   The  tower  cost  is
significantly  lower  due to the lower flow through it.  For
example,  by increasing the turbine exhaust pressure to  11.8
kN/sq  m1 (3.5 in. of Hg) and cooling 60% of the water 11.1°C
(20°F), the additional generation cost is reduced  from  1.0
mills/kwh .to  0.7 mills/kwh.  Thus the higher costs for the
6.7°C (12°F) rise case  can  be  substantially  reduced,  an
option  not  as  readily available in the 16.7°C (30°F) rise
case.  The cost of this scheme is  variable  depending  upon
site conditions and plant layout.

The results for the cyclic unit are shown in Figures B-VIII-
7,  B-VIII-8, and B-VIII-9.  The curves have essentially the
same shape  as  the  base-load  unit  curves,  however,  the
additional  generation  costs  are  doubled.  The reason for
this is that there is much less power generated in a cycling
plant against which the cost of the cooling  towers  can  be
charged.    With a six year remaining life, the 75°F wet bulb
case results in a higher incremental cost than the 83°F  wet
bulb  case.   For  the  18  and 30 year remaining lives, the
costs for the  75 °F  and  83°F  cases  are  the  same.   The
capacity  factor for the cycling plant is HH% versus 11% for
the base-load unit.  The penalties were assumed  to  be  the
same as in the base-load unit, as the cycling units would be
heavily  used during the summer peak load.  If this were not
true for specific units, the cost would be somewhat lower.

The costs for the peaking units are shown in Figures B-VTII-
10, B-VIII-11, and B-VIII-12.  The costs for these units are
almost an order of magnitude  greater  than  those  for  the
base-load  unit.   The maximum was 11.0 mills/kwh for a unit
with  6  years  remaining  life  and  the  minimum  was  4.5
mills/kwh  for  a  unit  with 30 years remaining life.  Here
again the major difference was the number of  kwh's  against
which  the cost of the cooling system could be charged.  The
capacity factor for peaking units used was 9% as opposed  to
77% for base-load units.  The change in additonal generation
cost  with  change  in  capacity  factor,  all other factors
remaining the same, can be determined from Figure B-VIII-13.

The cost of backfitting mechanical draft towers  on  nuclear
units  was  also  determined,  using the same techniques em-
                             602

-------
"5  i-l
1*  ..:
             10    ZO    30   40   SO   CO    TO    60   90
                               .„.»... He«t  Removed
                          ADDITIONAL 0ENEMT1NO COSTS  FflR
                                 100  w CYCLIC  UNIT
                               MECHANICAL DRAFT TOWERS
                                 G YEAB REMAINING  LIFE
                                   Figure  B-VIII- 1
                                                                                                40    50
                                                                                                   Pwreert  Heat  Removal
                                                                                            ADDITIONAL OKKEXATZHO COSTS  FOR
                                                                                                     JOO MM CYCLIC UNIT
                                                                                                   MECHANICAL  DRAFT TOWERS
                                                                                                    14  YFAR PEMAININT, LIFE
                                                                                                        Figure B-VIII- 8
                                                                                             Percent  H<
                                                                                              ADDITIONAL OEDtMTim COSTS FOR
                                                                                                      100 H» CYCLIC UNIT
                                                                                                   MECHANICAL DRAFT TOWERS
                                                                                                      30  YEAH REMAINING LIFE
                                                                                                         Figure B-VIII- 9
                                                 B0~  90" life"1"
ADDITIONAL GENERATING COSTS FOR
       JOO M«  PEAKING UNIT
    KECHA.1ICAL DRAFT TOWERS
       t  YFAB  PEMAININT LIFF
           Figure B-VIII-li
         40   "50  ~60~ "T0~  80 " 90
     Percent Hear Peaoved
AOOITIOKAL OEHEBATIBG COSTS FOR
        JOO «fe  prAJtINC UNIT
     MCOIAMICM DRAT? TfWERS
      IB YF.AP  PF1A[fT:)C  LIFE
             Figjc*  B-VIII-"
                                                                                                                                                                                   12.0


                                                                                                                                                                                   11.0


                                                                                                                                                                                   10.0 .
                                                                                                                                                                               s
                                                                                                                                                                               J. '••
                                                                                                                                                                               :S ...
                                                                                                                                                                                            Temperature Ri»e

                                                                                                                                                                       TO20!o4050toTOio   90   100
                                                                                                                                                                                                        Percent Heat Hraove
                                                                                                                                                                                                   ADDITICMH. CZNZKATinO COSTS  FOR
                                                                                                                                                                                                          JOO •%. PEAMrtT. UNIT
                                                                                                                                                                                                        MECHANICAL OBAFT TOWERS
                                                                                                                                                                                                         tO YEAR REMAIIflMC LIFE
                                                                                                                                                                                                              Figure B-VIII-IZ

-------
                                     CF
                                         , COMPARISON OF CAPACITY FACTORS
                                                   0.7     0.8    0.9    1.0
    0.0^
      0.0   0.1    0.2   0.3    0.4   0.5   0.6   0.7   0.8   0.9   1.0   1.1    1.2




   ADDITIONAL GENERATION COST AT CAPACITY FACTOR (CF2) IN QUESTION, MILLS/ kwh







FIGURE B-VIII-13 VARIATION OF ADDITIONAL GENERATING COST WITH CAPACITY FACTOR
                                    604

-------
ployed for the 300 Mw fossil-fueled plant.  Except for a few
small experimental units, most nuclear  facilities  fall  in
the  500  to 1000 Mw size range.  An 800 Mw nuclear unit was
assumed for the economic analysis.  The  heat  rate  assumed
was 11,088 kJ/kwh (10,500 Btu/kwh) , with 6,86<» kJ/kwh (6,500
Btu/kwh)  being  rejected through the condenser.  Two circu-
lating water temperature rises were used, 16.7°C  and  6.7°C
(30°F and 12°F).  The remaining assumptions were essentially
the  same as for the 300 Mw fossil-fueled unit.  Since there
are no large nuclear units over ten years old, only  18  and
30 years remaining lives were considered.  All nuclear units
presently  are  intended  for base-load service, so only the
base-load case was considered.  Wet  bulb  temperature  used
for  tower  design  was 23.9°C  (75°F).  Capacity factor used
was 70S.

The costs resulting from this analysis are shown in  Figures
B-VIII-HJ  and  B-VIII-15.   For the 16.7°C (30°F) rise, the
additional generation cost was higher than for  the  fossil-
fueled unit due to the increased heat rejection to the water
as  expected.   Here  again  the  'case where the circulating
water  rise  was  6.7°C   (12°F)  was  the  most   expensive.
However,  the  comments concerning this in the fossil-fueled
analysis are equally applicable to this case.

Two  sets  of  estimated  cost  for  retrofitting   existing
powerplants  were submitted as comments by the Utility Water
Act Group  (UWAG).388 The first of these  analyses,  prepared
by Sargent and Lundy Engineers**7, addressed the retrofit of
a  hypothetical  matrix  of  plants  which  was  selected to
represent variations in the  basic  design  parameters . that
affect  the  cost  of  installing  closed cooling systems at
existing plants.  The Sargent and Lundy analysis is  similar
to  the cost analysis presented above and performed by Burns
and Roe in its draft development document.  The  results  of
these two analyses are compared in Table B-VI11-16.

The  second  set  of  estimated costs submitted by UWAG is a
tabulation of a survey of utilities, each of which estimated
the cost of retrofitting plants in its system.  This  survey
is  contained  in  Volume  I  of  the  UWAG comments.  These
estimates are generally higher than those from  the  Sargent
and  Lundy  analysis,  since they include site related costs
not fully accounted for in the Rypothetical  analysis.   The
results  of the utility survey can be compared with the cost
curves shown in this document.  These cost curves,  prepared
by  EPA,  also  reflect  higher  allowances for site related
conditions.  The utility estimates  and  those  of  EPA  are
compared in Table B-VIII-17.
                             605

-------
     1.6
     1.4
     1.2
     1.0
5    0.4
     0.2
     0.0
              Condenser Pressures Shown
                      as "tig abs.


         _ 23.9°C (75°F) Wet Bulb Temperature
                           2.5"Hg
                                                          4.5"Hg
             10"203D   405060"70   80   90luu
                        Percent  Heat  Removed
                     ADDITIONAL GENERATING COSTS FOR
                         800 Hw   NUCLEAR UNIT
                        MECHANICAL DRAFT TOWERS
                         18 YEAR REMAINING LIFE
                         Figure  B-VIII-14
     1.4
                                                                                           1.2
•o    0.4
a
        Condenser Pressures Shown
                as "Hg abs.


23.9°C (75°P) Wet Bulb Temperature
                                                                                                                 2.5"Hg
                                                                                                                                                     16.7°C (30°FI
             10   20  ~30   40   50   60   70   80   90   100
                        Percent Heat Rejected
                    ADDITIONAL GENERATING COSTS FOR
                         800 Hw NUCLEAR UNIT
                       MECHANICAL DRAFT TOWERS
                        30 YEAR REMAINING  LIFE
                        Figure  B-VIII- 16

-------
                                                     Table  B-VIII- 16
                                         COMPARISON OF B&R ECONOMIC ANALYSIS OF RETROFITTING
                                           COOLING TOWERS WITH SARG12NT &  LUNDY ANALYSIS
CTi
O
No. of Plants •
in Analysis
Category
Peaking Units
Cycling Units
Base Loaded Units

Burns and Roe
Analysis
1
27
No.
9
9
9
27
Increased
Max.
5.70
1.31
0.62

Generating
Min.
2.90
0.64
0.31

Cost (Mills/kwh)
Avg.
4.
0.
0.

30
98
46


Sarqen
t and Lundy
Analysis
2
92
No.
3
32
54*
89
Increased
Max.
5.71
1.74
1.28

Generating
Min..
2.60
0.28
0.25

Cost (Mills/kwh)
Av
3.
0.
0.

9-
90
93
44

                       *  Note that the  S&L  Analysis deletes  3 base  loaded plants as "infeasible".

                          From Development Document for Effluent  Limitation Guidelines and Standards
                          of  Performance for Steam Electric Power Plants, Burns & Roe, Inc., June 1973,
                          Figures  B-VIII-1-3,  B-VIII-9-14.
                          UWAG comments  on  EPA  proposed guidelines,  Vol.  1, Attachment III -
                          Appendix A,  June  1974.

-------
                                                   Table B-V1II-17
                                      COMPARISON OF UTILITY SURVEY OF RETROFITTING COSTS
                                                  WITH EPA COST CURVES
No. of Plants
in Analysis
Category
Peaking Units
Cycling Units
Base Loaded Units .

EPA Cost Curves
27
Increased Generating Cost (Mills/kwh)
No. Max. Min. Avg.
9 9.30 4.30 6.22
9 2.00 l;02 1.44
9 1.12 -0.60 0.84
27


No.
2
97
(94)
25
(23)
or*


Increased
Max.
2.26
5.81
(3.40)
2.08
(1.89)
Utility Survey- •*•
92


Generating Cost (Mills/kwh)
Min.
2.26
0.72
(0.72)
0.46
(0.46)
Avg.
2.26
1.70
(1.58)
0.94
(0.84)
O
00
                     * Note:  In addition.to the 124  units  reported here the utility survey included
                              13 units for which the  costs  could not be broken out and 2 units scheduled
                              for retirement.
                       UWAG comments on EPA proposed guidelines, Vol. 1, Attachment III,
                       Appendix D, June 1974.

-------
The  variables  considered  in  the  Sargent and Lundy (SSL)
matrix included  weather  conditions,  stream  temperatures,
capacity  factor,  unit  age,  extent  of  turbine  back-end
loading, type of cooling and circulating  water  flow  rate.
The  Burns  and  Roe   (B&R)  analysis  also  used these same
variables, except for cooling  type  back-end  loading,  and
stream  temperatures.  The inclusion of these two additional
variables in the S&L analysis required a larger  matrix  (92
units)   than used in the B&R analysis (27 units) .  Estimated
capital costs in the two  analysis  were  approximately  the
same.  For instance, the average construction cost for the 6
schemes for S&L*s 111 Mw fossil plant ($7.97/kw)  compares to
the  average construction cost of B&R's schemes for it's 300
Mw fossil plant  ($7.30/kw).  Both analyses allowed for  both
capacity  losses and energy losses as supplied by combustion
turbines.  S&L allowed $106/kw for replacement capacity  and
B&R  used  $90/kw.  S&L estimated the cost of make-up energy
to be $.98/10* Btu which is equivalent to the  B&R  estimate
of  10  mills/Kwh  for  new  gas turbines with heat rates of
10,000  Btu/Kwh.   The  major  difference  between  the  two
analysis  was  that  the  S&L  analysis  optimized the tower
design with respect to the individual condenser-turbine sets
whereas the B&R analysis did  not.   One  would  expect  the
increased  generating costs estimated by the S&L analysis to
be slightly lower than those estimated by the B&R analysis.

The comparison of the results of the two analyses  is  shown
in  Table  B-VTII-16.   As  can  be seen from the table, the
average increase in generating cost resulting from  the  S&L
analysis  is  close to that estimated in the B&R analysis in
all three categories.  For instance, the S&L analysis  shows
an  average  increase  of  0.44 mills/Kwh for 54 base loaded
units.  The comparible number from the B&R analysis is  0.46
mills/Kwh.  The comparisons for the other two categories are
also close.  In all three cases the S&L estimate is slightly
lower, which reflects their tower optimization process.

Based  on  this  comparison,  it  is  concluded that the two
independent analysis are complementary and  that  the  costs
for  retrofitting  power  plants,  exclusive of site related
factors,  are  satisfactorily  established.   The  EPA  cost
curves  are shown in this document.  The curves are based on
the  original  B&R  analysis  but  contain   a   substantial
allowance  (300% of tower base cost) for site related factors
which   can   increase  the  fixed  cost  of  cooling  tower
installations at some locations.

The utility survey  represents  the  separate  estimates  of
eight  utilities  of  the costs of retrofitting the units in
their individual systems.  The factors  considered  and  the
                             609

-------
format  used  for reporting the results is identical to that
used in the  S6L  analysis.   However,  these  estimates  do
include  the  costs associated with the various site related
factors that would be  experienced  at  the  separate  plant
locations.   The total number of units in the utility survey
was 139.  Of these, 124 are  included  in  the  comparisons.
Thirteen  additional units were not included since the costs
were reported on combinations of units which did not  permit
breaking  out  of  costs  for peaking, cycling and base load
units.  Two additional units  in  the  utility  survey  were
scheduled for retirement and no costs were provided.

The  comparison of the results of the EPA estimates and that
of the utility survey is shown on Table B-VIII-17.  The cost
for retrofitting peaking units cannot be estimated from  the
utility  survey  data  since  only  2  units were separately
estimated.  Six other peaking units were reported,  however,
the costs of retrofitting for these units were combined with
cycling   and  base  loaded  units.   While  there  is  some
difference  between  the  maximum  and  minimum  costs   for
individual  units,  the  average  costs  of retrofitting are
fairly clo~e for both base-loaded  and  cycling  categories.
For  instance,  the  average  cost  for retrofitting 25 base
loaded units, as estimated in the  utility  survey  is  0.94
mills/Kwh.    This   rompares   to   an   average  cost  for
retrofitting the 9 base loaded units in the EPA analysis  of
0.84  mill/Kwh.   Similarly,  the  estimated  cost  for  the
cycling category is 1.70 mills/Kwh from the  utility  survey
and  1.44  mills/Kwh  from the EPA curves.  In addition, the
utility survey is  strongly  influenced  by  extremely  high
costs  for  relatively  few units.  For instance, if the two
most costly units were removed from  the  utility  analysis,
the  remaining  23  units could be retrofitted at an average
cost of 0.84  mills/Kwh,  which  is  identical  to  the  EPA
estimate.   If  the  three  most  costly  cycling units were
removed from the utility analysis  the  remaining  94  units
could  be  retrofitted at an average cost of 1.58 mill/Kwh a
figure which is roughly 10% higher than the EPA estimate.

In summary, it appears that there  is  reasonable  agreement
between  EPA  and  the  industry  on the cost estimates upon
which the thermal effluent guidelines are based.  First, the
theoretical basis used by BSR for establishing  retrofitting
costs,  exclusive  of  site  related  factors,  is  in close
agreement  withe  the  results  of  the  Sargent  and  Lundy
analysis.   Moreover,  the results of the EPA cost analysis,
which includes a large allowance for site related costs, are
also in close agreement with  the  results  of  the  utility
survey at least for the cycling and base loaded categories.
                              610

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Energy (Fuel) Requirements

Energy  significantly in excess of that normally required by
the circulating water system  is  required  to  operate  all
cooling systems except the cooling pond.  With spray canals,
the  water  is  pumped  into  the spray nozzle.  The natural
draft tower requires the water to be pumped to  the  top  of
the  packing.  In the mechanical draft tower, in addition to
pumping the water to packing, power is required to  run  the
fans  which  move  the air through the tower.  The amount of
energy required varies by a factor of three  for  mechanical
draft  towers  due to its dependency on condenser design and
climatic conditions.  A condenser with a high flow rate  and
low  temperature  rise  requires  more pumping energy than a
condenser with a lower flow rate and higher  rise,  for  the
same size plant.  With adverse climatic conditions, more air
is required, resulting in bigger fans requiring more energy.

Fan motors for mechanical draft cooling towers are about 0.2
percent  of  the  unit  generating capacity; pump motors are
about 0.5 percent.  However, fans  and  pumps  need  not  be
operated  continuously  year round.  Both fan power and pump
power can be  reduced  along  with  the  generating  demand.
Furthermore,  fan  power  can  be reduced when climatic con-
ditions permit to optimize the net unit power output.   Only
incremental pumping power should be considered as chargeable
to   closed  cooling  systems.   Incremental  energy   (fuel)
consumption due to fans  and  pumps  with  mechanical  draft
cooling  towers is estimated to be approximately 0.7 percent
of base  energy   (fuel)  consumption.   With  natural  draft
towers   and  spray  systems  there  is  no  fan  power  but
incremental pumping power is estimated to  be  approximately
0.7  percent or less of base fuel consumption.  With cooling
ponds there is no fan  power  and  pumping  power  would  be
approximately the same as with once-through systems.

A  further  source  of incremental energy (fuel) consumption
due to closed-cycle cooling systems is the incremental steam
cycle  inefficiency  due   to   changes   in   the   turbine
backpressure.   In  many  cases higher turbine backpressures
will result after backfitting closed-cycle cooling  systems.
In  these  cases  the  higher  backpressures  will result in
incremental steam cycle inefficiencies during  part  of  the
year.   The  incremental  fuel  consumption over any span of
time due  to  this  factor  is  a  product  of  the  average
incremental  inefficiency  over  that  span  and  the  power
generated over the span.  For example, the fuel  consumption
penalties  due  to  increased  turbine  backpressure  from a
closed-cycle cooling system  (See Figure B-VIII-16) is  shown
in Table B-VIII-18.  The maximum penalty during any month is
                               611

-------
                                  Figure B-VIII-16



                 TURBINE EXHAUST  PRESSURE  CORRECTION FACTORS (EXAMPLE/ PLANT NO0 3713)
to
                                                                  Throttle Flow
                                                                  1.5  x 10
                                                                  2.5 x 10
                                                            mm   3.2 x 10
                                                                  4.2 x 10 IbAr

                                                                  4.4 x 10 IbAr
                                 
-------
                                   Table  B-VIII-18


          ENERGY (FUEL) CONSUMPTION PENALTY DUE TO INCREASED TURBINE BACKPRESSURE
                           FROM CLOSED-CYCLE COOLING SYSTEM ***
                         Example calculated for plant no. 3713
Month
J
F
M
A
M
J
J
A
S
O
N
D
Dew Point
Temp. , F
32
32
36
46
56
64
67
67
61
50
39
32
Air
Temp. , F
42
43
50
59
68
75
78
77
71
61
50
42
Wet Bulb
Temp.,°F
38
39
43
52
60
68
70
70
64
55
45
38
Condenser Out-
let Temp. , F
68
69
73
82
90
98
100
100
94
85
75
68
Condensing
Temp. , F
73
74
78
87
95
1(33
105
105
99
90
80
73
Backpressure,
in. of Hg
0.82
0.85
0.97
1.29
1.66
2.11
2.24
2.24
1.88
1.42
1.03
0.82
Fuel Penalty*
% of base
Ool**
0.1**
0.0
0.0
0.1
0.5
0.7
0.7
0.3
0.2
0.0
0.1**
Annual Average 0.2
en
H
U)
     ** Note: This plant normally reduces the flowrate of cooling water in the winter to
              minimize this type of penalty, therefore flowrate reduction with the closed-
              cooling system is also assumed to eliminate the penalty during the winter months,
      * Note: Assumes no penalty for once-through system, which is probably the case for
              plant no. 3713. Some penalty for once-through systems could occur for other
              plants during the summer months.
   *** Notes The values given in the table are computed  from mean values for each month. The
             maximum backpressure penalty for which the  cooling ststem would be designed to
             operate would be base on the wet bulb temperature which would be exceeded no
             more than 5% of the time during the three months of summer. For plant no. 3713,
             this wet bulb temperature is 80 F and the maximum backpressure penalty is 2.1%.

-------
0.7  percent  of  base  fuel  consumption during that month.
Assuming uniform power generating from month to  month,  the
annual penalty is 0.2 percent of base fuel consumption.  The
greatest fuel penalty expected would occur when the wet bulb
temperature   reaches   the  maximum  level  for  which  the
evaporative cooling system is designed, i.e.  the  wet  bulb
temperature  which  is  exceeded no more than 5% of the time
during June, July, August  and  September.   For  the  plant
shown  the  maximum  penalty  is 2.1%.  In the case of a new
source the penalties would  not  be  as  great  due  to  the
opportunities  to  optimize  the  design  of  both the steam
system (turbine, etc.) and the cooling system.

The total annual fuel penalty for the example above  is  0.9
percent  of  base  fuel consumption, assuming that the power
generated from month to month is about  the  same.   If  the
plant  shown generates twice as much power during the months
of June through September  compared  to  other  months,  the
annual  backpressure  penalty  would approximately double to
0.4 percent, increasing the overall annual  penalty  to  1.1
percent  of  base  fuel  consumption.  Based on the analysis
above, an annual fuel penalty of  2  percent  of  base  fuel
consumption would be conservative.

Loss of Generating Capacity

In  the  case  of  Plant  no.  3713  described  in the above
discussion of fuel  requirements,  the  loss  of  generating
capacity  imposed  by a closed-cycle cooling system would be
the sum of the fan power and pump power requirements   (0.7%)
and  the  maximum backpressure penalty (2.1%), or a total of
2.8% of nameplate generating  capacity.   While  the  direct
effects  of these penalties would be felt as lost generating
capacity only when the demand for  generation  and  climatic
conditions  coincide  to  actually limit generation to below
nameplate capacity, the probability of  such  an  occurrence
must  be  considered  in  system  planning  leading  to  the
construction of replacement generating capacity.

Site-Dependent Factors

The analysis of the  cost  involved  in  installing  cooling
devices  on  the  circulating  water systems assumed average
site conditions.  At any particular station, costs  will  be
affected  by specific conditions existing at the site.  Some
of the more important factors are addressed in detail below.

Reference UU7 examined, by computer simulation, the  effects
of  wet-bulb temperature, circulating water flowrate, stream
temperature, extent of turbine back-end  loading,  dry  bulb
                             614

-------
temperature,   and   other   factors   on  equipment  costs,
capability losses, energy losses, and generating costs.   The
results are summarized in Tables B-VIII-19  through  B-VIII-
22.

Age

The  cost,  expressed  in  relation  to  power generated, is
inversely related to the number of  years  of  service  life
remaining  for  a  particular generating unit.  That is, the
shorter the remaining useful life over which the cost of the
cooling system may be amortized, the  greater  will  be  the
percentage  of the capital cost charged against each unit of
power generated.  Moreover, the shorter the remaining useful
life, the less heat will  be  rejected  to  the  environment
particularly  since  many  older units traditionally operate
only during periods  of  higher  demand.   Accordingly,   the
capital  cost  expressed  as  a  function  of  units of heat
removed will be greater for older plants.  In  addition  the
absolute  cost  of  retrofitting existing once-through units
with closed-cycle cooling is substantially greater  than  is
the cost of installing cooling equipment at new units.

Assuming  the  capital  cost  of  retrofitting  closed-cycle
cooling systems to steam-electric generating units to  be  a
function  of  generating  capacity  only,  the  costs versus
effluent reduction benefits function for units  of  a  given
capacity  would  be  determined by the remaining life of the
units  and  the  capacity  factor  for  the  unit  over  its
remaining  life.   If  it is assumed that the useful life of
all  generating  units  is  35  years  (with  the  following
capacity  factors:  year  1 through 20, 0.7 capacity factor;
year 21 through 30, 0.4 capacity factor; year 31 through 35,
0.1 capacity factor) then a cost versus  effluent  reduction
benefit function can be established for thermal controls, as
a  function  of  the  age  of  the  unit  when  controls are
implemented, as shown in Figure B-VIII-17.  As can  be  seen
from  the  figure,  the  costs/effluent  reduction  benefits
increases gradually as the age of the  unit  increases  with
the  costs/benefits  of  a  unit 5 years old being about 20%
greater than for retrofitting a unit of zero age, and  about
60%  greater  for  a  unit  10  years old, which is half-way
through its assumed base-load service life.  After this age,
the costs/benefits increases rapidly to about  120*  greater
than  the zero age unit at age 15 and 300% greater at age 20
which is the end of  its  assumed  base-load  service  life.
During  cyclic  service,  at  age 25, the costs/benefits are
over 800% greater than for the zero age unit.
                              615

-------
                      Table B-VIII-19
      Computer  Simulation of  Cost|4of Retrofitting
                    Cooling Towers
                 MECHANICAL DRAFT - 411 MW UNITS
                       72%CAPACITY FACTOR
\% Wet Bulb
                                   CMt (I/to)
                          «5
78
gr«A« 300
7.97
600
9.10
1100
9.80
300
. 8.57
600
9.71
1100
10. Ul
600
11.37
  Wet Bulb
                            Capability Lo.te. (*)
                          65
78
gpB/YW
1% Strean Temp.




C*)
58
78
93
300

1.7
l.U
-O.U
600

l.U
1.5
1.1
1100

1.8
1.8
1.8
300

2.U
2.1
0.3
600

2.U
2.5
2.1
1100

2.7
2.7
2.7
600

—
1.U3
«
  Wet Bulb
                          65
                              tnirgf Lo«««« (%)
78
82
g-po/XW
1% Stream Temp.




(*P)
58
78
93
300

0.7
0.7
0.6
600

0.8
0.8
0.7
1100

0.7
0.7
0.8
300

0.7
0.7
0.7
600

0.7
0.7
0.7
1100

0.7
0.7
0.7
600

—
1.16
..
1% Wet Bulb
                            ToUl Coat (mlll./KWH)
                          65
78
KTO/MW
1% Stream Temp.


58
78
93
300
0.32
0.31
0.25
600
0.3U
o.3U
0.33
1100
o.)5
0.35
0.37
300
0.35
0.3U
0.29
600
0.36
0.36
0.37
1100
o.uo
o.uo
o.uo
600

.15
* Note: High back-end loaded
                            616

-------
                         Table B-VIII-20
         Computer Simulation of Costs of Retrofitting
                    Cooling  Towers

                MECHANICAL DRAFT - 535 MW UNITS
                       44% CAPACITY FACTOR
If wet Bulb
Cr)
                         Equipment Cost($/IW)

                        65                  78
«n/MW

300
11. UO
600
12.23
1100
11.93
300
11. UO
. 600
12.23
1100
13.1*2
300
11.86
600
13.70
1100
13.U2
  Wet Bulb
Cr)
                            Capability Laaae* (%)

                        65                  78
                                                              82
Q>m'ni^
1> Strean Temp.




CD
58
78
93
300

3.63
• 31
-3.7U
600

2.86
l.M»
.1.20
1100

2.80
2.11
.23
300

5.75
2.U9
-1.62
600

U.32
2.90
.25
1100

3.88
3.18
1.30
300

6.U8
3.15
-90
600

U.U7
3.06
.'•0
1100

U.l.3
3.7<«
1.85
  '.'ct PL-IS
            (V)
                             tner,y Uoues «)
                               78
                                                              02
*WMW
If Strcan Teop.




Cr)
58
78
93
W

2.38
1.26
-.06
600

2.33
1.8U
i.oe
1100

2.53
2.23
1.66
300

2.77
1.65
.33
600

2.56
2.07
1.18
1100

2.52
2.28
1.71
300

I..78
3.67
2.35
600

3.79
3.29
2.JI.
1100

t.y
v.ot
3.«>!
If Wet Bulb     Cr)
                        65
                            Total Oott (Mllll/nm)
                               78
                                                              82
a»'*i
If Strcan Temp.




Cr)
58
78
93
300

.88
.61
.28
600

.88
.76
.55
1100

.68
.81
.67
300

1.02
.Tfc
.1*1
600

.96
.85
.63
1100

.99
.93
.78
300

1.31
l.Oh
.78
600

1.18
1.06
.85
1100

1.23
1.16
l.OJ
   * Note: Medium back-end  loaded
                            617

-------
                                                         Table B-VIII-21

                             Computer Simulation of Costs  of Retrofitting  Cooling Towers
                                                                             447
     1% Vet Bulb
CF)
                                                 NATURAL pRAFT - 41 1 MW UNITS
                                                      72% CAPACITY FACTOR
                                                        Equipment Coat($/foW)
                              65
                                                                                                    78
IX Dry Bulb
«=/*••

CF)
300
12. kl
82
600
12-91

1100
13.30
96
300
13-29
600
13-72
1100
13.91
92
300
13- 7U
600
11*. 18
1100
15.11
111
300 600
1100
11*.1B 15.13
       Vet Bulb
                       CF)
                                                        Capability Loiaeg (%)
                              65
                                                                             78
1H Dry 3ulb
BjnA*
154 Stream Tenperatur*


CF)

58
78
93

300
2.00
1.67
-.123
82
600
1.95
2.00
1.66

1100
2. A
2.1,0
2.33
96
300
2.15
1.81
.037
600
2.12
2.17
1.91*
1100
2.55
2.61
2.51*
92
300 600
2.52 2.85
2.18 2.91
•393 2.55
1100
3.51
3-57
3.52
111
300 600
2-95
3.01
2.65
1100
3-U
3-^
3-1*
CTl
M
00
     1* Vet "-:lb
CF)
                                                          Energy lx>esea (%)
                                                      65
                                                                             78
IX Dry Sulb
erafa
W Stress Temperature


CF)

58
78
93

300
0.1*3
0.1.3
0.36
82
600
O.U.
O.U*
O.U5

1100
0.!*S
0.1*5
0.1*5
96
300
0.55
0.55
0.1*7
600
0.51*
0.55
0.55
1100 •
0'.63
0.63
0.61*
92
300
0.52
0.52
o.U.
600 1100
0.51 0.51
0.52 0.51
0.53 0.52
111
30C 600
0.^2
C.'3
0.73
1100
0.8?
0.81
0.82
     \% Vet Bulb
                       CF)
                                                        Total Cost (Blll./KVH)
                              65
                                                                             78
IX Dry Bulb
gjn/rrv
l>i Streaa Teaperature

CFJ

58
78
93

300
.1*
• 39
.31.
82
600
.1*1
.1.1
.1*1

1100
-1*3
.1*3
• 1*3
96
300
• U.
• 1.3
• 37
600
• i.5
.1*5
1100
.LI
.1*7
.1*7
92
300
.1*5
.U.
• 39
600
.1*7
• L7
• U
1100
.51
.51
• 51
111
3?0 600 1100
•50 .5^
.53 .55
•W -55
      * Note: High back-end loaded

-------
                         Table  B-VIII-22
        Computer Simulation of Costs of  Retrofitting
                    Cooling Towers

                 MECHANICAL DRAFT - 82°F WET BULB
                      78° F STREAM TEMPERATURE
                             600 GPM/MW
                      Equipment Cor.t ($/K'v)
         MWe
                ?75
                                                 **
         MWe
                       Energy Losses (%)
1*11
275
                     Total  Cost (Mills/KWH)
               535
                                                                ***
Capacity Factor
72
9
MWe
Capacity Factor
72
1*1*
9
11.37
11.37
11.37
Capability Losses (%)
1*11
1.143
1.143
17.78',
17.78'.;
17.78:?
275
6.P3
6^23
13. (•'.)',
13-695
3.067
3.875
Capacity Factor
72
1*1*
9

1.157
1.727
1.156

5.71*0
6.669
8.760

2.672
3.298
3.700
         MWe
               275
               535
   Capacity Factor
             72
 .1448
 .713
2.597
1.28)4
1.76).
5.715
 .986
1.063
3.391
  * Note:  High back-end loaded
 ** Note:  Low back-end loaded
*** Note:  Medium back-end loaded
                               619

-------
-P
•H tP
IH £
0) -H
C -P
0) «J
« b
  0)
G C
O Q)
-H tr>
4J
o to
3
•a en
0) a
« -H
  -P
•P -P
C -H
0) ^
0 O
rH M
m .p
m  -P
CO  Q)
O  ta
Oi
fO
0)
N
  H  O
   fO
m  §
4J  fi
-HO
o
-P
•H
C
    10
     8
     6
     2
          0
           1980
                       Age of Generating Unit,  years


                       5          10        15         20
                                                              25
                  1975
                            1970
1965
1960
1955
1950
                 Date of Initial  Service if Retrofit Operation Begins in  1980

      Figure B-VIII-17   Costs/Benefits of Retrofitting Versus  Age of Unit

-------
National Economic Research Associates (NERA)   projected
the  percentage  distribution of the 1983 U.S. generation by
the cost of closed-cycle cooling in mills/Kwh (See Figure B-
VIII-18), which includes the effect of the age of units.

Size

Assuming that, based  on  costs  versus  effluent  reduction
benefits, retrofitting of thermal controls would affect' only
those  units  placed into service in 1970 and thereafter, an
analysis was performed to  ascertain  the  relation  of  the
capital cost of retrofitting mechanical draft cooling towers
to  the  generating  capacity of the unit in question.  As a
basis for the costs,  the  data  submitted  to  EPA  by  the
Utility  Water  Act  Group  were used, which resulted from a
survey of utilities and which include the effects  of  site-
dependent factors.  The data used are displayed in graphical
form  on  Figure  B-VIII-19.   In  all, data representing HH
generating  units  were  used,  ranging  in  size  from   70
megawatts  to  1300  megawatts generating capacity.  Capital
costs ranged  from  $13.98/kw  to  $33.08/kw  of  generating
capacity.   A  statistical  representation of the data using
the method of least squares indicates that, in general,  the
capital   cost   of   retrofitting   ($/kw)  decreases  with
increasing unit size   (generating  capacity) .   The  average
capital   cost   of   the  sample  was  $25.63/kw,  and  the
statistical representation of the data indicates  that  this
is  the most likely cost for a unit with a capacity of about
500 megawatts.  Based on the statistical representation,  the
capital costs for retrofitting a 100  Mw  unit   could  most
likely  be  about  $30/kw,  and  for a 1000 Mw unit the most
likely cost could be about $21/kw.

There are a very large number of small units  (defined by the
Federal Power Commission as units in plants of 25  megawatts
or  less  and  in systems of 150 megawatts total capacity or
less).  Yet these systems and units represent  only  a  very
small  percentage of the total installed generating capacity
in the United States.  Moreover, the  potential  for  higher
costs  due  to  site specific pecularities at any given unit
could be expected to be balanced by more  favorably  located
units  in  a  larger utility system.  In very small systems,
this expectation of  counterbalancing  unit  costs  is  less
justifiable  and the costs of meeting the thermal limits may
not be economically achievable.

Site-Dependent Factors in General

During the comment period, industry representatives supplied
two sets of data on the cost of installation  of  mechanical
                               621

-------
            33.13
                                          Figure B-VIII-18
33.13
      Mills/Kwh"
to
wh — Percentage D^strib

4 • 0 •



3.5 -


3.0 -



2.5 -
2.0 •
1.5 •

1 0 •
Oc _
. j •



By Annual Cost o
ution of 1983 Generatigg-j
f Closed Cycle Cooling ~j
(Excludes hydro and cor.bustion turbine /
generation cron plants which, ir. the /
absence of ar.y
federal thermal guide-
lines, would operate with closed cycle
cooling. )

B=Base load (72% capacity factor) ,
C=Cyclic (44% capacity factor) /
P=Peaking (9% capacity factor) /
M=Mechanical draft tower
/
N=Natural draft tower I /
33,20,10,5 =Years of remaining life //
•




A -^
^y /^
B B
M N
33 33
iiit
10% 20% 30% 40%
J/

J
/^
f

B
M
20
i i •
J
f



B
N
20
/
/
1




B
M
.0
• i i


B
N
1C

r





c
M
10
/
/
/
/











C
N
10
i i
|] 	
	 Mills/Kwh
•4.0



•3.5


•3.0



•2.5
•2.0
•1.5

• i n
i. . U
• n s
w . J
\ M,N
15

50% 60"o 70% 80% 90% 100%
                                       Percent of 1933 Generation

-------
K>
CO
•H HIJ
O
rtf
0,
O
O
rH -P
m -P
CJ r« 30
•H £
c 5
ra H
S 
CP «•
C co
-P -\
^^^^CD 00°
"^ -^ CP
o> ^ ^ ^
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^f Q ^ "*^ ^iL.
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Least squares representation of the data 	 '
_ _








iii ill
                          200        400        600       800      1000      1200

                              Size of Unit,  Generating Capacity,  megawatts
                                                               1400
   Figure B-VIII-19
Capital Cost of Retrofitting Mechanical Draft Cooling Towers to
Units Placed into Service after 1970 Versus Size of Unit

-------
draft  cooling  towers.383  The  first  was  a  report of an
engineering  firm  experienced  with  the  construction   of
cooling  towers.   Its  estimate  of  the  capital  cost  of
retrofitting, on a per kilowatt  basis,  was  only  slightly
higher   than  that  used  in  the  Agency's  original  cost
estimates of the proposed regulation.

The second was based on a survey of 60  plants,  in  several
utility systems, which represent approximately 12 percent of
the  total  steam electric generating capacity in the United
states.  The results of the survey are summarized  in  Table
B-VIII-23  The  average  capital  cost  of  this  survey was
significantly higher than the  previous  industry  estimate;
the  disparity  being  accounted for by the commenter on the
ground that the higher estimates reflected additional  costs
attributable  to  site-specific factors.  The variability of
the plant by plant  costs  reported  in  the  latter  survey
approximates  a normal distribution and ranges from about $9
per kilowatt to about $81 per kilowatt.  The median  of  the
sample  and  the capacity weighted average cost is $21.9 per
kilowatt.  Only  three  (5%)  of  the  plants  reported  per
kilowatt  costs  significantly  above  the average value (in
excess by 100 percent or  more.)  The  few  exceptions  with
extraordinarily  high  cost  per  kilowatt represent about 3
percent of the generating capacity covered  by  the  sample.
Since the extensive sample of cost estimates from individual
plants   addresses   all  site  dependent  factors  in  most
instances, and includes to some extent  costs  corresponding
to   the  factors  addressed  specifically  below,  EPA  has
determined that the sample adequately depicts the effects of
the total of the  site  dependent  factors  that  materially
influence the costs of achieving the effluent limitations on
heat.   While  the  estimated  costs of implementing thermal
controls at three of the plants  were  reported  to  reflect
costs  in excess of twice the median cost, these incremental
cost factors would not  significantly  affect  the  economic
achievability  of  the  effluent limitations.  Favorable and
unfavorable  site-dependent  factors  may  be ,expected   to
counterbalance  one another, when applied across the several
units at individual plants and the  numerous  plants  in  an
electrical  generating  system.   Hence,  the average of the
cost estimates reported in the 60 plant sample represents  a
realistic  estimate  of  the retrofitting costs likely to be
encountered by any utility system except the very  smallest.
Even  in  the  extraordinary case of the one plant in the 60
plant sample reporting a cost estimate of $81 per  kilowatt,
the  incremental cost  (above that within which 95 percent of
plants estimated costs  reflecting  site  specific  factors)
would  not  affect the economic achievability of the thermal
limitations.  For example, the abnormal incremental costs at
                           624

-------
             Table B-VXXI-23
  SUMMARY OK  SliUXTTD UTJLITIKC CAPITAL COSTS,
    CAPABILITY  LO.'JSnS AIID KIIERCY LOSSES FOR
MECHANICAL  UltAfT AND 11/iTUIlAL UnAFT COOLIIIG TOWERS •»«"
                  (1973 Dollars)
                                            Tower,  Punp,
Site Costs and Site
Capacity Preparation Costs
Capability
Losses'
(Mw) (S/Kw) 	 (Perec
(1) (2) O)
Mechanical Draft Cooling Towers
2,600
1,100
1,575
175
1,312
892
550
564
282
700
1,000
692
990
892
882
2,286
1,300
350
350
275
550
330
266
200
2,659
2,360
142
256
1,214
146
960
640
350
143
1,500
430
960
350
292
670
350
430
430
215
215
700
500
500
88
402
156
848
570
845
239
185
61
BOG
1,448
800
$14.83
21.57
19.75
19.75
19.09
21.21
18.26
22.61
22.61
21.39
22.24
24.24
20.74
28.05
'19.42
11.11
11.73
11.73
. 11.73
11.04
11.04
11.04
12.12
12.12
17.81
17.84
13.17
15.01
13.17*
32.48'
27.71*
27.51*
30.86*
62.24'
19.87*
30.70*
$27.50'
29.14'
40.41)
27.46*
29.14*
81.00*
29.76!
28.84*
31.63
18.35
21.34
17.58
17.43,
8.76!
9.45*
37.20
26.56,
26.20
33.68
33.12
27.72
49.99
26.93
29.41
1.42%
1.30
1.98
1.90
1.67
1.05
1.21
2.36
2.68
2.54
1.96
1.55
1.33
2.21
2.74
1.84
3.38
3.38
3.38
3.36
3.36
3.36
4.03
4.03
2.98
3.20
2.92
3.75
6.00
2.04
3.85
3.48
3.32
4.46
3.40
3.50
3.74%
3.03
3.55
4.70
3.48
4.00
3.26
3.07
3.41
1.91
1.52
1.47
3.35
2.08
2.30
2.35
2.22
2.71
1.56
0.09
4.08
2.78
2.37
2.50
Energy
Losses'
) 	
(4)

1.26%
1.43
2. 55
2.17
2.32
1.53
1.29
3.52
3.83
3.40
2.45
227
• A /
Inn
• o o
20*7
. 97
3.70
1.36
2.08
1.93
1.95
2.15
2.28
2.32
2.46
2.89
2.42
2.42
1.39
2.07
3.00
1.53
4.86
4.38
4.56
2.60
4.10
4.82
3.18%
3^ e
. 35
4.06
5.60
6.12
4.49
4.56
3.76
4.30
1.70
2.34
1.35
4.30
2.08
2.30
3.03
3.00
2.98
1.87
0.09
4.48
3.00
4.40
4.30
Site
Capacity
(Mw)
(1)

2,240
2,200
389
225
660
660
358
239
355
326
326
598
188
184
299
172
172
172
172
107
360
347
159
1,130
873
1,778

Total 14.689

Costs and Site Capability Energy
Preparation Costs Losses > Losses
($/Kw) 	 (Percent) 	
(2) (3)
Natural Draft Cooling Towers
$17.47 5.89%
48.88 7.24
47.45 7.98
47.45 7.98
16.41 3.14
16.41 3.14
31.34 2.80
31.34 2.80
22.54 4.60
22.54 4.60
22.54 4.60
21.93 3.47
21.93 3.47
21.93 3.47
21.93 3.47
30.65 1.67
30.65 1.67
30.65 1.67
30.65 1.67
23.48 4.42
23.48 4.42
33.82 3.52
33.82 3.52
64.08 2.72
58.09 2.87
28.48 2.72



(4)

3.70%
6.90
6.85
6.89
3.68
3.46
3.45
2.42
5.35
3.49
'11.62
3.82
5.55
4.64
3.50
1.91
• 1.64
3.07
2.47
10.42
3.45
3.36
8.43
2.80
2.90
4.40



'Sum of losses from pumps, fans and back pressure.
'Excludes site preparation costs.
































Weighted Average
Mechanical Towers


Weighted Average
Natural Draft Towers



Weighted Average
for All Towers


















$21.89



$33.33



$24.81













             625

-------
that site ($37 per kilowatt)  would  add  about  1  mill  per
kilowatt-hour  to  the cost of electricity generated by that
unit.  Unusual compliance costs could  impact  the  numerous
small units or small systems more severely.

Flow Rate

The  cost  of  closed-cycle  cooling equipment and the total
cost of generation are higher for  units  with  higher  flow
rates,  all  other  factors  being  equal.  Flow rates for a
particular unit  can  be  reduced  to  some  degree  without
significant  incremental  cost  to achieve the reduced flow.
In the cost analysis submitted to the Agency in  support  of
the   proposed   subcategorization   criteria,  the  cooling
equipment costs for the cases  of  highest  flow  rate,  all
other  factors being equal, were less than 10 percent higher
than the average cost of all cases with various flow  rates.
Total  generation  cost  were  less  than  approximately  10
percent higher for the cases with the  highest  flow  rates.
In  the  cost  analysis  for the worst combination of intake
temperature,  wet-bulb  temperature,  and  flow  rate,   the
equipment  cost  exceeded  the  average equipment cost by 52
percent.  These variations in  equipment  cost  are   within
the  range  of  variations  in  cost  that  are  anticipated
considering  the  numerous  factors   that   combine,   some
favorably  and  some  unfavorably, at each site to determine
the final cost of  thermal  control  implementation.   A  10
percent  cost  differential  is  within  the  range of costs
reflecting  the  normal  variability  among   site-dependent
factors in general as discussed above.

Intake Temperature

    It  is  recognized  that  units  with  high intake water
temperature will incur higher costs, all other factors being
equal.  This factor, however, is significant  mainly  during
the months when the high intake water temperatures occur and
also  for those units for which high levels of blowdown flow
are necessary, thus requiring relatively large quantities of
makeup water.  It is not as significant a  factor  for  most
units  which require normal quantities of makeup water flow.
In the cost analysis submitted to the Agency in  support  of
the  proposed  subcategorization  criteria,  this factor all
other factors being equal, added a maximum of 20 percent  in
the  most  extreme case to the average total thermal control
equipment cost.  This 20 percent cost differential is within
the range of costs reflecting the normal  variability  among
site-dependent factors in general as discussed above.
                                 626

-------
Wet-Bulb Temperature

The general cost analysis presented at the beginning of this
section  tested  the  significance  of,  wet-bulb temperature
costing  various  types  of  evaporative   cooling   systems
considering  four geographic locations representative of the
range of wet-bulb temperatures in the  United  States.   The
cost  of  cooling equipment at the most unfavorable location
based on wet-bulb temperature was 25 percent higher than the
average  cost  of  all  locations  tested   for   conditions
otherwise  identical.  In the cost analysis submitted to the
Agency  in  support  of   the   proposed   subcategorization
criteria,  this factor, all other factors being equal, added
a maximum  of  24  percent  to  the  total  thermal  control
equipment  cost  for the average of subcases covered for the
most  costly  case   analyzed.    This   24   percent   cost
differential  is  within  the  range of costs reflecting the
normal variability among site-dependent factors  in  general
as discussed above.

Back-End Loading

The  back-end  loading  of  a unit is the maximum steam flow
which the unit "an pass through the last stage blades of the
low pressure  turbine  expressed  as  a  percentage  of  the
maximum  steam  flow through che last stage blades which the
turbine is capable of accepting.

    In the cost analysis submitted to the Agency in  support
of the proposed subcategorizaticn criteria, this factor, all
other  factors being equal, added a maximum of 22 percent to
the total thermal control equipment costs  compared  to  the
average  of  the  cases covered.  The maximum cost reflected
the cost for a una  \ ith a back-end loading of approximately
15 percent.  Generation costs in mills per kilowatt-hour for
the worst  case  of  a  15  percent  back-end  loadi ••g  were
estimated  to  be  about  1 mill per kilowatt-hour.  This 22
percent differential in equipment costs is within the  range
of  costs  reflecting  the  normal  variability  among site-
dependent factors in general, as discussed above.

Aircraft Safety

An examination of this potential hazard indicated that it is
unlikely that an existing powerplant which will be  required
to  install a recirculated cooling water system would pose a
hazard to commercial aircraft during periods of takeoff  and
landing.  However, the vulnerability of aircraft during this
portion of the flight pattern requires special consideration
of cases where a substantial hazard may be shown to exist.
                             627

-------
Miscellaneous Factors

Certain   additional   site-dependent   factors   have  been
suggested  by  commenters  which  should  be  considered  in
subcategorization  for  effluent limitations on heat because
they can materially affect  cost;  existing  system  layout,
soil  conditions, site geology, and topography,  while it is
acknowledged that  these  factors  may  affect  case-by-case
costs,  the  costs  attributable  to  these  and other site-
dependent factors have been assumed in  the  computation  of
the economic costs of thermal control.
Relative Humidity

Natural  draft  towers are limited for practical purposes to
localities where the relative humidity exceeds approximately
50%.  The lower  humidities  result  in  prohibitively  tall
towers  to  provide  sufficient natural air flow through the
tower.
Land Requirements

The land area for installation  of  cooling  systems  varies
widely, as indicated on Table B-VTII-24.  Obviously, cooling
ponds  will  need  large  areas,  and can only be considered
where  such  land  is  economically  available.   The  tower
systems also require significant amounts of land.

The mechanical draft tower cell for medium size plants is on
the  order  of 21 x 12 meters (70 x 40 ft).  These cells are
placed side by side to make up the tower, which  can  be  as
much as 183 m (600 ft) long, depending on capacity required.
For  a  single  tower  installation,  anywhere from 30 to 60
meters (100 to 200 feet) of clear area  is  required  around
the tower to avoid interference of surrounding structures on
tower  performance.   This  means that from 3 to 6 times the
tower plan area is required.  When two or  more  towers  are
necessary,  the separation between towers must be 120 to 180
meters (UOO to  600  feet)  to  avoid  interference  between
towers.   Total area required for two towers would be U to 7
times the tower plan area.

Reference  52  presents  the  following  discussion  of  re-
circulation and interference as related to tower placement.

The  problems  most  usually encountered on large mechanical
draft industrial  towers  affecting  the- entering  wet-bulb
temperature  are recirculation and interference.  The former
is a pollution of the  inlet  air  by  a  tower's  discharge
vapors,  and  the latter is pollution of the inlet air by an
                               628

-------
                                                                     TABLE  B-VIII-24
                                                                  EFFLUENT  HEAT
                                                   APPLICABILITY OF CONTROL AND TREATMENT TECHNOLOGY
Size of Plant

Relative Humidity
                      Mechanical Draft
                      Met Cooling Tower
No limitation

No limitation
Natural Draft
Wet Cooling Tower

Greater than 500 Mw

Generally  limited  to  nrcns
of  th»  country  having an
avcrayo relative huni-Jity of
greater than  47%.
Surface Cooling
_(Pond3f Canals,_etc.j_

 No limitation

 No limitation
Mechanical Draft
Dry_Cpoling Tower

No  limitation

No  limitation
Fogging
Height
                      70 ft. wide x 150 - 600 ft.
                      long  (depending on plant size);
                      separation for multiple towers
                      400-600 ft.; clear area of
                      100 to 200 ft. required
                      around perimeter of tower area.


                      Current performance - less
                      than  .03% of circulating flow;
                      anticipated improvement to less
                      than  .005%; potential problem
                      in brackish or salt water areas.
                      Potential local problem depend-
                      ing on location & climatic con-
                      ditions; reduction of fogging
                      possible with parallel-path wet/
                      dry type tower.

                      Potential problem only if
                      adjacent to sensitive area;
                      can be reduced by attenuation
                      devices.
                                 350 - 550 ft. diameter plus
                                 100 ft. open area around  tower;
                                 nuclear plant-tower must  be
                                 distance equivalent to height
                                 away from reactor; 1/3 reduc-
                                 tion of land area possible
                                 with fan-assisted type tower.

                                 Current performance - .005%  of
                                 circulating flow; one tower
                                 under construction guaranteed
                                 to be less than  .002%; poten-
                                 tial problem in  brackish  or
                                 salt water areas.

                                 Little anticipated at ground
                                 level.
                      No limitation
                                 Less serious than mechanical
                                 draft towers, but still  poten-
                                 tial problem if very close  to
                                 sensitive area; noise can be
                                 attenuated.

                                 350-600 ft.; potential aviation
                                 pro!.lem in specific locations;
                                 compiv with FAA restrictions.
                                   1-3  acres per kwh of capacit''
                                   depending on climatic conditions;
                                   use  of spray modules reduces
                                   land requirement by approximately
                                   a  factor of 10.
                                   Applicable only with use of spray
                                   modules; drift only in ijnmediate
                                   area  of pond, canal, etc.
                                   Potential  local problem depending
                                   on  location  & climatic conditions.
                                    Higher than land require-
                                    ments of mechanical draft
                                    wet cooling tower.
                                                                                          No limitation
                                                                     Potential problem only if
                                                                     adjacent to sensitive area; can
                                                                     be reduced by attenuation devices.
                                                                                                                            No limitation
Water Consumption
                      Up to 0.7 gallons per
                      produced.
                                             kwh
                                 Up to 0.7 gallons per  kwh
                                 produced.
                                  Up  to 1.1 gallons per kwh
                                  produced; includes natural evap-
                                  oration from surface.
Energy Requirements
Max. wind Velocity

Foundation Require-
ments
Turbine Back Pres-
sure(Present units
limited to 5 in. Hg)


Aesthetic Consider-
ations
Fan power - 5-13 Hw per million
GPM  of circulating water; pump-
ing power - 7-12 Mwper million
GPM of circulating water.
No limitation
                                                       Pumping power - 10-15 Mw per
                                                       million GPM of circulating water;
                                                       no fan power required.

                                                       Current design -120mph @ 30ft. elev.
Greater than 3000 psf soil bear- Greater than 6000 psf bearing
ing value or equivalent with piles, value or equivalent with piles.
                                  Pumping requirements vary with
                                  plane conditions; spray modules
                                  generally 75 HP per unit.


                                    No limitation

                                    No limitation
Applicable to all plants;penalty Generally app3 icable only to      Applicable to all plants; penalty
for operation at back pressure   plants  above 500 Mw ; penalty for for operation at back pressure
above original design.           operation  at back pressure above above original design.
                                 original design.
visual plume.
                                 visual plume; size and height.
                                                                     No  limitation
                                   Total power requirement - .02-.08Mw
                                   per installed Mw capacity.
                                   No limitation

                                   Greater than 3000 psf soil bearing
                                   value or equivalent with piles.

                                   Not applicable to existing plants;
                                   results in back pressure of 8-15 in.
                                   Hg during summer months; new plants
                                   will require turbine re-design.

                                   No limitation

-------
adjacent tower or other heat  source.   These  problems  are
nonexistent  on  hyperbolic  towers because of the height of
vapor discharge.

The magnitude of recirculation is dependent  primarily  upon
wind  direction  and velocity, tower length, and atmospheric
conditions.  Other  factors  are  fan  cylinder  height  and
spacing,  exit  air  velocity,  tower height and the density
difference between exit air and ambient air,

A longitudinal wind tends to carry  discharge  vapors  along
the  tower  and  the  first  few cells will not be seriously
affected.  However, from the initial downwind point of entry
into the louver face or faces, the effect  of  recirculation
becomes  increasingly  severe along the length of the tower.
Therefore, as tower length increases, the  more  damaging  a
longitudinal wind can become.

A  broadside  wind  causes  no recirculation on the windward
side of the tower.  Recirculation is  greatest  towards  the
midpoint  on  the  leeward  side.  It diminishes towards the
ends because of fresh air flow around the ends of the tower.
High stacks and maximum space between stacks serve to reduce
the broadside recirculation  effect  in  proportion  to  the
ratio of this free space area to the lee side louver area of
the tower.

It is apparent that recirculation is primarily a function of
tower  length.   Normally,  placement  of single towers with
ambient winds in a longitudinal direction is recommended for
tower lengths up to 200 to  250  feet.   For  tower  lengths
greater than this, more rigorous study of the aforementioned
factors  affecting  the circulation is required to determine
the most suitable orientation.  When  tower  length  exceeds
300  to  350  feet,  strong consideration should be given to
splitting into multiple units.   The  problem  then  becomes
more   a   matter   of   locating   the  units  to  minimize
interference.

The  principal  objective  in  arranging  a  multiple  tower
installation   is   to   orient   the   units   for  minimum
recirculation within  themselves  and  minimum  interference
between  each other, particularly during the high capability
requirement  periods.   No  set  rules  can  be  given   for
orientation  of  multiple  units,  but  generally, it can be
stated that as the number of units increases, the  broadside
arrangement  tends  to  be more favorable than longitudinal.
Each installation should be analyzed for orientation  within
the  prescribed  real estate limitations with respect to the
following factors:  (1)  number  of  towers  in  system,  (2)
                             630

-------
number  of  cells per tower, (3) cell length and height, (U)
height and spacing of stacks, (5) discharge air velocity and
density,  (6)   ambient  atmospheric  conditions,   and   (7)
prevailing  wind  rose for high wet-bulb hours.  See Figures
B-VIII-20,  and  B-VIII-21  for   possible   broadside   and
longitudinal multiple tower orientations.

The  natural  draft tower, which varies in diameter from 108
to 168 meters (350 to 550 feet)  normally  requires  a  clear
area  30  m (100 feet) wide around it perimeter to allow for
construction.   This amounts to a land area  twice  the  plan
area  of  the  tower.   For nuclear units, the tower must be
separated from the reactor buildings by a distance equal  to
its height.

If  land space is restricted, any number of solutions may be
used.  Rearrangement  of  mechanical  draft  towers  to  fit
space,  or  use  of  a mechanical draft tower of a different
configuration, such as round, might be used.  Natural  draft
towers  might require less land.  A single large tower might
take the place of two smaller, more  economical  ones.   The
fan-assisted natural draft tower appears to be a system with
minimum  land  requirements.  One existing plant, located in
an urban area, is installing one of these towers in a former
parking lot.  An analysis of land estimated to  be  required
for  evaporative  cooling  towers  at  eight  nuclear plants
indicates that 20 acres/1000  megawatt  generating  capacity
would be the maximum amount required.

The  Federal  Power Commission, National Power Survey (196<4)
puts the land requirement for mechanical  draft  evaporative
towers  at 1,000 to 1,200 square feet per megawatt including
area  required  for  spacing.   Furthermore,  natural  draft
evaporative  towers would require 350 to UOO square feet per
megawatt.  For a 1,000  megawatt  capacity  tower  requiring
1,200  square  feet  per megawatt, approximatley 28 acres of
land would be required.

Land requirements reported  by  other  sources  for  various
cooling methods are summarized by Reference 385 as follows:

     Cooling Ponds                 1000-3000 acres/lOOOMw
     Jet Spray Ponds                 50- 300 acres/1000Mw
     Natural Draft Wet Towers         U-   5 acres/lOOOMw

Due  to  the variations in heat rate, climatic factors, etc.
from site-to-site, 28 acres per  1,000  megawatts  generating
capacity  should  be  sufficient land for any plant to apply
closed-cycle evaporative  cooling  towers.   In  many  cases
where  less  than this amount of land is available, it would
                              631

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             Prevailing wind-rose for
             high wet-bulb hours
                   Figure B-VIII-20
       BROADSIDE MULTIPLE TOWER ORIENTATION

Tower No. 2 placed typically in location a,b, or c
         relative to Tower No. 1 and the wind-rose
                          632

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CO
CO
                        \
                           \
                 Figure B-VIII-21

       LONGITUDINAL MULTIPLE TOWER ORIENTATION

Tower No. 2 placed typically in location a,b, or  c
     relative to Tower No. 1 and the wind-rose
                                         Prevailing wind-rose for
                                         high wet-bulb hours

-------
still be practicable to apply evaporative cooling towers due
to the conservatism  of  the  28  acres  per  1000  megawatt
assessment  and, further, due to the possible practicability
of natural draft or other systems at the site.  Many  plants
which do not have land immediately available for evaporative
cooling  systems  could  make  sufficient  land available by
shifting, to some degree, present uses of land at  the  site
and   by  acquiring  the  use  of  neighboring  land.   Land
reguirements for other uses would depend on  the  types  and
relative  amounts of fuel, method of ash disposal, and other
factors in addition to plant generating capacity.

Reference 370 addresses the land requirments  for  projected
3,000-megawatt  plants as compared to 1,500-megawatt plants.
The land required for a  powerhouse  containing  three  500-
megawatt  units  is  in the range of 3 to 4 acres; for three
1,000-megawatt units the range  is  6  to  7  acres.   These
figures include the service bay, but not space for equipment
and   facilities   outside  the  powerhouse.   Electrostatic
precipitators, stacks, walkways, drives, and  parking  areas
immediately  adjacent  to  the powerhouse would be about 2-3
acres for three 500-megawatt units and 6-7 acres  for  three
1000-megawatt units.  Sulfur dioxide removal equipment would
add  as  much  on  2-4  acres.   Coal-fired  plants  require
inactive coal storage in an amount to supply 45 - 120  day's
burn  at  the  total plant capacity.  A typical coal-storage
yard to provide 90 days supply  at  a  3,000-megawatt  plant
would  require  40  acres and the coal pile would be 40 feet
high.  The switchyard area requirements for a typical 3,000-
megawatt plant with 500-kv transmission voltage would be  in
the range of 10-15 acres.  The transmission lines connecting
a   typical   3,000-megawatt   plant   with   the   existing
transmission  system   at   500   kilovolts   would   occupy
rights-of-way  of  from  100 to 150 acres per mile.  On-site
ash disposal for a 3,000-megawatt coal-fired plant  (assuming
35 year useful life and 50% capacity factor)  would  require
300  to  400  acres  with ash piled to a depth of 25 feet to
store all the ash developed during the life  of  the  plant.
Limestone-injection  systems  for controlling sulfur dioxide
emissions would double or triple the volume of ash  produced
while  the  system  is in operation.  In some cases off-site
disposal of ash would be an available alternative to on-site
disposal.

Other facilities that would require significant  amounts  of
land  include rail, barge and truck terminals for coal-fired
and oil-fired plants, oil storage for oil-fired plants,  and
an  exclusion area for nuclear plants.  In summary, a 3,000-
megawatt plant would require, if  coal-fired,  200  to  1200
acres,  nuclear  200-400 acres, oil-fired 150-350 acres, and
                              634

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gas-fired 100 to 200 acres, assuming cm-site storage of coal
and oil, pipeline delivery of gas with some on-site storage,
and on-site coal-ash disposal.


In spite of the ingenuity of  the  cooling  tower  engineer,
there  may  be a significant number of units or plants where
addition of a cooling tower would not  be  practicable.   In
the case of a plant in a location where the surrounding land
is  already highly developed, the cost of available land may
be high, and it might be necessary to  remove  any  existing
structures  from the land, once it was purchased.  Secondary
effects, such as fogging or drift could result in complaints
from surrounding neighbors, as  well  as  a  requirement  to
repair  resulting damage.  Noise levels from the tower might
be unacceptable to the  neighbors.   The  number  of  plants
located in the 50 largest metropolitan areas amounts to some
15%  of  the  total  (see  Table IV-3).  An equal number are
probably located within the  city  limits  of  small  towns,
particularly  in  the Great Plains states.  The practicality
of installing  cooling  towers  will  depend  on  the  local
conditions  at  each  plant.   One may be surrounded by high
rise buildings, while the next may be adjacent to  a  vacant
city  block.  Another plant may be .01 a heavy industrialized
area, whereas another would be in  a  semi-residential  area
where  the  tower  noise aspect may be more sensitive.  Land
values will vary  greatly,  from  possibly  $25,000  per  ha
($10,000  per  acre)  in  small  towns  to $2,500,000 per ha
($1,000,000 per acre) in the center of a large  metropolitan
area.

In  a  case  where  28  acres  would need to be acquired for
cooling towers at a 1000 Mw plant, at $36,000 per acre,  the
added  land  cost of $1,000,000 would be less than 5X of the
other capital costs of the towers at $22/kw ($22,000,000).

Reference 446, reporting results of a  survey  of  utilities
concerning  land  availability  for cooling towers and other
factors, found that sufficient land  was  considered  to  be
available in 75X of the plants sampled.

Nuclear  plants  would not normally be seriously affected by
land area limitations for two reason.  They are not  located
in  metropolitan  areas,  and  the  required  exclusion area
normally  provides  sufficient  area  for   cooling   system
installation  unless topographic conditions are unfavorable.
However, when a nuclear  plant  goes  from  open  to  closed
system cooling, the low-level radwaste system normally needs
to  be  upgraded.  With the open system, low-level radwastes
are added to the circulating  water  for  dilution  to  meet
                              635

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standards  for  the discharge of radioactive materials.  The
blowdown stream may not be sufficient for dilution,  forcing
installation  of  a  new low-level radwaste system.  Cost of
this has been estimated to be several million dollars at one
nuclear plant.

Non-Water Quality Environmental Impact of Control and
Treatment Technology

The potential non-water quality environmental impacts  which
could influence the type of system selected or which must be
minimized in certain cases include these listed below.

1.   Drift.,  resulting  in  salt  deposition  on surrounding
areas.

2.  Fogging, visual impact and safety hazards.

3.  Noise levels unacceptable to neighbors.

U.  Height, creating aviation hazards.

5.  Water consumption by evaporative systems.

6.  Aesthetic  considerations,  visual  impact  of   cooling
device.

The influence of the majority of these factors on the selec-
tion  and  cost of the installation of these cooling systems
is summarized in Table B-VIII-21, with a detailed discussion
below of some of the factors not discussed elsewhere in this
document.
Drift

Water vapor and heated air are not the only effluents from a
cooling tower.  Small droplets of the cooling  water  become
entrained in the air flow, and are carried out of the tower.
These  drops have the same composition as the cooling water,
i.e., they  contain  the  same  concentration  of  dissolved
solids   and  water  treatment  chemicals.   The  water  may
evaporate from the drops, leaving the solids behind, or  the
drops   may  impinge  upon  the  surrounding  structures  or
terrain.  The chemicals and dissolved solids add a  chemical
load  to  the air and surrounding terrain that must be taken
into account.
                              636

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Some data on estimated solids in drift from  cooling  towers
are shown in Table B-VIII-25.  This was taken from the final
environmental  statements  for a number of nuclear stations.
There is obviously a large variation in  the  assumed  drift
rates.   All  these  values are mentioned in the literature/
with the lower values the more recent.   Another  factor  is
the  concentration  of  solids  in the drift.  It is obvious
that the proposed towers at Plant no. 1209, operating on sea
water, will have a higher  solids  loss  through  drift,  as
indicated in Table B-VIII-25.

The  amount  of drift from any tower is primarily a function
of  the  tower  design,  and  the   drift   eliminators   in
particular.    The   total  losses  to  drift  are  normally
expressed as a percentage of the  flow  through  the  tower.
Until   recently,  drift  losses  of  less  than  0.256  were
guaranteed.  »*°  Now  cooling   tower   manufacturers   are
guaranteeing  much  lower drift losses.  Losses of 0.02S are
considered high.  Several new towers have been awarded based
on drift guarantees in the range of 0.002 - 0.005 percent of
cooling water flow.  A number  of  tests,  summarized  in  a
report  for  EPA  by  the  Argonne  National Laboratory, 2«*
showed that  drift  from  mechanical-draft  towers  averaged
0.005%,  while  that from natural-draft towers might average
half of that, or 0.0025X.  With a 0.01X drift eliminater, an
estimated 1 ton of salt per day would be deposited  downwind
of a 1,000 megawatt nuclear unit.

While  better  design is partially responsible for the lower
drift rates, better measurement techniques are  equally,  if
not  more  important  in establishing drift rates.  With the
older, less sophisticated methods, manufacturers  were  less
sure  of the actual drift rates, resulting in high rates for
guarantees.

With the greater emphasis on  environmental  protection,  it
became  necessary to measure drift more accurately to deter-
mine the amount of solids leaving the tower  to  end  up  as
fallout  on  the  surrounding  terrain  or  suspended in the
atmosphere.  Currently at least two systems  are  available.
The first, the Pills System, is for continuous monitoring of
drift.   The  second  is  a  system  for  sampling the drift
intermi tt ently.

The  Pills   (Particle   Instrumentation   by   Laser   Light
Scattering).  system   is   an  electro-optical  system  for
monitoring the drift.

The intermittent sampling system is  an  isokinetic  device.
The discharge air is sampled at its natural flow velocity as
                           637

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                                        TABLE B-VIII-25
                              SOLIDS IN DRIFT FROM COOLING TOWERS

Plant
No.

1209
1311
3608
6506
3940
0109
3635

Size
Mw

1320
1644
873
850
872
1722
821

Cooling System
(Type )
Mech . Draft
(salt water)
Mech. Draft
Nat. Draft
Nat. Draft
Nat. Draft
Mech. Draft
Mech. Draft

Drift
(% Flow)

0.1
0.2
0.0025
.01
.01
.01
.005
i
Solids in Drift
Ibs ./yr .

3.8 x 107
6 x 105
1.1 x 106
4.0 x 105
9.0 x 104
10.5 x 105
4.7 x 104
Ibs/kwh
(installed)xl°

3.3
.042
.14
.054
.012
.070
.0065
CTl
CO
OO

-------
implied  by  the  term  "isokinetic".   One  device  uses  a
sampling tube filled with  warmed  glass  beads.   A  vacuum
system  pulls  the  sample into the tube where the drift im-
pinges on the glass beads.  The moisture evaporates, leaving
the solids behind.  Weighing of the sample  tube  determines
the  solids collected.  This, plus a knowledge of the solids
contents of the water, permits calculation of the amount  of
drift.   This  device  supersedes a number of isokinetic de-
vices  considerably  more  cumbersome,   and   of   doubtful
accuracy.

Drop  size  is  another  problem.  Sensitive paper, and more
recently, the Pills system »*"  are  used  to  measure  drop
sizes  of  100  micron  or  larger.   Several  tests  by one
manufacturer indicate that the drops accounting for  85%  of
the  mass  of  the  drift  have  diameters  greater than 100
microns, with less than IX over 500 microns.

The drift from cooling towers, mechanical  draft  in  parti-
cular, potentially can create serious problems, depending on
the salts and chemicals in the cooling water.  Drift coating
insulators  on the transformers and switchyards can possibly
lead  to  leakage  and  insulator  failure.   Corrosion   of
metallic  surfaces,  deterioration or discoloration of paint
and killing  of  vegetables  have  been  noted.   Thus,  the
minimization  of drift is an important design feature of the
cooling tower.

The use of brackish or seawater in cooling towers aggravates
the drift problem due to the high concentration of  salt  in
the  water.   Fifteen saltwater cooling towers are in use or
planned for steam electric  powerplants.   Numerous  factors
affect  the  dispersion  and  deposition of drift from these
towers  (See Table  B-VIII-26),38S  Proper  location  of  the
towers  with  respect to the plant buildings and switchyards
can avoid most  of  the  problems  encountered  with  highly
saline  drift.   The rate of drift fallout is related to the
distance from the tower.  (See Figure  B-VIII-22) .   This  is
particularly  true  for  mechanical  draft towers which dis-
charge at relatively low levels.

    Although the environmental effects of saltwater  cooling
towers  vary  from case to case depending on the sensitivity
of  local  environment  and  diverse  local   meteorological
conditions,  experience  with  existing  salt  water cooling
towers  indicates  that  environmental  problems  would   be
confined  to  areas in close proximity to the cooling tower.
One study  (Reference U51) showed that about  70  percent  of
all  drift  mass  fell within 400 feet downwind of a typical
saltwater mechanical draft tower, well within the boundaries
                              639

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                                             Table B-VIII-26
                               FACTORS AFFECTING DISPERSION AND DEPOSITION  OF DR
                                 FROM NATURAL-DRAFT AND MECHANICAL-DRAFT  TOWERS
       Factors associated with the design
       and operation of the cooling tower
                                        Factors related to atmospheric
                                        conditions
                                        Other factors
en
*>.
o
Volume of water circulating in the
tower per unit time

Salt concentration in the water

Drift rate

Mass size distribution of drift
droplets

Koist plume rise influenced by
tower diameter, height and mass
flux
Atmospheric conditions including
humidity, wind speed and direction,
temperature, Pasquill's stability
classes, which affect plume rise,
dispersion and deposition.

Tower wake effect which is especi-
ally important with mechanical
draft towers

Evaporation and growth of drift
droplets as a function of
atmospheric conditions and the
ambient conditions

Plume depletion effects
Adjustments for
nonrpoint source
geometry

Collection efficiency
of ground for drop-
lets

-------
c
o
E
0}
fc
6
o
o
m

u.r

K
CO
o
a.
to
.".r
   1000
I 1
     100
      10
              TT—TT
                DIFFUSION
                  METHOD
                       SOSANQUET
                       METHOD
                             GAUSSIAN
                              METHOD
                                   J	I
                             1.0
                                                          HOSI.ER
                                                  _L ....... __ I ____ 1 ___ L.
                                                   10
                                                                        100
                          DISTANCE  DOWNWIND, kilometers

                             Figure B-VIII- 22

               Crouiul-Lnvcl  Salt Deposition Katie From A Natural-Draff Tc-./cr
               As A 1'iip.ctj.on Of The  Distance Do'.:m;incl.  A Comparison I'utwcen
               Various Prediction Method
                                     641

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of most powerplants.  The same study showed that even  under
the  most  adverse conditions, all drift droplets that would
reach the ground would do so  within  1,000  feet  downwind.
The  subject  of  this  study  was a hypothetical eight-cell
crossflow mechanical draft tower designed  to  cool  134,000
gallons   per   minute  of  water  with  the  same  chemical
composition and salinity as seawater.  The plant was assumed
to be located on an estuary  or  bay,  two  miles  from  the
ocean.   The drift rate was 0.004 percent of the circulating.
water.

    Airborne drift from this tower plus  natural  background
salt  nuclei  from  the  sea  exceeded  conservative  damage
thresholds for foliar injury for distances up to 2,200  feet
downwind   of   the   tower.   The  background  salt  nuclei
contributed over 75 percent of the salt mass causing  damage
at  this  distance from the tower.  Moreover, the fractional
increase in airborne salt concentrations  due  to  drift  at
2,200   feet  was  insignificant  as  compared  with  normal
variations in the background  level  caused  by  changes  in
atmospheric wind conditions.

    Obviously,   local   plant  life  in  areas  potentially
affected by salt  drift  frcm  towers  must  be  capable  of
withstanding  these natural airborne salt levels if they are
to survive.  Other possible recipients of . incremental  salt
drift  would  likewise  be  affected  by the natural ambient
levels.

    The  additional  cost  of  drift  eliminators  does  not
represent  a  significant  increment to total cooling system
cost and should be reflected in the cost estimates  supplied
by  the  industry for plants representing over 12 percent of
the Nation's total generating capacity.

Wistrom and Ovand36* concluded, from their  study  of  field
experience  during  the last 20 years where salt or brackish
water has been used in cooling towers, that  "cooling  tower
drift  effects  in  the  environment  are localized and that
beyond same reasonable distance that is usually  within  the
plant site boundary, drift does not significantly affect the
environment".

The  fact  remains  that  this salt will be deposited on the
surrounding terrain.  Whether or  not  this  influences  the
environment,  i.e.,  vegetation  and  ground water salinity,
will depend on the increase over the natural  deposition  of
salt  on  the  surrounding  terrain.  The natural salt load,
particularly along ocean coasts exposed  to  continual  wave
action, can be fairly high.  If the tower drift results in a
                               642

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salt  load  of  only  a  few  percent  of  this natural salt
deposition rate, the effect would probably be minimal.

A summary  of  the  state-of-the-art  of  saltwater  cooling
towers  (Reference  No.  385)   concluded  that "although the
environmental effects of saltwater cooling towers vary  from
case to case depending upon the sensitivity and diversity of
local   conditions,  experience  with  existing  salt  water
cooling towers indicates  that  the  environmental  problems
would  be  confined  up  to several hundreds meters from the
cooling tower." Environmental impact on the biota, bodies of
fresh water, soil salinity and structures  is  difficult  to
detect  at  the  levels  of the long-term average in coastal
areas.  The direct experimental  data  available  about  the
environmental effects are sparse.  Most of the environmental
impact predictions are based upon research studies pertinent
to  the  coastal  environment,  which  may  or  may  not  be
applicable for salt water cooling towers in other locations.
Most of this available information is descriptive in  nature
and  does not permit a correlation between the airborne salt
concentration or deposition rate and environmental effects."

Adverse  environmental  impacts  due  to  drift  are  not  a
national-scale   problem.    Technology   is   available  to
integrate a low drift requirement  into  the  overall  tower
design  at  moderate  cost.   In addition, alternate cooling
systems selection and proper  location  of  the  tower  with
respect  to  prevailing  winds and surrounding land uses can
also be used to  meet  stringent  drift  requirements.   New
plants  have the additional flexibility of site selection to
help minimize this problem.

Fogging

Fogging is one of the most noticeable of the  possible  side
effects  of  the use of evaporative cooling devices.  Fog is
produced when  the  warm,  nearly  saturated  air  from  the
cooling  facility mixes with the cooler ambient air.  As the
warm air becomes cooler, it reaches first  saturation,  then
supersaturation  with  respect to water vapor content.  When
this occurs, the vapor condenses into visible  droplets,  or
fog.   The  psychrometric  chart  in  Figure B-VIII-23 shows
representative  conditions  through  which   the   air-water
mixture can pass to create fog.  The condition at point B is
that  of  the  ambient  air.   As this air leaves the tower,
(point A)  it mixes with the colder, less humid  ambient  air
following  the dotted line which lies largely in the portion
of the chart which represents  a  condition  where  the  air
contains   more   moisture  than  it  can  contain  at  100X
saturation.   In  this  condition  condensation  can  occur.
                               643

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                                                            Saturation

                                                             (100%  RH)
-P .H
-H

T) X
•H —


3 l-i
33 -H
  n)
O
-H -a
o
0) A
20 -
          15 .
          10 .
                                                           80% RH
                     20       40      60       80     100

                        Dry Bulb Temperature  (°F)
                                                    120
                            MODIFIED PSYCHROMETRIC CHART

                                (From Reference  128)

                                  FIGURE B-VIII- 23
                                    644

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producing  fog  although  normally  some  supersaturation is
necessary.   As  more  mixing  occurs,  the  air   condition
eventually returns to point B.

The  development  of fog by cooling devices is primarily de-
pendent  on  the  local  climatic  conditions.   The   areas
normally susceptible to cooling tower fog are those in which
natural fogs frequently occur.  EG £ G, Inc. in a report for
EPA,  219, defines three levels of potential for fogging, as
listed below.

    a»  High Potential!  Regions where heavy fog is observed
    over 45 days per  year,  wh^re  during  October  through
    March the maximum mixing depths are low (400-600 m), and
    the  frequency  of  low-level inversions is at least 20-
    30%.

    b.  Moderate Potential;   Regions  where  heavy  fog  is
    observed  over  20  days  per year, where during October
    through March the maximum mixing depths  are  less  than
    600  m,  and the frequency of low-level inversions is at
    least 20-30%.

    c.  Low Potential;  Regions where heavy fog is  observed
    less  than  20  days per year, and where October through
    March the maximum depths are moderate to high (generally
    greater than 600m).

Using this criteria and several  meteorological  references,
EG&G  has  developed  the  map  shown  in  Figure B-VIII-24,
indicating the fogging potential  of  locations  within  the
United States.

The length of the expected fog plume can be estimated from
the following equation: »s

    Xp = 5.7(Vg)°«s (320Vw)-o«s (Tge-Tgi) o«s  (Tp-Tgi)-°«s


Where Xp = visible plume length, ft

      Tg = air or plume temperature, °C

      Tp = temperature at end of visible plume, °C

      Vw = wind speed, ft/sec

      Vg - total rate from tower cu m/hr (gas evaluated at 20°C)

       i - tower inlet

       e = tower exit
                               645

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HIGH  POTENTIAL


MODERATE POTENTIAL


SLIGHT POTENTIAL
                                            Figure  B-VIII-24

                     GEOGRAPHICAL  DISTRIBUTION  OF  POTENTIAL  ADVERSE EFFECTS FROM COOLING TOWERS,
                       BASED ON FOG, LOW-LEVEL INVERSION AND LOW MIXING DEPTH FREQUENCY.

                            (From Reference 219)

-------
In  order  for  fogging to create an impact it most exist in
close proximity to a land use with which it  interfers  such
as  a  major residential, commercial or industrial activity.
As can be seen from Figure B-VIII-2U, most of the major U.S.
residential, commercial and industrial centers do not lie in
the areas of high fogging potential.

Furthermore, local meteorology and the configuration of  the
source and its surroundings must permit a downwash condition
to  obtain  fogging.   These  will  not usually exist if the
cooling tower if properly designed and located.

In view of these factors a conservatively high  estimate  of
the  plants  that  would  be concerned with fogging problems
resulting from the installation of closed cooling systems is
less than 5 percent of the total plants.  Moreover,  fogging
would  only  be of concern at the plants for small fractions
of the total operating time,


The fog plume from a mechanical draft tower is emitted close
to the ground, and under appropriate conditions, can drop to
the ground.  Under these conditions the  fog  can  create  a
serious  hazard  on  nearby  highways.   If  the  fog passes
through the switchyard, insulator leakage  problems  can  be
encountered.  Thus, in addition to being highly visible, the
fog  plumes  create  safety hazards and accelerate equipment
deterioration.   Careful  placement  of  the   towers   will
eliminate   most   of   the   problems.    If  placement  is
unsatisfactory, or creation of hazards  is  still  expected,
the  use  of  a  wet-dry  tower can significantly reduce the
plumes.  In the wet-dry tower   (typically)  ambient  air  is
heated from point B (See Figure B-VIII-23) to point C in the
dry  section.   Air  from  the wet section  (point A) and dry
sections are mixed and exhausted at a condition  represented
by  point  A*.   In  mixing  with  ambient air  (dotted line)
subsaturated conditions exist and fogging cannot occur.  Two
towers of this type are currently on  order  or  under  con-
struction for large generating plants in the U.S.  It should
be  noted  ,however,  that this type of tower is more costly
than the conventional wet-type tower  (approximately  1.3  to
1.5 times the cost of a conventional tower).  This would add
an  increment  of  approximately  0.15  mills/kwh  for plume
abatement for a large, modern base-load unit.  While wet-dry
towers are more costly than  conventional  wet  towers,  the
cost of employing plume abatement in specific cases has been
accounted for in the general analysis of the cost of cooling
                             647

-------
tower  construction.   The general analysis is based on cost
data supplied by industry, which were,  in  turn,  developed
from a sample of 60 plants and units and the costs for 18 of
the  units  in  the  sample  reflected  the  use  of wet-dry
towers.*47 Other  possible  techniques  of  plume  abatement
include   increasing  the  mechanical  draft  stack  height,
heating  tower  exhaust  air  with  natural   gas   burners,
installing  electrostatic precipitators or mesh at the tower
exit, and spraying chemicals at the tower exhaust.

Another possible solution is to use a  natural-draft  tower.
The  plumes from these towers are emitted at altitudes at 90
to 150 meters (300 to 5001) above the  tower  ground  level,
and there is little possibility of local fog hazards, as the
plume  is normally dispersed before it can reach the ground.
One hazard that might arise would be to aircraft  operation,
although  plumes are normally localized.  The use of natural
draft cooling towers in high potential fog areas seems to be
an accepted practice, as indicated in Figure B-VIII-25  z«3,
which shows  the location of 75% of the natural draft towers
expected  to  be  constructed  through  1977.  Note that the
majority of them  are  in  the  eastern  area  of  high  fog
potential.   Under  freezing  conditions the fog may turn to
ice upon contacting a freezing surface.  The ice thus formed
is commonly called rime ice.  This is  a  fragile  ice,  and
breaks  off  the  structure  before  damage  occurs from the
additional weight,  except  on  horizontal  surfaces.   Here
again,  although  it  is  mentioned  in  the literature, the
problem is considered to be insignificant.

The potential for modification of regional  climate  exists,
but  has  not been verified to date.  The Illinois Institute
of Technology Research Institute in its report 2a3  for  EPA
on  the  field  tests  at Plant no, U217 in Pennsylvania de-
termined  that  the  effects  were  minimal.    This   plant
evaporates  approximately  0.63 cu m/s  (10,000 gpm) of water
and releases approximately 0.5 x 10* kg  cal/s   (120  x  10«
btu/min)   of  heat to the atmosphere when operating at 1U40
Mw, 80% of its design capacity.  Two  natural  draft  towers
are  installed  at  Plant  no.  4217.   A  review of weather
station records at stations located 13 to 51 kilometers from
the plant resulted in Ma  suggestion  of  precipitation  en-
hancement".   Initiation of cloud cover occurred rarely, and
only preceded  natural  development  of  cloud  cover.   The
cooling tower plume would merge with low stratus clouds when
they were at an appropriate elevation.

The  current  "state-of-the-art11 in meteorology has not pro-
gressed to the point where  the  effects  of  large  thermal
releases  to the atmosphere can be quantitatively evaluated.
                              648

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vo
                                           Figure B-VIII-25
                         LOCATION OF NATURAL DRAFT  COOLING TOWERS THROUGH 1977
                                          (From Reference  283)

-------
Improvements in meteorological techniques currently in  pro-
gress  will  undoubtedly  result  in quantification of these
effects.  A number of meteorologists indicate  that  thermal
emissions  to  the atmosphere could have significant effects
on mesoscale phenomena, where mesoscale refers to a scale of
from 1 to 50 kilometers.  A comparison of some  natural  and
artificial energy production rates is shown in Table B-VIII-
27.  3*7   It  is  obvious  that  some  of  our artificially
produced energy rates are equal in  magnitude  to  those  of
concentrated natural production rates.

It  is  possible  that  these  thermal discharges may have a
"triggering" effect on a  much  larger  phenomena,  such  as
thunderstorms,  tornados,  or  general cloud development and
precipitation.  This could prove  beneficial  if  the  trig-
gering   could   be   adequately  controlled,  and  possibly
disastrous if control was not possible.

Although no regional climatic changes  have  been  noted  to
date,  this  does  not  mean the possibility does not exist.
with larger and larger stations  being  built  which  reject
their  heat to the atmosphere through wet cooling towers, it
becomes evident  that  this  water  must  be  added  to  the
rainfall  at some location, wherever it may be, and that the
additional heat will influence the  climatic  conditions  to
some  extent.   This  probably  falls  into  the category of
weather modification, even though it be  unintentional,  and
is currently being investigated by meteorologists.

With  coal-fired or oil-fired plants, there is an additional
factor in relation to plumes.   The  stack  gases  of  these
plants  contain  varying  amounts  of  SO2,, depending on the
sulfur content of the fuel used and the degree of  flue  gas
desulfurization  achieved.   To  the  extent  that the stack
gases and the cooling  tower  fog  plume  became  intimately
intermixed,  the  fog will interact chemically with the SO£,
forming sulfuric  acid.   This  is  a  corrosive  acid,  and
settlement   on   surrounding   buildings   will  accelerate
deterioration. Vegetation will  also  be  affected  by  this
"acid  fog".   The  relationship  between the two discharges
should be such as to minimize their intermixing.

In addition to the basic meterological  considerations,  two
other  factors  should be considered where stack and cooling
tower plume intermixing must be minimized, as follows:   (1)
location  of  the  cooling towers in relation to the stacks,
and (2)   the buoyancy of the plumes as related to the  stack
and tower heights.  A further consideration is that in cases
when   the   plumes   would   intermingle,  they  would  not
necessarily become intimately mixed.  In  the  case  of  the
                            650

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                                          TABLE B-VIII-27
         ENERGY PRODUCTION  OF SOME NATURAL AND ARTIFICIAL PROCESSES AT VARIOUS SCALES  (367)
Area
(m2)
5 x 1014
1012
108
104
Natural Production
Event
Solar energy absorption
by atmosphere
Cyclone latent heat
release (1 cm rain
per day) .
Thunderstorm latent heat
release (1 cm rain per
30 min)
Tornado kinetic energy
production
Rate
(W/m2 )
25
200
5000
104
Artificial Production
Type of Use
Man's ultimate energy
production
Northeast U.S. ultimate
production (108 people,
20 kw each)
Super energy center or
city
Dry cooling tower for
1000- Mw (e) powerplant
Rate
(W/m2)
0.8
2.0
1000
105
cr

-------
study  of  plant  no.  4217,  cited previously, measurements
suggested that the plumes were not uniformly mixed  and  may
have been merely co-mingled.

In  any  case,  since hundreds of evaporative cooling towers
have been operated over many years at  coal-fired  and  oil-
fired  stations  scattered  across the United States without
significant numbers of reports of  adverse  impacts  due  to
"acid  fog",  the  engineering  and  other  design practices
employed should be adequate to assure that this problem does
not arise in subsequent applications of evaporative  cooling
towers.

In summary, potential adverse impacts due to fogging are not
a  national-scale  problem.  In the relatively few instances
where it could be a problem, technology is available,  at  a
moderate  incremental  cost, to control or eliminate fogging
to the degree required by the related considerations.

Noise

Noise created by the operation of  cooling  towers,  results
from  the large high-speed fans.  The enormous quantities of
air moving through restricted spaces, and large  volumes  of
falling water contacting the tower fill and cold water basin
also  create  noise.   Mechanical draft towers will generate
higher noise levels than natural  draft  towers.   At  sites
where the incremental noise due to cooling towers might be a
problem,  it  should  be considered in the design of cooling
tower installations.  A three step procedure usually results
in adequate coverage of this problem.

1.  Establish a noise criteria that will  be  acceptable  to
the neighbors within hearing range of the proposed tower.

2.   Estimate  the  tower  noise levels, taking into account
distance to neighbors, location  of  the  installation,  and
orientation of the towers.

3.   Compare the tower noise level with the acceptable noise
level.
Only if the tower noise level exceeds the  acceptable  noise
level need corrective action be taken.

All  cooling  towers  and powered spray modules produce some
noise.  The noise from powered  spray  modules  and  natural
draft  cooling  towers  is primarily from the falling water.
In the mechanical draft dry tower there is the fan noise and
                              652

-------
possible noise from high velocity flow of the water  through
the cooling surface.

Since  the  powered  spray modules are normally located in a
canal, the banks tend to direct the sound  upward,  and  the
bank  surface  can  absorb  part of the sound.  Their use to
date has not created serious noise problems.

The noise level from cooling towers is of the same order  of
magnitude as that in the rest of the station, and thus noise
from both sources can be a problem in noise sensitive areas.
Every  effort  should be made to place these structures away
from potential sources of complaints.  Sound levels decrease
with the square of distance from  the  source.   Large  flat
wall surfaces can direct sound into sensitive areas.  At the
same  time,  walls and buildings can act as a sound barrier.
Fan speeds can be reduced at night when load is  lowest  and
when  ambient  noise  levels  may  also  be  lowest.  Proper
attention to noise problems in tower design, selection,  and
placement can avoid costly corrective measures.

It  is possible to decrease fan noise about lOdB by reducing
tip speed  from  12,000fpm  to  8,000fpm.   This  reduction,
however,  would be possible only if the fan being considered
had the capability of handling 125* more  pressure  and  50%
more  flow  without  stalling.  A rough estimate of fan cost
versus decibel reduction is shown in  Figure  B-VIII-26.   A
lU-ft  fan  was  used in the analysis but the costs would be
proportional for any fan.455

If the above procedures are unable to reduce noise levels in
the affected areas to acceptable levels,  sound  attenuation
can  be  done  by  modification  or  addition  to the tower.
Discharge baffles, and acoustically  lined  plenums  can  be
used.   Barrier  walls, or baffles can be erected.  Adequate
noise suppression is normally possible, but the cost can  be
high.   Good  practices can minimize the expense involved in
noise suppression.

It is recognized that incremental costs  would  be  incurred
where  mechanical  draft  cooling  towers  may require noise
control.  Little information is available  on  the  cost  of
implementing  noise control procedures on powerplant cooling
towers principally because it has rarely been  necessary  to
employ  these measures, even though powerplants with cooling
towers exist in areas of high  population  density.   It  is
doubtful  that  there  will  be  a significant need for this
technology  as  a  result   of   technology-based   effluent
limitations  on  heat,  since  many  plants in areas of high
population density would be exempted because of the lack  of
                              653

-------
.1,5 WJ
3,000
2,500
2,000
1,500
1,000
500
0






12M














X
10M





_^x





S*





>
s
w..t





/
	
J
/


/to



Tip «peed
17.000 fpm
10.000 fpm
9,000 fpm
C.OOO fpm
4,000 fpm
• 14-h-dion>.el:r !.in>
1

-
           106  104   102   100   98   96    94   92   90
                          Hemispherical PY/l dbA
Figure B-VIII-26
Fan  Cost Versus Noise Reduction
Reference  455
                    654

-------
sufficient land for closed-cycle cooling systems, because of
the salt drift exemption, or because of the exemptions based
on  age  or  size.  Furthermore, alternative thermal control
technologies may be employed that are generally quieter than
mechanical draft cooling towers.  In the only case cited  by
comments  on  the  proposed effluent limitations, guidelines
and standards, a plant in West Germany was reputed  to  have
incurred  twice  the  normal capital cost for cooling towers
due to the installation of noise control equipment.  This is
a most unusual case indeed.  The  plant  cited  is  in  West
Berlin,  a  politically  land locked community isolated from
outside power sources.  Increased demand and  a  paucity  of
available  sites required that a new plant be constructed in
close proximity to residences in an area of high  population
density,  hence,  the  need  for noise abatement technology.
Furthermore, it is  significant  that  cooling  towers  were
employed  with  noise suppressors in order to take advantage
of the site while accomodating the need to reduce  noise  to
locally required levels.

It  is  concluded  that  adverse  impacts  of noise is not a
national-scale  problem.   Technology  is  available  at   a
moderate  cost to reduce the noise impact of cooling towers.
In addition, alternate cooling system selection  and  proper
locations  of  the  towers  can  be used at highly sensitive
sites.  New plants have  the  further  flexibility  of  site
selection to help minimize this problem.

Height

The height of natural draft cooling towers, up to 183 meters
(600  ft) ,  results  in  a  localized  potential  hazard  to
aircraft.  Location of such a tower would generally  not  be
permitted  in the approaches to an airport.  Other pertinent
FAA restrictions and regulations would have to  be  complied
with.  Aircraft warning lights would have to be installed on
the  tower  along  with  provision  for servicing them.  The
height of alternative technologies would not present hazards
to aircraft.

Consumptive Water Use

All evaporative heat rejection systems result  in  the  con-
sumptive  use  of  water.  The primary consumption occurs as
evaporation and drift.   Even  the  once-through  system  is
responsible  for  consumptive  use  of  water by evaporation
during the transfer of heat from the river, lake or ocean to
the atmosphere, the ultimate receiver.
                              655

-------
Heat is transferred from the river or lake to the atmosphere
by  three   major   means,   radiation,   evaporation,   and
conduction,  with that by conduction being small compared to
the  other  two.   The  Edison  Electric  Institute   report
entitled,  "Heat  Exchange  in  the Environment" •*, gives a
detailed analysis of these processes.

The closed systems, cooling towers and spray ponds,  utilize
the same mechanisms, although their respective contributions
may be much different.  Figure B-VIII-27, taken from a paper
by  Woodson,  3»8  gives  a  graphic  representation  of the
percentages of heat transferred by each process.  In  a  re-
port  prepared  for EPA, »°4 some representative consumptive
use rates for a 1000 Mw unit are shown  (see  Table  B-VIII-
28).  Consumptive use varies from 1.3 to 2.1 times that of a
river or lake, depending on the type of closed system used.

Woodson, in his article, 318 gives a more detailed analysis,
including costs to make up for penalties inherent in the use
of  closed systems as shown in Table B-VIII-29.  Consumptive
use, according to his figures, can be as much as  2.5  times
that of a once-through system.

The  amount  of water consumed depends to some extent on the
climatic conditions existing at the  site.   Some  of  these
factors  and their effect are shown in Figure B-VIII-28. »"
The use of cooling ponds results in the highest  consumptive
use, since the total consumptive loss is equal to the sum of
the  natural  evaporation plus that due to heat rejection to
the cooling pond.   The  increment  of  consumption  due  to
natural  evaporation is approximately the difference between
the consumption of a cooling pond and that of a natural lake
or river.  The consumptive use of water in a natural lake or
river is low, since  the  natural  losses  are  not  charged
against  the  power  station, and in addition, a significant
part of the heat is transferred by radiation.

The dry-type cooling  tower,  as  opposed  to  the  wet-type
cooling  tower, has essentially no consumptive use of water.
The only consumptive use would be losses  from  this  closed
system due to leaks.

In general, the replacement of a once-through cooling system
with  a  closed  system will result in somewhat higher water
consumption from a broad environmental standpoint.  This in-
crease averages about 25% as shown in the referenced  tables
and  graphs,  and only represents the absolute difference in
water consumed.
                             656

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ONCE-THROUGH


RIVER OR LAKE
                     RADIATION AND CONDUCTION
                     EVAPORATION
BASIN

COOLING
 RADIATION AND CONDUCTION
 EVAPORATION
BASIN COOLING


     SPRAYS
 RADIATION & CONDUCT^
	i.	

 EVAPORATION
WET COOLING


TOWER
 CONDUCTION


 EVAPORATION
WET/DRY


COOLING TOdER
 CONDUCTION


 EVAPORATION
DRY COOLING


TOWER
                     CONDUCTION

                   0%
    10%   20%   30%   40%   50%  60%   70%   80%   90%   100%
                                   Figure B-VIII-27


                             HEAT TRANSFER MECHANISMS


                        WITH ALTERNATIVE COOLING  SYSTEMS



                               (From Reference 318)
                                        657

-------
                             TABLE B-VIII-  28
      EVAPORATION RATES FOR VARIOUS COOLING SYSTEMS  (Reference 104)
Cooling System
Cooling Pond (2 acres/Mw)
Cooling Pond (1 acre/ Mw)
i
; Mechanical Draft Tower
: . Spray Pond
Natural Draft Tower
i
< Natural Lake or River
i
Evaoorat ioir-
m-Vsec
.566
.453
.368
.360
.340
.266
cfs
20.0
16.0
13.0
12.7
12.0
9.4
For a 1000 Mwe fossil-fueled plant at 82 percent capacity factor average
annual evaporation (assume constant meteorological conditions).
                                   658

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                                                          TABLE  B-VIII- 29
                                           COMPARATIVE UTILIZATION OF NATURAL RESOURCES

                                                 WITH ALTERNATIVE COOLING SYSTEMS
                                                                 FOR .
                                                      FOSSIL  FUEL PLANT WITH

                                                      680 Mw  NET PLANT OUTPUT
                                                  (70 per cent annual load factor)






Once-through river or
lake cooling system

Alternative cooling systems
Basin cooling facility
Basin cool.ing with auxiliary sprays
Mechanical draft wet tower
Mechanical draft wet/dry tower
Mechanical draft dry tower
Natural draft wet tower

Gross
Generating
Capacity
kw
Net
Plant
Heat
Rate
Rtu/Vwh

Fuel
Input
Billions of
Btu/yr

Coal
Consumption
10,000 Rtu/lh
tons/yr

Water
Consumption
(Evaporation)
Acre ft/yr


Land
Area
acres
BASE REQUIREMENTS

715,580

9,489

39,567

1,978,343

2,800


ADDITIONS TO BASE REQUIREMENTS

-
6,360
4,420
5,070
17,770
3,060
19
103
77
86
1,173
59

79
429
321
358
4,682
246

3,950
71,450
16,050
17, 900
734,100
12,300
5,400
6,300
6,300
2,800
* (?,800)
6,300
1,000
500
15
15
6
15
01
Ui
vo
              *Denotes Decreased Requirements
(From Reference 318)

-------
                                    2 ACKIS/MW
                                     1 ACRt/MW
                          MCCHANICAl GRAFT C.I
                       SPkAY PONDS
                 NATURAL DRAFT C.T.
                              NAIURAI UKE OR RIVU
             SO        60
              WET BULB TEMPERATURE •
     WATER CONSUMPTION VERSUS
     WET BULB TEMPERATURE
                                       CAl/Kcl
                                        1.6
                                                       KWH
                                                                   NAlUSAl LAKE OR SIVER
                                                               KECHAIiiCAl DRAFT C.T.
                                                            SPRAY PONOS
                                                         NATURAL DRAFT C.T.
                                                  40         EO
                                                      RELATIVE HUMIDITY • %

                                            WATER CONSUMPTION  VERSUS
                                            RELATIVE  HUMIDITY
CAL/Nct KWH
 1.20
                      2 ACRES.'KV
                7   8   9  10   II   12  U  U  IS
                 WIND SPEED • MPH

    WATER CONSUMPTION VERSUS
    WIND SPEED
                                                                       2 ACRES MW
                                                                       NATURAL LAKE OR RIVtR '
                                        0  10  20  30   40   50   60   70   60  90  100
                                                      CLOUD COVER• %
                                          WATER CONSUMPTION VERSUS
                                          CLOUD COVER
 CAL/Nct KWH
 I.I
 1.0
 .9
 .8
 .7
 .6
 .5
 .4
 .3
 .2
 .1
 0
\
                       2 ACRCS MW
I ACRE MW
                       SPRAY POKO
                      NATURAL LAKE
                      OR KiVER
                  10      15
                COOLING RANGE •'{
                      20
     WATER CONSUMPTION VERSUS  TEMPERA-
     TURE RANGE  FOR  BODIES OF  WATER
                                     CAL/Nct KWH
                                     .60
.73

.76

.74

.7J

.70
.r,3
.bG

.64
.62
.60
                                                   	00
                                                        V
                                                         ATURAL DRAfT C.T.
                                       10 12 14  li 18  20 2? 24 70 28  30 32 ]4  36 38  48
                                                             •{
                                      WATER  CONSUMPTION  VERSUS TEMPERATURE
                                      RANGE  FOR  COOLING  TOWERS
                                    (From Reference  133)
                                     FIGURE  B-VIII- 28
           WATER CONSUMPTION VERSUS METEOROLOGY AND COOLING RANGE
                                        660

-------
Present powerpiants have been sited, in  many  cases,   where
the  lack  of a reliable supply of quality cooling water has
dictated the use of closed-cycle  evaporative  cooling.   In
other words, where water is in short supply, the more-highly
water   consuming  evaporative  cooling  systems  have  been
justified and legal rights to water  consumption  have  been
obtained  where  required.   In  many states water users and
consumers must obtain legal rights to use or consume  water.
In some of these states all water use and consumption  rights
have  already  been  allocated but not necessarily utilized.
Rights can be bought and sold among users.  Many powerplants
have rights  to  more  water  than  they  currently  use  or
consume.   In  some  states  powerplants  have  the power of
eminent domain over water rights, and are thereby authorized
to appropriate all or a part thereof to the necessary  public
use, reasonable compensation being made.


A comprehensive study, prepared by  the  Utility  Water  Act
Group  (Reference  U41),  of  the  water use implications of
applying closed-cycle  evaporative  cooling  to  all  steam-
electric  powerplants  concluded that an increase of over 80
percent would result in the amount of fresh  water  consumed
annually by these plants.  When considering total freshwater
consumption  by  all  uses, complete closed-cycle cooling in
the year 2000 is projected by the same study to increase the
total water  consumption  nationally  by  5.U  percent  when
compared to maintaining the existing mix of once-through and
closed  cooling  systems.   At  the  same  time,  the   Water
Resources Council projects possible shortages  of  water  in
the year 2000 in major portions of the U.S.  from California
to  Texas.  The study cited above projects for the year 1983
the following  increases  in  freshwater  consumption,  over
present  freshwater  consumption by powerplants for the arid
regions from Texas to California:

                            Base               Increases

Texas-Gulf                 376.7MGD             125.7MGD
Rio Grande                  36.8                  0.0
Upper Colorado              13.1                  0.0
Lower Colorado              65.6                  0.0
Great Basin                  5.3                  0.2
California                  <*7.0                197. a

The regions listed above encompass  the  geographical   areas
shown on Figure B-VIII-29.

The  previously referenced study **» further estimates that,
in the case of California  (which appears  to  be  the  worst
                             661

-------
                                         WATER RESOURCE REGIONS
to
                                           s-0.uils!E  RAINY
                                               ~
                                  	   •  M»«"w«M»i/    ' ~~\ I/I ^rrAT I A'KES
                                  "" "MSRI  x uv^ute v'   •
                                        .BASIN ^   u\—-•—\    \\    t>
                                           •CAJUSU
                               UPPER
                             COLORADO
                             ^rgr—j^. ARKANSAS-WHITE-RED     ^ss^i^
                                              - "^
                                                   -4 MISSISSIPPI i  SOUTH   "v
                                                       '  ')< ATLANTIC GULF
                                                         i-4-.  \.crT  ~]rSSirJ
        Figure B- VIII- 29    Regions Upon Which Water Consumption Studies Have Been Based
                                                                                 441

-------
case  for  the  6 arid regions), in the year 2000 there will
be, as a base, a deficit of 29.1 billion gallons per day  of
freshwater  based  on  monthly  flow available 95 percent of
months  (20-year  drought).   Corresponding  to  this,   the
freshwater  consumption  due to retrofitting of closed-cycle
cooling to steam-electric powerplants would add 1.1  billion
gallons  per  day  to  the  base deficit during peak monthly
power demands under summer conditions.  For this worst  case
(of the 20-year condition) the increase in the water deficit
that  may  be attributable to retrofitting is 3.8 percent of
the base deficit.

The previously reference study prepared by the Utility Water
Act Group indicates the consumptive use of freshwater due to
retrofitting steam-electric powerplants  in  California  for
1970, 1983 and 2000 as follows:

                            Base               Increases

1970                      19.8MGD               83.4MGD
1983                      47.0                 197.H
2000                     198.9                 835.9

The  existing  mix  employed above for 1970 of 78.27 percent
capacity using once-through  saline  cooling  systems,  6.48
percent  using  once-through  freshwater,  and 15.25 percent
using cooling towers, is based on FPC Form 67 data for 1970.
Projections of increases for the years 1983  and  2000  were
based  on  applying   h  same  percentage to the base as was
applied for the 1970 computations.

From the 1970 mix described above it can be  seen  that  the
consideration  of  salt  water  cooling  towers  'which is an
available alternative for plants using  once-through  saline
systems  would  significantly  diminish  the  projection  of
freshwater consumption indicated by Reference 441, which  is
based as the use cf freshwater towers for plants using once-
through  saline  systems.   Reports  submitted to the FPC by
regional  reliability  councils  in  1973  in  response   to
Appendix  A  of  Order  383-3  list projected steam-electric
units 300 megawatts and larger for  which  construction  has
begun  pr  is  scheduled  to  begin  within  2 years.  These
reports list 7,013 megawatts of generating  capacity  to  be
added in California over the years 1973-1980.  Of this 5,802
megawatts  are  planned with once-through saline systems and
cooling  tcwers  are  planned  for   the   remaining   2,211
megawatts.  Considering all the plants listed in FPC Form 67
for  1970  and all the plants listed by the FPC for start-up
in 1973-^980, incremental freshwater consumption will result
only from retrofitting the 6.48S of the 1970 capacity  which
                             663

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uses  once-through  freshwater  cooling  systems,  or  1,280
megawatts cut of the 26,792 megawatts covered by the two FPC
sources.  In contrast, the  previously  mentioned  study  by
UWAG  assumes  retrofit freshwater cooling systems on 34,500
megawatts of generating capacity by 1983 for California.

Similar results would be obtained for the Texas-Gulf  region
which was assumed to have a capacity mix of 27.30 percent on
once-through  saline  systems; 15.30 percent on once-through
fresh systems; 36.00 percent on  cooling  ponds;  and  21.40
percent  on cooling towers.  Subsequent to the publishing of
the  reference  study,  virtually  all   of   the   capacity
identified  above as being on once-through fresh systems has
been  determined  to   actually   be   on   cooling   lakes.
Furthermore,  the  Electric  Reliability  Council  of Texas,
whose geographical area roughly coincides  with  the  Texas-
Gulf  region, reported to the FPC in 1973 only 750 megawatts
of capacity planning  once-through  cooling  for  units  300
megawatts  and  larger,  out  of  14,737 megawatts for which
construction had begun or was scheduled to  begin  within  2
years.   These  capacity additions were planned to be placed
into service over the period 1973-1982.

In Florida, which Reference 441 identified  as  a  potential
problem area for freshwater consumption due to retrofitting,
875  megawatts  of capacity are reported by the southeastern
Electric Reliability Council  to  be  planning  once-through
freshwater  cooling  out of a total of 8,919 megawatts to be
added from 1973 to 1978.

Reported under FPC Docket R-362, April 1,  1974,  Order  No.
383-3,  Appendix  A-l  are  cooling  methods  for  projected
generating unit additions, 300 megawatts and larger, for the
period 1974-1983, for the entire U.S.   Closed-cycle  sytems
total  181,702 megawatts and once-through systems (including
many salt water systems) total  51,265  megawatts.   Closed-
cycle  systems  represent  approximately  75  percent of the
added generating capacity  reported  for  this  period.   In
summary,  in  all  the regions where Reference 441 indicated
that retrofitting would add  to  the  year  2000  freshwater
deficit, consideration of applying saltwater towers to once-
through  saline  systems,  identification  of  cooling lakes
which had been  accounted  for  as  once-through  freshwater
systems,  utilizing  for  projections  cooling systems mixes
based on regional reliability council  reports  rather  than
projecting the 1970 mix, and exclusion of the older, smaller
generating  units  results in no indication of a significant
contribution to freshwater deficits due to retrofitting.
                               664

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Slowdown

In the closed cooling systems utilizing evaporative cooling,
there is  a  buildup  of  dissolved  and  suspended  solids,
including  water  treatment  chemicals,  due to evaporation,
which removes pure water,  leaving  the  above  constituents
behind.   Without  some control over this buildup, scale and
corrosion may occur, damaging the equipment and reducing its
performance.   To  prevent  excessive   buildup,   a   small
percentage  of  the  water  is  continually removed from the
circulating water system.  This is  normally  called  "tower
blowdown" or "blowdown".  The water that is added to replace
this  water,  and the evaporative, drift and leakage losses,
is known as makeup.  The amount of blowdown is dependent  on
two  factors.   The primary factor is the avoidance of scale
or  other  detrimental  effects  in  the  circulating  water
system.   Of  secondary  importance  is  the  quality of the
blowdown water.  The two types of scale normally encountered
are CaCOj and CaSOU.  The CaCO3  can  be  controlled  by  pH
adjustment,  with sulfuric acid normally being used to lower
the pH.  The CaSOU scale formation is avoided by maintaining
the concentration~of  CaSOU  below  saturation.   The  CaSOU
concentration is controlled by the amount of blowdown.  Thus
the  amount  of  blowdown  varies  with the concentration of
dissolved solids in the makeup water.  The blowdown on fresh
water towers amounts to on the order of 2% of the total flow
through the tower.  With some types of water, blowdown rates
of less than 1% may be used.  The blowdown rate is  normally
determined  by  the  number  of  concentrations of dissolved
salts   allowed   'in   the   circulating    water    system.
Concentrations of 10 or less are common, with concentrations
as high as 20 being used.

Use  of  salt  water makeup in ccoling towers would decrease
the number of  permissible  concentrations,  increasing  the
blowdown  rate.   A  blowdown  rate equal to the evaporation
rate would result in a blowdown twice as concentrated as the
makeup.  In addition to concentrated  salts,  this  blowdown
will  have  the chemicals used to treat .the water to prevent
corrosion and algae growth in the system.   While  chromates
were  previously  used  to a large extent, their use has de-
creased in recent years with the availability of other types
of corrosion inhibitors.

Technology is  currently  available  to  control  and  treat
pollutants  in  blowdown,  to  levels up to and including no
discharge of pollutants.  See Part A of this  report  for   a
description  of  the  technology  related  to  pollutants in
blowdown.

Blowdown removed from the hot side of the circulating system
is advantageous to the plant, as the heat  in  the  blowdown
                                665

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does  not  have  to be removed in a tower.  However, it is a
better environmental practice to discharge blowdown from the
cool side.  The percentage of heat involved is in the  order
of  2^>  of  the  total,  and  the thermal discharge could be
correspondingly  further  reduced.    The   blowdown   would
normally be at a higher temperature than the receiving body,
even  if  taken from the cool side, since the approach is to
the  wet  bulb  temperature,   not   the   receiving   water
temperature.

Aesthetic Appearance

In  addition  to all the other factors described, the visual
impact of. the cooling system could  be  of  concern  to  the
neighboring  residents  and visitors.  Cooling towers create
two types of aesthetic impact.  First,  the  large  size  of
natural  draft  towers  will dominate most settings in which
they are placed.  In this regard, natural draft  towers  can
be  as  high as a 50 story building and cover an area at the
base  equivalent  to  several  football  fields.    In   all
applications,  they  will  dwarf  the associated powerplant.
Mechanical draft towers, on the other hand, are considerably
smaller in height than the natural  draft  towers,  although
the  aggregate base area of a multicelled unit may be larger
than the base area of a natural draft unit for the same size
plant.  Therefore mechanical draft towers  will  not  be  as
objectionable in this regard as will natural draft towers.

The  second type of aesthetic impact is common to both types
of towers.  This impact is caused by the visible plume  that
can  be generated by both types of evaporative systems where
plume abatement is not employed.  Cooling tower plumes  will
sometimes  be  larger than the stack emission from a fossil-
fuel plant, especially in areas of high  fogging  potential.
At  some plants cooling tower plumes can be so insignificant
that they escape notice by many viewers.  Some cooling tower
plumes, however, can be visible for  several  miles  and  be
noticed  even  where  the  surrounding topography completely
hides both the plant and the tower.  As with fogging,  plume
abatement technology is available at moderate cost.

The  question  of  whether  a  tower or its plume creates an
adverse aesthetic impact is a  subjective  issue  since  the
sensibilities  of  individual  viewers varies widely.  There
are those who believe  that  all  cooling  towers  create  a
visual nuisance.  Others have expressed the opinion that the
hyperbolic shape of cooling towers is visually pleasing.

The  aesthetic impact of cooling towers is not necessarily a
function of urban or rural location as some nave  suggested.
                           666

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Discussions  with  utility  representatives revealed as much
opposition to cooling towers placed in rural  settings  such
as  along  the  California Coast and in scenic areas such as
the Hudson River, as was voiced over towers placed in  urban
areas.

The  impact  of  cooling  tower  aesthetics  can  effect the
application of cooling towers at existing plants as well  as
at  new  sources.   With  existing plants locational factors
will have been fairly well established and relatively little
flexibility in the placement of the tower will  be  possible
compared  to  new  plants.  The most critical plants will be
those which are located in areas of mixed zoning.  Residents
of those areas which have accepted  a  powerplant  in  close
proximity to their homes may object to the additional impact
of  a  massive structure and a new, large, visible emission.
In terms of aesthetic impact the mechanical draft  tower  is
superior  to  the natural draft tower.  The physical size of
these units is much smaller than the natural draft tower and
the  mechanical  draft  tower  can  be  fitted  with   plume
suppressive equipment which is not yet available for natural
draft towers.  It is anticipated that this latter difference
will  be  corrected  in  the  near  future.   It may be that
another type of evaporative cooling could be substituted for
the tower in some instances.  It is also noted that the fan-
assist  modification  to  the  natural   draft   tower   can
substantially reduce its size.

For  new  plants  where the location, site layout and archi-
tectural plan have not been finfelized, considerably more can
be done to abate adverse aesthetic impact than  is  possible
at  existing plants.  In addition to the selection of a less
imposing cooling system where possible, and the installation
of  plume  abatement  systems,  the  site  location  can  be
selected  to  reduce  the  cooling  tower visual ar les to a
minimum.  The site layout  can  be  used  to  place  natural
barriers between the tower and the surrounding land uses.  A
pleasing  grouping  of  building  and  common  architectural
treatment can  be  used  to  blend  the  facility  into  its
surroundings.

Mechanical  draft  towers will more easily fit into the sur-
rounding area.  Plant nc . 2612 is using the low  hills  sur-
rounding  the  plant  to almost completely screen the towers
from view.  Landscaping can hide or blend  the  towers  into
other  types  of  terrain.   Painting  the towers can aid in
making their appearance more pleasing.

Cooling  lakes,  if  sufficiently  large,   can   serve   as
recreation   sites.    With   appropriate   landscaping  and
                              667

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structures, camping, boating, swimming, and fishing  can  be
accommodated.   One  utility leases summer cabin sites along
its cooling lake.  Being low,  these  lakes  normally  blend
well into the landscape.  Landscaping of cuts and fill areas
will normally be required.

Spray canals can be very pleasing to the eye if properly de-
signed.   Appropriate  landscaping  can hide the canal banks
and power distribution systems.  The sprays  themselves  can
be  attractive  if  arranged in a symmetrical pattern.  They
can be decorative, and be a definite asset  to  the  plant's
appearance.

In  summary, aesthetics is not a national-scale problem.  In
cases where aesthetic impacts of  towers  and  plumes  could
occur,  alternative  technologies  are  available  and plume
abatement technology is available  at  moderate  incremental
cost.   New  plants  have  the  added  flexibility  of  site
selection to help minimize this problem.

Icing Control

Icing can result from the operation  of  cooling  towers  in
cold  weather.   Ice  formation  is  usually confined to the
tower  itself  and  adjacent  structures  within  the  plant
boundaries.   No  cases  of  tower  related ice formation at
locations external to the  plant  are  known  to  have  been
reported.  Therefore, icing is an operational problem of the
cooling  system similar to the control of biological growths
in the system rather than a nonwater  quality  environmental
impact.

Control  of  cooling  tower ice formation can be obtained by
providing appropriate  features  in  the  tower  design  and
employing  certain  procedures  in  tower  operation  during
periods of cold weather.  In the case  of  mechanical  draft
towers,  ice  formation  in  the  louvers  can  be melted by
periodically reversing the fans to drive air across the  hot
water  and through the louvers.  Louvers can also be di-iced
by flooding them with hot water which is deliberatly spilled
from the outer edge of  the  water  distribution  basin  and
allowed to cascade down over the louvers.  In some instances
louver  icing  can  be  controlled  by concentrating the hot
water load on the outmost segments of the fill  during  cold
weather.   This  is  accomplished  by  means  of partitioned
distribution basins and  water  distribution  systems  which
allow  for flexibility in the distribution of the water load
over the fill area.  For hyperbolics  this  is  achieved  by
providing an annular channel at the outside edge of the fill
                              668

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and  a distribution system which can divert a large fraction
of the hot water into this channel.

During cold weather an annular segment  of  the  fill  of  a
cross  flow  hyperbolic  or  one or more cells of mechanical
draft units may be taken off line.  The resulting  increased
water loading also serves to reduce tower icing.  In some of
the  new  designs  for  hyperbolics,  the fill is completely
bypassed during periods of very cold weather and small plant
loads.

Non-Water Quality Environmental  Aspects  of  Spray  Cooling
Systems

The text of this subsection is exerpted from Reference U05.

Ceramic   Cooling  Tower  Co.  presents  a  pseudo-technical
comparison, using known psychrometric principles, to display
the  relative  magnitude  of  fog  intensity  and  frequency
probability  between conventional cooling towers and powered
spray modules.  Superiority of  the  spray  is  rationalized
qualitatively by comparing such apparent differences as: (a)
Sprays provide substantially greater area and air volume for
head  dissipation of identical duty; (b) Air discharged from
the spray is not as near saturation as that  from  a  tower;
(c)  Temperature  of  air in tower exhaust is close to water
temperature but downwind of spray  the  air  temperature  is
significantly less.

Extensive  winter  tests  of one Cherne Thermal Rotor module
were sponsored by 31 electric companies.   On  approximately
15 mornings when natural fog was present, observable amounts
of  fog  continued  to  be  produced  by the Rotor for 10-15
minutes after natural fog lifted.  With winds less  than  15
miles  per  hour (<^.3 kn) and air temperature less than 10°F
(-12°C) hoarfrost  (rime ice) was observed to  a  maximum  of
about 100 ft  (30 m).  Ice accumulated to several inches on a
embankment  about  20  ft   (6  m) from the edge of the spray
pattern.

Commonwealth  Edison  of   Chicago   (Illinois)    contracted
detailed  micrometeorological  studies of a cooling lake and
test sprays at a plant in Illinois.  Although the effects of
the  sprays  are  difficult  to  isolate  from  the   total,
observations  made  near  the  sprays  may  be  useful.  The
highest frequencies  of  steam  fog  occured  in  the  early
morning.   The  overwhelming  majority of steam fog observed
remained aloft.  Fog travelled at or near ground  level  150
ft  (46 m) or more, for short periods of time, on 60 days out
of U56 from January, 1972, through March, 1973.  Only 10 per
                              669

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cent  of  the  extrusions were more than 175 ft (53 m).  Six
times rime ice deposited at a distance of 150 ft (46  m)  or
more;  a  maximum distance occurred twice at 425 ft (130 m) .
On two occasions during winter months a very light trace  of
snow was observed to fall out of the steam fog.

Little  objection is raised concerning environmental effects
of drift  from  freshwater  systems,  but  some  concern  is
expressed  for  salt  water  systems  because  of  potential
damages to surrounding area from the fallout of salt.    Data
presented  here  were  obtained by different methods and may
not be comparable.

Ceramic reports that the composite of substantial testing at
various  sites  of  generally  full  scale  systems,   under
numersous atmospheric conditions, indicates that measureable
drift,  during any meaningful time period, does not exceed a
distance of 600 ft  (183 m) from the sprays.  These tests are
based on dissolved solids fallout into  collection  pans  of
accurately  determined  area  of  controlled  time  periods.
Average curves are presented  for  1,  2,  4,  and  6  units
arranged  axially  perpendicular  to  the  predominant  wind
direction.  These curves show, for example, that one  module
with  10  MPH (8.6 kn) wind will deposit 0.002 gal/day/sq ft
(0.082 1/day/sq m 100 ft  (30m)) from the spray.   Deposition
with  multiple  modules  is  not  linear;  six  modules will
deposit about 0,004 gal/day/sq ft).  "Drift Multipliers" for
approximating  deposition  at  different  wind  speeds   are
presented;  these range from about 0.1 for 3 MPH (2.6 kn) to
2.2 for 15 MPH (13 kn).

Cherne presents  a  graph  of  maximum  deposition  rate  as
function of distance for winds up to 14 MPH  (12 kn).  At 100
ft   (30 m) from the Rotor the maximum rate is 0.05 Ibs/hr/sq
ft (5.86 1/day/sq m). At about 470 ft (143 m)  the  rate  is
0.0004  Ibs/hr/sq  ft   (0.047  1/day/sq  m),  which  is  the
resolution limit of the test.  The tests involved collecting
samples of droplet fallout over short time periods in  glass
petri   dishes   and    immediately   weighing  on  precision
laboratory balance.  Surprisingly, little  correlation  with
wind speeds up to 14 MPH  (12 kn) was noted.

Richards approximates the drift emission characteristics, or
the  amount  carried  away,  in contrast to deposition.  The
analysis is based on drop  size  distribution  and  particle
transport  theory.   The  investigators point out that there
are no data available on either drop sizes  or  distribution
to  be  expected  from  breakup of massive sprays.  However,
estimates of drop size distribution were made  by  analyzing
close-up photographs of sprays.  These estimates agreed well
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with  those  predicted by Fan Jet theory.  Turbulent effects
in vertical directions were ignored but compensated by other
conservative assumptions in the calculations.

Drift emission characteristics are presented graphically  in
units of amount of suspended spray at various distances as a
function  of  different  wind  speeds.   It  is difficult to
summarize this complex graph,  but  typical  numbers  for  a
single  module are as follows: a 5 MPH (4.3 kn) wind carries
10 Ibs/hr (U.5 kg/hr) of spray a distance of 100 ¥t (30  m);
a 20 MPH (17 kn)  wind carries the same amount to 500 ft (152
m) .
                                               •
Measurements made for Ceramic during operation of full scale
PSM systems in various terrain situations indicates that the
sound  pressure  level  from  operation  of  the full system
reaches background level at 200-250 ft (61-76 m)   when  wind
was calm to 5 MPH (4.3 kn).  The octave band level is rather
flat  with  a  maximum  around  425  Hertz.   Tests  with 14
Richards modules indicate attenuation to background at about
2,000 ft (610 m).  No wind data are presented.  Octave  band
level  near the sprays is rather flat also, with the maximum
around  500  Hertz.   Higher   frequencies   decrease   with
increasing distance.

Spray  cooling requires less than 5 percent of the land area
of a cooling pond for the same cooling  duty.   No  chemical
additives  to  the  circulating  water are required by spray
equipment.   Consequently, possible air or water pollution by
such additives is not a  problem.   Under  summer  operating
conditions  80-90  percent  of  cooling  is  accomplished by
evaporation; less for annual average conditions.

Hoffman gives an excellent summary of spray systems.  In  it
he  concludes:  "It  is  the  opinion  of  this  author that
floating  spray  modules  commercially  available   are   an
attractive  alternative  when designing powerplant condenser
cooling systems.   The thermal performance of such systems is
predictable  and  measurable.   The  adverse   environmental
effects  caused by spray systems can be largely mitigated by
careful design procedures and by  taking  advantage  of  the
operating  flexibility  that  is  inherent  in  spray  canal
systems."

The  data   presented   to   date   substantiate   Hoffman's
conclusion.   The  major  deficiency  at  this  time  is the
prefection and  verification  of  models  to  predict  drift
transport.
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The  U.S.  Environmental Protection agency has begun studies
in co-operation with Florida Power and Light Company on salt
water  cooling  at  the  Turkey  Point  Station  near  Miami
(Florida).  These studies will include ambient (natural)  air
chloride  concentration  and  deposition,  salt  water drift
emissions from mechanical draft towers  and  spray  modules,
fallout  characteristics,  and terrestrial effects on native
and cultured vegetation.

Ashbrook Corporation has entered into a co-operative program
in New York State University.  The purpose is  to  determine
quantitatively  ice  formation and drift deposition rates as
functions of distance from the spray source.

Detroit Edison and its consultants are continuing  to  study
environmental effects of cooling system alternatives.

Non-Water Quality Environmental Aspects of Surface Cooling

The text of this subsection is exerpted from Reference 413.

In  cooling  ponds, evaporation is one of the main mechanism
in the dissipation of waste heat load and this  takes  place
at the water surface.  If subsequent condensation occurs, it
will  take  place  not far above the water surface.  Induced
fogs  (and freezing  fogs)  formed  in  this  way  may  drift
downwind  and  reduce  visibility.   Evaporation  of  heated
effluent from once-through cooling systems would produce the
same effects.

There is a lack of information on the frequency,  intensity,
and   inland   penetration  of  cooling  pond-induced  fogs.
Reported observations at  existing  cooling  ponds  indicate
that  the  fog,  categorized  as  thin  and  wispy, will not
penetrate inland more than 30.5  to  152.5  m  (100  to  500
feet)*14;  although  under  severe conditions fog may extend
from 3  to  18  km   (1.86  to  11.2  miles).   Ice  crystals
suspended  in  the  atmosphere have also been observed.  The
particular danger associated with freezing fog is  that  the
supercooled   droplets,   coming  into  contact  with  solid
surfaces, freeze immediately and form  a  thick  and  smooth
layer of ice.  This could be a hazard on road surfaces.

Any  increase  in  local  fog  or  clouds  created by either
cooling ponds or towers will  lead  to  a  decrease  in  the
amount  of solar radiation, including ultraviolet radiation,.
received at the surface*1*.

Recent studies*1* on the severity of fogging caused by  warm
water  lagoons  used  for  power  station  cooling show that
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steaming increases as the humidity increases,  and  the  air
temperature decreases.

Comparison of Control Technologies

The   available   control  and  treatment  technologies  for
effluent heat are  compared  in  Table  B-VIII-30  based  on
incremental costs (production, capital, fuel, and capacity),
effluent    reduction   benefits,   and   nonwater   quality
environmental impacts.

Costs Versus Effluent Reduction Benefits

A study was made *s* of the incremental costs of controlling
at various levels the quantity of  heat  discharged  into  a
river  (in  Belgium) by a lOOOMw nuclear unit, using a once-
through system as a base.  See  Figure  B-VIII-30.   Various
methods  were  assumed  for achieving successive incremental
reductions in effluent heat., as shown  in  Table  B-VIII-31.
The  incremental  costs  of  each  successive  effluent heat
reduction are also  given  in  the  table  compared  to  the
percent effluent heat reduction that would be attained.  The
table  shows  that  the  incremental  costs  are  lowest  in
relation  to  the  effluent  reduction  benefits   for   the
incremental  heat  removal with the closed circuit employing
simple treatment  of  make-up  water.   To  achieve  a  95.8
percent  effluent heat reduction the incremental costs would
be 86.2 percent of the incremental costs of 100 percent heat
reduction.

The  incremental  costs  (production,  capital,  fuel,   and
capacity),  and  costs versus effluent reduction benefits of
the application  of  mechanical  draft  evaporative  cooling
towers  to  nonnew  nuclear  units  and  fossil-fueled units
(base-load, cyclic,  and  peaking)  with  various  years  of
remaining  service  life  is  shown  in  Table B-VIII-32.  A
similar costs breakdown for new units is given in  Table  B-
VIII-33.   Both  tables indicate the assumptions used in the
cost analyses.

In general for  nonnew  sources,  the  total  costs  of  the
application of thermal control technology in relation to the
effluent   reduction  benefits  to  be  achieved  from  such
application are the most  favorable  for  the  newest,  most
highly  utilized  generating  units, and, progressively, the
least favorable for the oldest,  least  utilized  generating
units.   For new sources the costs versus effluent reduction
benefits are even more  favorable  due  to  the  absence  of
"backfitting" costs of any kind, which would be a major cost
for  nonnew  sources.   In the intermediate case of a nonnew
                             673

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                                                                 TABLE B-VIII-30
                                                     CONTROL AND TREATMENT TECHNOLOGIES FOR HEAT
                                    COSTS,  EFFLUENT REDUCTION BENEFITS, AND NON-WATER QUALITY ENVIRONMENTAL IMPACTS
TECHNOLOGY
(Approx. no. of units
employing technology)
Once-Through ( 2500 )
Process Change (0)
Surface Cooling (100)
Unaugmented
Augmented
Evaporative (Wet) Tower
Mechanical Draft{250)
Natural Draft (60)
Dry Tower ( 1 )
Wet/Dry Tower (1)
Alternative Processes
Hydroelectric UOO ' s )
Internal CombustionClOO' s
Combined Cycle (approx. 50) a
INCREMENTAL COST FOR MAX. EFFL. RED.
% Base
Production
0
100
10-20
10-20
10-20
10-20
20-40
14-28
0
100
Capital
0
100
9-14
9-14
9-14
9-14
11-16
10-15
0
100
pp 50 app 50
Fuel
0
Capacity
0
ISgain ISgain
1-2
1-2
1-2
1-2
4-5
2-3
lOOgai
0
app 50gai
3-4
3-4
3-4
3-4
7-10
4-5
n 0
0
n 0
BFBL. RED. BENEFITS
% Base
0
15max
0-100
0-100
0-100
0-100
0-100
0-100
0-100
0-100
app 50
NONWATER ENVIRONMENTAL IMPACTS
% Base
Fog
0
0
0
*
*
0
0
0
0
0
0
Drift
0
0
0
*
*
Noise
0
0
0
0
*
0 ! 0
0
*
. 0
0
*
*
0
*
Aesthetics
0
0
0
*
*
*
0
0
0
0
Land
0
0
2000
1000
30
30
30
30
Water Consumption
0
0
100
200
200
200
30gain
35
2000 • SOgain
0 lOOgain
0 * 0 ' 0 SOgain
* Note: Some highly site-specific  incremental impacts, but not generally anticipated to be limiting.

-------
                             1000 Mw nuclear unit
        X
       CO
       -p
       w
       o
       o
        c
        o
                         100     200     300      400
                 HEAT DISCHARGE DTTO TI-HD Rr/ER IN Meal/sec
500
                 AB - Closed circuit with decarbonation of the
                      malce-up water
                 BC - idem - simplified  treatment
                 CD - H? - Lliyed circuit
                 DE - Cooling on discharge
                        0ii circuit
Figure B-VHI-30 Additional Cost Versus Heat Discharged
                                                              456
                            675

-------
                       Table B-VIII-31

COST VERSUS EFFLUENT  REDUCTION BENEFITS,  0-100 % REMOVAL OF HEAT
              Basis:  Figure B-VIII-30 (Reference 456)
Cooling Method
\
Base: Open circuit
(once- through)
Cooling on dis-
charge (once-
through with
"helper")
Mixed circuit
(partial recycle
of water cooled
by the tower)
Closed circuit
with simple
treatment of
make-up water
Closed circuit
with decarbon-
ation of make-
up water
Effluent Heat Reduction,
% of base heat discharged
Incremental
0
8.5
63.9
23.4
4.2
Accumulated
0
8.5
72.4
95.8
100
Incremental Cost,
% of total incremental cost
for 100% heat reduction
Incremental
0
19.8
53.5
12.9
13.8
Accumulated
0
19.8
73.3
86.2
100
Incremental Cost,%
Incremental Heat Reduction, %
Incremental
-
2.33
0.84
0.55
3.29
Accumulated
-
2.33
1.01
0.90
1.00

-------
                                                                   TABLE B-VIII-32
                                  INCREMENTAL  COST OF APPLICATION OF MECHANICAL DRAFT EVKPORATIVE COOLING TOWERS TO
                                                        NONNEW UNITS (BASIS 1970 DOLLARS)
TYPE UNIT REMAINING LIFE
Years

I. Nuclear 30-36
(All base-load) 24-30
18-24
12-18
6-12
0-6
Average excl. 0-6
II. Fossil-Fuel
A. Base-Load 30-36
24-30
18-24
12-18
6-12
0-6
Average excl. 0-6
B. Cyclic 30-36
24-30
18-24
2 12-18 '
-1 6-12
0-6
Average excl. 0-6
C. Peaking 30-36
24-30
18-24
12-18
6-12
0-6
Average excl. 0-6
INCREMENTAL PRODUCTION COSTS
% of Base Cost

13
14
15
16
19
30
15

11
12
13
14
16
22
13
14
15
16
18
20
30
17
40
40
45
50
60
100
47
Assumptions: TYPE UNIT Base Prod. Cost
mills/kwh
I. Nuclear 6.50
II. Fossil-Fuel
A. Base-Load 6.34
B. Cyclic 8.35
C. Peaking 12.5
Cost/Benefit
S/IMWHJ
XlO
4
5
5
6
7
11
5

4
4
4
5
5
7
4.
5
5
6
6
8
10
6
20
20
20
30
30
60
24
Base Cap. Cost
S/i™
150

120
120
120
INCREMENTAL CAPITAL COSTS
% of Base Cost Cost/Benefit
$/[MWH]
XlO
12 1
12 1
12 2
12 2
12 5
12 10
12 2

12 1
12 1
12 1
12 2
12 3
12 8
12 1.6
14 2
14 2
14 2
14 3
14 5
14 15
14 3
16 7
16 8
16 10
16 13
16 21
16 61
16 10
ADDITIONAL FUEL CONSUMPTION
% qf Base Fuel Cost/Benefit
Consumption [MWHJ /[MWHJ
xlOO
2 3
2 3
2 3
2 3
2 3
2 3
2 3

2 ' 3
2 3
2 3
2 3
2 3
2 3
2 1
2 3
2 3
2 • 3
2 3
2 3
2 3
2 T
2 3
2 3
2 3
2 3
2 3
2 3
2 3
GENERATION CAPACITY REDUCTION
% of Base Gen-
erating Capac.
3
3
3
3
3
3
3

4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Annual Boiler Heat Rate Heat Loss Heat Converted Heat to Cooling Water
Capacity Factor Btu/ kuh Btu/kwh Btu/ kwh Btu/ kvh
0.70 10,500 200 3,500 6,800

0.77 1O,500 500 3,500 6,500
0.44 11,500 500 3,500 7,500
0.09 12.500 500 3.500 8.500
Cost/Benefit
MH/IMWII]
XlO
1
1
1
2
3
9
1.6

1
1
1
2
3
9
1.6
1
1
2
3
5
14
4
6
7
9
13
21
64
11
Cost Hcr-lacement
C3P-.C. $/ kw
^t>

90
90
90
Subscripts: F indicates electrical
            calculated at  0.293  xio~
niivalence of fuel consumed, and T indicates electrical equivalence of heat rejected to cooling water.  Both  are
  [MWHJ/Btu.

-------
                                                                            TABLE 3-VIII-J3
                                            INCREMENTAL COST OF APPLICATION OF MECHANICAL DRAFT EVAPORATIVE  COOLING TOWERS TO
                                                                    NEW  UNITS  (BASIS  1970 DOLLARS)
TYPE UNIT


I. Nuclear (All base-load)
II. Fossil-Fuel
A. Base-Load
B. Cyclic
C. Peaking
INCREMENTAL PRODUCTION COSTS
% of Base Cost

10

10
11
28
Cost/Benefit
5/tMWH]
xlO
3

3
4
13
INCREMENTAL CAPITAL COSTS
% of Base Cost

9

9
10
11
Cost/Benefit
S/IMWH]
xlO
1

2
4
18
ADDITIONAL FUEL CONSUMPTION GENERATION CAPACITY REDUCTION
% of Base Fuell Cost/Benefit % of Base Gen-
Consumption
1

1
1
1
[MWH] /[MWH]
xlOO
2

2
2
2
erating Capac.
3

4
4
4
Cost/Benefit
MW/IMWH]
XlO 1
1

1
1
4
Assumptions:
TYPE UNIT

I. Nuclear
II* Fossil-Fuel
A. Base-Load
B. Cyclic
C. Peaking

Useful Life
Years
40

36
36
36

Base Prod. Cost
mills/kwh
6.50

6.34
8.35
12.5

Base Cap. Cost
5/K.
150

120
120
120

Annual Boiler
Capacity Factor
0.70

0.77
0.44
0.09

Heat Rate
Btu/kwh
10,500

10,500
11,500
12,500

Heat Loss
Btu/kuh
200

500
500
500

Heat Converted
Btu/kwh
3,500

3,500
3,500
3,500

Heat to Cooling Water
Btu/ kwh •
6,800

6,500
7,500
8,500

Cost Replacement
Capac. s/kw
150

120
120
120
Subscripts: F indicates electrical  equivalence of fuel consumed, and T indicates electrical equivalence of heat rejected to cooling water. Both are
            calculated at 0.293x 10~  [MWH]/3tu.

-------
source for which construction has  not  been  completed  and
some  backfitting  cost attributable to construction aspects
would  not  occur,  the  costs  versus  effluent   reduction
benefits  are  likewise at a level of favorability above the
typical operational nonnew source and below the new source.

For  otherwise  similar  units,  the  cost  versus  effluent
reduction  benefits  are  the  most favorable for those that
will be the most highly utilized, or base-load  units.   The
costs  versus  effluent  reduction  benefits  are  the least
favorable for the units that will be utilized the least,  or
peaking  units.   Cyclic  units  rank  intermediate  between
base-load and peaking units.  In any case, the costs  versus
effluent reduction benefits for units that are to be retired
from  service  within 6 years are very high when compared to
the newer units in that  class  of  utilization  (base-load,
cyclic,  peaking)  which  have  a  greater remaining service
life.

Considerations of Section 316 fa)

Section 316 (a) of the Act authorizes  the  Administrator  to
impose  (on  a  case-by-case  basis) less stringent effluent
limitations when  a  discharger  can  demonstrate  that  the
effluent  limitation  proposed  for the thermal component of
the  discharge  from  his  source  is  more  stringent  than
necessary  to  assure  the  protection  and propagation of a
balanced,  indigenous  population  of  shellfish,  fish  and
wildlife  in  and  on  the  waterbody.   The  procedures for
implementing Section 316 (a) may  extend  over  an  estimated
time  span of approximately from two months to twenty months
depending,  from  case-to-case,  in  the  extent  to   which
additional   studies  are  required  to  establish  effluent
limitations based on environmental  need.   Correspondingly,
the timing for cases leading to significant thermal controls
could extend in some cases to the end of 1980.  See Table B-
VIII-34.   The  Act  does  not  authorize  extentions of the
implementation dates for best practicable control technology
currently available at individual  sources  to  dates  after
July  lt 1977, or for best available technology economically
achievable  to  dates  after   July   1,   1983,   even   in
consideration of Section 316 (a).
                              679

-------
                                  Table B-VIII- 34


              TIMING FOR CASES LEADING TO SIGNIFICANT THERMAL CONTROLS
ACCOMPLISHMENT
Propose effluent limitations guidelines
Propose Section 316 (a) procedures
Begin Section 316 (a) procedures
Promulgate effluent limitations guidelines
Promulgate Section 316 (a) procedures
Establish effluent limitation based
on Section 316 (a) procedures
Discharger selects control means
Discharger awards construction contract
Discharger meets effluent limitation with. . „
• Mechanical draft cooling tower
• Natural draft cooling tower
• Other means*
EARLIEST
Mar 1974
Mar 1974
Mar 1974
Oct 1974
Cct 1974
Oct 1974
Nov 1974
Feb 1975
Aug 1976
Jan 1978
Feb 1977
LIKELIEST
Mar 1974
Mar 1974
Mar 1974
Oct 1974
Cct 1974
Sep 1975
Nov 1975
Feb 1976
Nov 1977
Apr 1979
Feb 1978
LATEST
Mar 1974
Mar 1974
Mar 1974
Oct 1974
Oct 1974
Feb 1976
May 1977
Aug 1977
Aug 1979
Dec 1980
Aug 1979
00
o
      * Note: Assumes  two years after award of construction contract in each case.

-------
                           PART B

                     THERMAL DISCHARGES

                     SECTIONS IX, X, XI

       BEST PRACTICABLE CONTROL TECHNOLOGY CURRENTLY
           AVAILABLE, GUIDELINES AND LIMITATIONS

           BEST AVAILABLE TECHNOLOGY ECONOMICALLY
           ACHIEVABLE, GUIDELINES AND LIMITATIONS

              NEW SOURCE PERFORMANCE STANDARDS
                 AND PRETREATMENT STANDARDS

Limitations

Based  on consideration of the factors set forth in the Act,
the   effluent   limitations    for    thermal    discharges
corresponding  to  the  best  practicable control technology
currently available, best available technology  economically
achievable,   and   new  source  performance  standards  are
described below.  No limitations on heat are prescribed  for
pretreatment   since   this   pollutant   parameter  is  not
incompatible with municipal wastewater treatment processes.

The technological basis for limitations of no  discharge  of
heat is closed-cycle evaporative cooling, such as mechanical
draft  and  natural  draft  cooling  towers,  spray  cooling
systems and cooling ponds and cooling lakes.   For  all  new
sources the effluent limitation is no discharge of heat from
the main condenser except:

    1.   Heat   may   be   discharged   in   blowdown   from
recirculated  cooling water systems provided the temperature
at which the blowdown is discharged does not exceed  at  any
time  the  lowest  temperature of recirculated cooling water
prior to the addition of the make-up water.

    2.  Heat may be  discharged  in  blowdown  from  cooling
ponds  provided  the  temperature  at  which the blowdown is
discharged  does  not  exceed  at  any   time   the   lowest
temperature  of  recirculated  cooling  water  prior  to the
addition of the make-up water.

For  all  other  sources  the  effluent  limitation  is   no
discharge of heat from the main condensers except:

    1.   Heat   may   be   discharged   in   blowdown   from
recirculated  cooling water systems provided the temperature
                              681

-------
at which the blowdown is discharged does not exceed  at  any
time  the  lowest temperature of recirculating cooling water
prior to the addition of the make-up water.

    2.   Heat   may   be   discharged   in   blowdown   from
recirculated  cooling water systems which have been designed
to discharge blowdown  water  at  a  temperature  above  the
lowest  temperature  of  recirculated cooling water prior to
the addition of make-up water providing  such  recirculating
cooling  systems  have been placed in operation or are under
construction prior to the effective date of this regulation.

    3.  Heat may be discharged where the owner  or  operator
of   a   unit  otherwise  subject  to  this  limitation  can
demonstrate that a cooling pcnd or cooling lake is  used  or
is  under  construction  as  of  the  effective date of this
regulation to cool recirculated cooling water before  it  is
recirculated to the main condensers.

    4.   Heat  may be discharged where the owner or operator
of  a  unit  otherwise  subject  to  this   limitation   can
demonstrate  that  sufficient  land for the construction and
operation of mechanical draft evaporative cooling towers  is
not  available  (after  consideration  of alternate land use
assignments) on the premises or on adjoining property  under
the  ownership  or  control  of  the owner or operator as of
March 4, 1974 and that no  alternate  recirculating  cooling
system is practicable.

    5.   Heat  may be discharged where the owner or operator
of  a  unit  otherwise  subject  to  this   limitation   can
demonstrate that the total dissolved solids concentration in
blowdown   exceeds   30,000  mg/1  and  land  not  owned  or
controlled by the owner or operator as of March 4,  1974  is
located  within  150  meters  (500  feet)   in the prevailing
downwind  direction  of  every  practicable1   location   for
mechanical  draft  cooling  towers  and  that  no  alternate
recirculating cooling system is practicable.


    6.  Heat may be discharged where the owner  or  operator
of   a   unit  otherwise  subject  to .this  limitation  can
demonstrate to the regional administrator or State,  if  the
State  has  NPDES  permit  issuing authority, that the plume
which must necessarily emit from a cooling tower would cause
a substantial hazard to  commercial  aviation  and  that  no
alternate  recirculated cooling water system is practicable.
In making such demonstration to the  regional  administrator
or  State  the owner or operator of such unit must include a
finding by the  Federal  Aviation  Administration  that  the
                             682

-------
visible  plume  emitted  from  a well-operated cooling tower
would in fact  cause  a  substantial  hazard  to  commercial
aviation in the vicinity of a major commercial airport.


    7.   Heat  may be discharged from a unit of less than 25
megawatts generating capacity or any unit which is  part  of
an  electric  utilities  system  with a total net generating
capacity of less than 150 megawatts.

    8.  Heat may be discharged from  a unit of less than 500
megawatts generating capacity  which  was  first  placed  in
service on or before January 1, 1974.

    9.   Heat may be discharge from a unit with a generating
capacity of 500 megawatts or greater which was first  placed
in service on or before January 1, 1970.

Compliance  dates  for  effluent limitations on heat for all
but new sources is July 1, 1981 except as follows:

In the event that a regional reliability council, or when no
functioning regional reliability  council  exists,  a  major
utility  or  consortium of utilities, can demonstrate to the
regional administrator or State,  if  the  State  has  NPDES
permit  issuing authority, that the system reliability would
be seriously impacted by complying with the  effective  date
set  forth  above,  the regional administrator may accept an
alterna'feve proposed schedule of compliance on the  part  of
all  the  utilities  concerned providing, however, that such
schedule of compliance will require that units  representing
not  less than 5035 of the affected generating capacity shall
meet the compliance date, that units representing  not  less
than  an  additional  30%  of  the generating capacity shall
comply not later than July 1, 1*82 and the balance of  units
shall comply not later than July 1, 1983.
Factors

The  Agency  has  reviewed  the  bases  on which the thermal
limitations were determined to be applicable to  units  with
differing  operating  characteristics,  climatic conditions,
and site related features.   Additional  distinctions  among
units  have  been  made  as a result of this review.  A very
large number of  factors  were  considered  including  those
suggested,  as potential criteria for exemption from thermal
control, by commentors who reviewed  the  proposed  effluent
limitations  guidelines  and  standards  for  steam-electric
powerplants.  To address them in an orderly manner  requires
                            683

-------
that  those  which serve explicitly or implicitly as a basis
for distinctions in the applicability of the requirement for
closed-cycle evaporative cooling be discussed first.
(A) Age


The cost, expressed  in  relation  to  power  generated,  is
inversely  related  to  the  number of years of service life
remaining for a particular generating unit.   That  is,  the
shorter the remaining useful life over which the cost of the
cooling  system  may  be  amortized, the greater will be the
percentage of the capital cost charged against each unit  of
power generated.  Moreover, the shorter the remaining useful
life,  the  less  heat  will  be rejected to the environment
particularly since many older  units  traditionally  operate
only  during  periods  of  higher  demand.  Accordingly, the
capital cost expressed  as  a  function  of  units  of  heat
removed will be greater for older plants.


In  addition,  however,  the  absolute  cost of retrofitting
existing cnce-through units  with  closed-cycle  cooling  is
substantially greater than is the cost of installing cooling
equipment  at  new  units.   An  exemption  cast in terms of
remaining service life accomodates this disparity  but  does
so only in the most extreme cases.


In  order  to  avoid  the  additional costs of conversion of
older units to closed-cycle cooling to  the  maximum  degree
consistent  with  the  protection  of .the  environment, the
Agency has expanded the exemption based  on  age.   No  unit
placed  into  operation  before  January  1,  1970  will  be
required to meet the limitations on the discharge  of  heat.
Of  the  units placed into operation between January 1, 1970
and January 1, 1974 only the largest baseload  units   (i.e.,
those  of  500 megawatt capacity or greater) will be subject
to control.
The Agency was urged  to  exempt  all  existing  units  from
thermal  control, requiring closed-cycle cooling only of new
units.  Because of the long lead times required  for  design
and construction of powerplants, particularly nuclear units,
and   the   definition   of   the  terms  "new  source"  and
"construction" in section 306 of the Act,  this  would  have
resulted  in  confining  applicability  of the regulation to
units which will not commence operation until the end of the
                             684

-------
decade.  Moreover, the units placed into service  since  the
start of this year and those scheduled for completion during
the  next several years are typically large units.  Adopting
a "new source" cutoff  would  exempt  units  exceeding  1000
megawatts,  some  of  which  will  still  be  operating, and
discharging heat, past  the  year  2000.   In  view  of  the
extended  periods of time during which these plants would be
operating and discharging heat, the  Agency  concluded  that
they should remain subject to thermal control.


(B) Size
There are a very large number of small units (defined by the
Federal Power Commission as units in plants of 25  megawatts
or  less  and  in systems of 150 megawatts total capacity or
less).  Yet these systems and units represent  only  a  very
small  percentage of the total installed generating capacity
in the United States.  Moreover, the  potential  for  higher
costs  due  to  site specific pecularities at any given unit
could be expected to be balanced by more  favorably  located
units  in  a  larger utility system.  In very small systems,
this expectation of  counterbalancing  unit  costs  is  less
justifiable  and the costs of meeting the thermal limits may
not be economically achievable.  On this  basis  the  Agency
proposed  an exemption from the thermal limitations defining
best practicable control technology currently available  for
existing small units and systems.


The  exemption  has  been  extended  to apply to the thermal
limits   required   by   the   best   available   technology
economically  achievable, in order to preclude the necessity
of retrofitting such small units.


The promulgated regulation makes a second distinction  based
on  rated  capacity, or size.  The effect of the revision to
the regulation described above is tc exempt from controls on
thermal discharge all  units  operating  before  January  1,
197U,  except for units of 500 megawatts or greater.  In the
case of  such  very  large  units,  the  regulation  imposes
control  on  those placed into operation on or after January
1, 1970.  An analysis of a survey of 60 plants submitted  by
an   industry   representative  during  the  comment  period
indicates that the capital cost of retrofitting units placed
into service after January 1, 1970 is  inversely  correlated
with  size.   That  is,  the cost on a per kilowatt basis of
installing a mechanical draft cooling tower at a large unit.
                            685

-------
other factors being  equal,  is  typically  less  than  that
incurred by smaller units.


A  500  megawatt capacity unit's costs are approximately the
average costs of all units included  in  the  survey;  costs
will  decline  below  the  average  as  the size of the unit
increases.
Units of this size which are now less than  five  years  old
may  be  expected  to be operating for another 30 years.  In
view  of  this  extensive  remaining   service   life,   the
relatively  lower retrofitting costs, and the larger volumes
of heated water discharged, the Agency  has  concluded  that
the  largest  units  coming  on  line  since  1970 should be
included while smaller units, of comparable age, should not.


(C) Capacity Utilization


All generating units do not  produce  power  at  their  full
capacity    at   all   times.    There   are   three   major
classifications of powerplants based on the degree to  which
their  rated  capacity  is  utilized  on  an  annual  basis.
Baseload units are designed to run  at  near  full  capacity
almost  continuously.   Peaking units are operated to supply
electricity during periods of maximum system demand.   Units
which  are  operated  for  intermediate  service between the
extremes of baseload and peaking are termed cycling units.


    Generally accepted definitions term units generating  60
percent  or more of their annual capacity as baseload, those
generating less  than  20  percent  as  peaking,  and  those
between 20 and 60 percent as cycling.

Most  large units (over 300 megawatts capacity)  are baseload
units.   Baseload  units  provide  approximately  80  to  90
percent   of  the  Nation's  electric  power  and,  account,
therefore, for approximately the same  percentage  of  waste
heat.   Because  of  their  large  size  and  high  level of
utilization, uncontrolled heated discharges from these units
are generally considered to pose the greatest  environmental
risk.  •And because of their greater power output, the costs
of  retrofitting  cooling  systems  to  baseload  units   is
considerably lower in mills per kilowatt hour than costs for
peaking or cycling units.
                              686

-------
Peaking  units  account  for  less than one percent of total
effluent heat from the industry.   Moreover,  the  cost  per
unit  of  production  for  thermal  control is three to four
times that of baseload costs.   On  this  basis,  commenters
urged  the  Agency  to  exclude existing peaking and cycling
units from thermal control and the  Agency  essentially  has
done so in the regulation promulgated today.


Though  there  is  no  explicit  exemption based on capacity
utilization,  the  combined   effect   of   the   exemptions
predicated  on  age and size will effectively exclude almost
all  existing  units  operating  at  substantially   reduced
capacity factors.


Capacity   utilization   is   related   to  age.   With  few
exceptions, units begin operation  as  baseload  units.   As
they  become  older  and relatively less efficient, they are
replaced by newer more efficient baseload units and  reduced
to  cycling  service.  As they near the end of their service
life they are employed as peaking units.  By  confining  the
coverage  of the thermal limitations to units less than nine
months old  (except for those of 500  megawatts  capacity  or
greater),  the  Agency has, in effect, excluded low capacity
utilization units.  Virtually all units which have  come  on
line  since  January  1,  1970  which  are  in excess of 500
megawatts capacity are intended to be operated  as  baseload
units  at  the  time  the conversion to closed-cycle must be
effected.
 (D)  Units With Existing Closed-Cycle Cooling Systems


 Some commenters suggested that units with  existing  closed-
 cycle  systems  employing hot-side blowdown be exempted from
 the requirement of cold-side blowdown.

 The Agency agrees that incremental costs  of  converting  to
 cold-side blowdown for units which already have closed-cycle
 systems  employing  hot-side  blowdown  is  not justified in
 light of the small reduction in thermal discharge that would
 ensue.
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(E)  Salt Drift

Although the  environmental  effects  of  saltwater  cooling
towers  vary  from case to case depending on the sensitivity
of  local  environment  and  diverse  local   meteorological
conditions,  experience  with  existing  salt  water cooling
towers  indicates  that  environmental  problems  would   be
confined  to  areas in close proximity to the cooling tower.
One study showed that about 70 percent  of  all  drift  mass
fell  within  400  feet  downwind  of  a  typical  saltwater
mechanical draft tower, well within the boundaries  of  most
powerplants.  The same study showed that even under the most
adverse  conditions, all drift droplets that would reach the
ground would do so within 1000 feet downwind.   The  subject
of  this  study was an eight-cell crossflow mechanical draft
tower designed to cool 134,000 gallons per minute  of  water
with the same chemical composition and salinity as seawater.
The  plant  was located on an estuary or bay, two miles from
the  ocean.   The  drift  rate  was  O.OOU  percent  of  the
circulating water.


Airborne  drift from this tower plus natural background salt
nuclei from the sea exceeded conservative damage  thresholds
for  foliar injury for distances up to 2200 feet downwind of
the tower.  The background salt nuclei contributed  over  75
percent  of  the  salt  mass causing damage at this distance
from  the  tower.   Moreover,  the  fractional  increase  in
airborne  salt  concentrations due to drift at 2200 feet was
insignificant as compared  with  normal  variations  in  the
background  level  caused  by  changes  in  atmospheric wind
conditions.
Obviously, local plant life in areas potentially affected by
salt drift from towers must be capable of withstanding these
natural airborne salt levels if they are to survive.   Other
possible recipients of incremental salt drift would likewise
be affected by the natural ambient levels.


The  additional cost of drift eliminators does not represent
a significant increment to total  cooling  system  cost  and
should  be  reflected  in the cost estimates supplied by the
industry for plants representing  over  12  percent  of  the
Nation's total generating capacity.


Potentially  significant environmental damage over and above
that from ambient conditions may be expected to be  confined
to  areas  in  proximity  to the tower and in the prevailing
downwind direction.  The regulation  therefore  provides  an
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exemption  where  land  not  owned  by  the plant is located
within 500 feet downwind  of  every  practicable  mechanical
draft  tower  site  using  saline  intake water and where no
alternative closed cycle mode (such as natural draft  towers
which have significantly less drift loss)  is practicable.


(F) Land Availability
Some comments urged that the Agency liberalize its exemption
from  thermal control for units which do not have sufficient
land on which to construct the necessary evaporative cooling
system, suggesting that  where  the  costs  of  making  land
available  raise  the  total cost of installing closed-cycle
cooling above 1 mill per killowatt-hour the exemption should
apply.  Others recommended that,  in  order  not  to  reward
utilities  for  poor  site  planning,  the  determination of
sufficient land include property within  two  miles  of  the
unit  whether  owned  by  the utility or not, if it could be
acquired.


The size  of  the  evaporative  cooling  tower  required  is
related to the generating capacity of the unit.  Taking into
account  the  other  factors  which can influence tower size
(such as heat rate, climatic conditions,  etc.)  the  Agency
has  determined  that 28 acres per 1000 megawatts generating
capacity is ample land  on  which  any  existing  plant  can
construct  a  mechanical  draft  cooling  tower, the cooling
system  which  is  most  universally  applicable  and  which
provides  the  basis  for the Agency's cost estimates.  This
conservative area-to-capacity standard is based  on  Federal
Power Commission estimates of mechanical draft cooling tower
land  requirements  and  the  Agency's  review of mechanical
draft cooling tower land use requirements at nuclear  units,
including sufficient allowances for construction and spacing
between towers.
In  determining  whether  sufficient  land is available at a
particular site the  regulations  require  consideration  of
reassignment  of  present  land  uses   (parking  areas,  for
example)  as  well  as  the  practicability   of   alternate
evaporative  cooling  systems.   Natural  draft  towers, for
example, require less than 40 percent of the land needed for
mechanical draft towers.  The judgment of whether or not the
reassignment of  existing  land  is  practicable  cannot  be
reduced  to  a  single  cost  per  unit  of output figure as
suggested.
                              689

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Moreover, in many cases adjoining land may be  purchased  at
reasonable   cost  as  an  alternative  to  reassignment  of
existing  land  uses.   Nevertheless,  adjacent  land  costs
could,  in  some  instances, materially increase the cost of
installing closed cycle  systems.   Hence,  the  promulgated
regulations  do  not  predicate  the  exemption from thermal
limitations on the acquisition of neighboring land.  Instead
it is based solely on land owned or controlled by the  owner
or  operator of the plant as of the date of proposal of this
regulation.


(G) Aircraft Safety


Some comments urged the consideration of the possible hazard
to aircraft of steam plumes issuing from cooling towers.

    An examination of this potential hazard  indicated  that
it  is  unlikely  that  an existing powerplant which will be
required to install  a  recirculated  cooling  water  system
would pose a hazard to commercial aircraft during periods of
takeoff and landing.  However, the vulnerability of aircraft
during  this  portion of the flight pattern requires special
consideration of cases where a  substantial  hazard  may  be
shown  to  exist.   The promulgated regulation reflects this
consideration.
The  Agency  considered  exempting  units  discharging  into
oceans  or coastal waters because of two reasons advanced in
comments that were received.  First, because of the  greater
dissipative capacity of oceans, heat discharges were said to
be  less  likely to cause environmental damage.  Second, the
requirements of closed cycle cooling would exacerbate  fresh
water  shortages  which could be expected in certain coastal
areas by the year 2000 during extreme low flow conditions.


No water shortage appears evident, or likely  to  ensue,  by
the  end  of  the  century  in  Washington, Oregon, Northern
California, most Gulf Coast States, or the  Atlantic  Coast.
Moreover,   the   projection   of   increased   fresh  water
consumption was predicated on  conversion  of  all  existing
coastal  plants  from  once-through  saline systems to fresh
water evaporative towers and adoption of fresh water  towers
by  all  new  ocean  sited  plants.   Such  an assumption is
unrealistic, however, since salt water towers are  presently
in  operation and available to coastal plants in arid areas.
                             690

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Use of saline water in evaporative towers would, of  course,
have no effect on the supply of fresh water.

On  the  other  hand,  there is evidence to suggest that the
discharge of heat into marine waters at sufficient depth and
distance from biologically  sensitive  shoreline  zones  may
pose  considerably  less of a threat to the environment than
do thermal discharges into rivers, lakes and estuaries.  But
if  the  compatibility  of  thermal  discharges   with   the
environmental integrity of aquatic communities at particular
sites can be demonstrated, a modification of the limitations
on  heat  may  be made through the procedures established by
the  Agency  to  implement  section  316 (a).    The   Agency
recognized  in the proposed regulation that artificial ponds
built for cooling and located on the property of the utility
constitute an acceptable process technology for the  control
of  heat.   In response to criticisms of the lack of clarity
of the proposal, the regulation has  been  revised  to  make
clear  that  existing  units  otherwise  subject  to  a  "no
discharge"  limitation  on  heat  may  discharge  heat  into
existing  cooling lakes and ponds.  Definitions of each term
have also been provided which differentiate between "cooling
ponds" (artificial water bodies constructed by  means  other
than  impounding  the  flow of navigable water) and "cooling
lakes" (artificial  water  bodies  whose  construction  does
entail  blockage of navigable water flows) .  While new units
whose cooling system involves creation  of  an  "on  stream"
cooling lake would remain subject to the limitations on heat
discharge   from   the   condenser  into  such  a  projected
impoundment, the  provisions  of  section  316 (a)  would  be
available   to   such   units.    Chemical  discharges  into
artificial water bodies which  constitute  navigable  waters
under the Act must comply with the limitations on pollutants
other than heat.

The  Agency  is convinced that the electric utility industry
has  both  the  economic  and  technological  capability  to
install  closed  cycle  cooling systems on those units whose
thermal discharges are controlled by this regulation and  to
do  so by the compliance date established.  The estimates of
reduced  reserve  capacity  submitted   were,   the   Agency
believes,  over-stated since they assume that no units would
obtain   exemptions   under   section   316(a).    Moreover,
significant  revisions  to the proposed regulation have been
made to insure that the required conversion to  closed-cycle
is  realistic and that compliance with it entails no risk to
the continued reliable supply of electric power.  First, the
number of units potentially subject to it has  been  reduced
drastically.   Second,  the  date by which the largest units
are subjected to control has been extended by two years; the
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compliance date now being nearly seven years in the  future.
Finally, the permit issuing authority is authorized to defer
compliance for an additional two years if, despite the above
described  revision,  compliance  by  all units in a related
system could, by virtue of  outages  during  tie-in  to  the
cooling  system,  seriously impact system reliability.  This
will permit each utility to plan, design, and construct off-
stream cooling systems at the  optimum  time  in  accordance
with   planned   maintenance   schedules   as   well  as  in
consideration of reliability factors.

The Agency has reviewed the  significance  of  the  numerous
site-dependent  factors  both independently as well as their
aggregate impact.  A summary of its conclusions  as  to  the
collective  significance  of site dependent factors and each
individual variable follows.
(A)  Site-Dependent Factors in General
During the comment period, industry representatives supplied
two sets of data on the cost of installation  of  mechanical
draft  cooling  towers.   The  first  was  a  report  of  an
engineering  firm  experienced  with  the  construction   of
cooling  towers.   Its  estimate  of  the  capital  cost  of
retrofitting, on a per kilowatt  basis,  was  only  slightly
higher   than  that  used  in  the  Agency»s  original  cost
estimates of the proposed regulation.


The second was based on a survey of 60  plants,  in  several
utility systems, which represent approximately 12 percent of
the  total  steam electric generating capacity in the United
States.   The  average  capital  cost  of  this  survey  was
significantly  higher  than  the previous industry estimate;
the disparity being accounted for by the  commenter  on  the
ground  that the higher estimates reflected additional costs
attributable to site-specific factors.  The  variability  of
the  plant  by  plant  costs  reported  in the latter survey
approximates a normal distribution and ranges from about  $9
per  kilowatt  to about $8.1 per kilowatt.  The median of the
sample and the capacity weighted average cost is  $21.9  per
kilowatt.   The  Agency  adjusted  its cost estimates of the
economic impact of the final regulation to a figure  closely
approximating  this  industry-estimated cost.  Only three of
the plants reported per kilowatt costs  significantly  above
the  average  value  (in excess by 100 percent or more.) The
few exceptions with extraordinarily high cost  per  kilowatt
represent about 3 percent of the generating capacity covered
                             692

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by the sample.  Since the extensive sample of cost estimates
from  individual plants addresses all site dependent factors
in  most  instances,  and  includes  to  some  extent  costs
corresponding  to  the factors addressed specifically below,
EPA has determined that the sample  adequately  depicts  the
effects  of  the  total  of  the site dependent factors that
materially influence the costs  of  achieving  the  effluent
limitations   on   heat.    While  the  estimated  costs  of
implementing thermal controls at three of  the  plants  were
reported  to  reflect  costs  in  excess of twice the median
cost, these incremental cost factors would not significantly
affect  the   economic   achievability   of   the   effluent
limitations.    Favorable   and  unfavorable  site-dependent
factors may be expected to counterbalance one another,  when
applied  across  the  several units at individual plants and
the numerous plants  in  an  electrical  generating  system.
Hence,  the average of the cost estimates reported in the 60
plant  sample  represents  a  realistic  estimate   of   the
retrofitting  costs  likely to be encountered by any utility
system.  Even in the extraordinary case of the one plant  in
the  60  plant  sample  reporting a cost estimate of $81 per
kilowatt, the incremental cost  (above that within  which  95
percent  of  plants estimated costs reflecting site specific
factors) would not affect the economic achievability of  the
thermal  limitations.  For example, the abnormal incremental
costs at that site  ($37 per kilowatt) would add about 1 mill
per kilowatt-hour to the cost of  electricity  generated  by
that  unit.   Unusual  compliance  costs  could  impact  the
numerous  small  units  or  small  systems  more   severely.
Consequently,  these  units have been exempted categorically
from the effluent limitations on heat.
 (B)  Type of Generation


In  general,  nuclear  units  reject  more  waste  heat   to
condenser  cooling  water  than  do comparable fossil-fueled
units.  The Agency recognizes that the costs  of  installing
thermal  control  technology  are  greater  for  units which
reject more waste heat.  Nevertheless, the cost differential
due to type of generation is approximately equivalent to the
additional waste heat discharged by nuclear  plants  and  is
within  the range of costs reflecting the normal variability
among site-dependent factors in general as discussed  above.
In either case, the costs per unit of heat removed by closed
cycle  cooling would be the same.  Therefore, no distinction
need be made between nuclear and fossil-fueled units.
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Conversion of a nuclear unit from once-through cooling to  a
closed  cycle  system may entail associated modifications to
the radioactive  waste  disposal  system.   Units  employing
once-through   cooling  normally  discharge  treated  liquid
radioactive wastes to the large volumes of non-recirculating
cooling water, relying on dilution in that  stream  to  meet
water  quality  standards  on  the  discharge of radioactive
materials.  The volume of the  blowdown  from  closed  cycle
cooling   may  not  provide  sufficient  dilution  for  this
practice to be continued.  However, in three cases in  which
closed  cycle  cooling  systems  were  backfitted to nuclear
powerplants, none of the additional  costs  for  radioactive
waste  system  modification  were directly attributed to the
closed cycle backfit by the U. S. Atomic  Energy  Commission
in  its final environmental statement.  Since the Agency has
received no specific cost information concerning radioactive
waste system modification due to closed-cycle cooling system
backfitting,  no  incremental  costs  for   this   potential
modification   have  been  included  in  the  Agency's  cost
estimates.

(C)  Flow Rate

The cost of closed-cycle cooling  equipment  and  the  total
cost  of  generation  are  higher for units with higher flow
rates, all other factors being  equal.   Flow  rates  for  a
particular  unit  can  be  reduced  to  some  degree without
significant incremental cost to achieve  the  reduced  flow.
In  the  cost analysis submitted to the Agency in support of
the  proposed  subcategorization   criteria,   the   cooling
equipment  costs  for  the  cases  of highest flow rate, all
other factors being equal, were less than 10 percent  higher
than  the average cost of all cases with various flow .rates.
Total  generation  cost  were  less  than  approximately  10
percent  higher  for  the cases with the highest flow rates.
In the cost analysis for the  worst  combination  of  intake
temperature,   wet-bulb  temperature,  and  flow  rate,  the
equipment cost exceeded the average  equipment  cost  by  52
percent.   These  variations  in  equipment cost are  within
the  range  of  variations  in  cost  that  are  anticipated
considering   the   numerous   factors  that  combine,  some
favorably and some unfavorably, at each  site  to  determine
the  final  cost  of  thermal  control implementation.  A 10
percent cost differential  is  within  the  range  of  costs
reflecting   the  normal  variability  among  site-dependent
factors  in  general  as  discussed  above.   Therefore,  no
distinction need be made for this factor.
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 (D)  Heat Rate

Units  with  high  heat  rates  would  be the most costly to
control due to the high  incremental  fuel  cost  associated
with  the  increased  inefficiency  attributable  to thermal
controls.   While  no  specific   exemption   is   provided,
exemptions  based  on  age and size will exclude most of the
units with high heat rates.

 (E)  Intake Temperature

EPA recognize that units with high intake water  temperature
will  incur  higher  costs,  all  other factors being equal.
This factor,  however,  is  significant  mainly . during  the
months  when  the  high  intake water temperatures occur and
also for those units for which high levels of blowdown  flow
are necessary, thus requiring relatively large quantities of
makeup  water.   It  is not as significant a factor for most
units which require normal quantities of makeup water  flow.
In  the  cost analysis submitted to the Agency in support of
the proposed subcategorization  criteria,  this  factor  all
other  factors being equal, added a maximum of 20 percent in
the most extreme case to the average total  thermal  control
equipment cost.  This 20 percent cost differential is within
the  range  of costs reflecting the normal variability among
site-dependent  factors  in  general  as  discussed   above.
Therefore, no distinction need be made for this factor.

 (F)  Wet-Bulb Temperature

EPA  tested  the  significance  of wet-bulb temperature as a
factor by  costing  various  types  of  evaporative  cooling
systems considering four geographic locations representative
of  the range of wet-bulb temperatures in the United States.
The cost  of  cooling  equipment  at  the  most  unfavorable
location based on wet-bulb temperature was 25 percent higher
than the average cost of all locations tested for conditions
otherwise  identical.  In the cost analysis submitted to the
Agency  in  support  of   the   proposed   subcategorization
criteria,  this factor, all other factors being equal, added
a maximum  of  24  percent  to  the  total  thermal  control
equipment  cost  for the average of subcases covered for the
most  costly  case   analyzed.    This   21   percent   cost
differential  is  within  the  range of costs reflecting the
normal variability among site-dependent factors  in  general
as  discussed above.  Therefore, no distinction need be made
for this factor.

 (G)  Back-End Loading

The back-end loading of a unit is  the  maximum  steam  flow
which the unit can pass through the last stage blades of the
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low  pressure  turbine  expressed  as  a  percentage  of the
maximum steam flow through the last stage blades  which  the
turbine is capable of accepting.

In  the  cost analysis submitted to the Agency in support of
the proposed subcategorization criteria,  this  factor,  all
other  factors being equal, added a maximum of 22 percent to
the total thermal control equipment costs  compared  to  the
average  of  the  cases covered.  The maximum cost reflected
the cost for a unit with a back-end loading of approximately
15 percent. • Generation costs in mills per kilowatt-hour for
the worst  case  of  a  15  percent  back-end  loading  were
estimated  to  be  about  1 mill per kilowatt-hour.  This 22
percent differential in equipment costs is within the  range
of  costs  reflecting  the  normal  variability  among site-
dependent factors in general, as discussed above.  The worst
case  generation  cost  is  in  the  range  recommended   by
industry,  therefore,  no  distinction need be made for this
factor.

(H)  Plume Abatement

Cooling towers can  produce  visible  plumes  consisting  of
minute  water  droplets.   Plumes are normally not a problem
unless they reach the ground and obstruct  vision  or  cause
icing  conditions.   Under  normal conditions, cooling tower
plumes rise due to their initial velocity and  buoyancy  and
rarely  intersect  the ground before they are mixed with the
ambient air and dissipated.  However, under adverse climatic
conditions (i.e., high humidity and  low  temperature),  the
moisture could produce a fog condition if it were trapped in
the  lower  levels  of  the  atmosphere during an inversion,
i.e., a period of high atmospheric stability.  In almost all
cases, natural draft towers are less likely to cause fogging
problems than mechanical draft towers.  Even with mechanical
draft towers, in most cases fogging or icing  would  be  on-
site   (i.e.,  within  1000-2000  ft  of  the  tower).  Plume
abatement  technology,  e.g.,  wet-dry  cooling  towers,  is
currently  available.   While wet-dry towers are more costly
than conventional wet towers, the Agency has  accounted  for
the  cost  of employing plume abatement in specific cases in
its estimate of the  cost  of  codling  tower  construction.
This  estimate  is  based on cost data supplied by industry.
The industry estimates,  in  turn,  were  developed  from  a
sample  of  60  plants and units and the costs for 18 of the
units in the sample reflected the  use  of  wet-dry  towers.
Hence,  no  specific  exemption  based  on the potential for
plume  generation  is  warranted  except  where  the   plume
presents a substantial hazard to aircraft flight paths.
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(I)  Noise Abatement Costs

EPA  recognizes  that incremental costs would be incurred in
cases where mechanical  draft  cooling  towers  may  require
noise  control.  Little information is available on the cost
of  implementing  noise  control  procedures  on  powerplant
cooling  tewers  principally  because  it  has  rarely  been
necessary to employ these measures, even though  powerplants
with  cooling  towers  exist  in  areas  of  high population
density.  It is doubtful that there will  be  a  significant
need  for  this  technology  as a result of this regulation,
since many plants in areas of high population  density  will
be  exempted  because  of  the  lack  of sufficient land for
closed-cycle cooling systems,  because  of  the  salt  drift
exemption,  or  because  of  the  exemptions based on age or
size.  Furthermore, alternative thermal control technologies
may be employed that are generally quieter  than  mechanical
draft cooling towers.  In the only case cited by commenters,
a  plant  in West Germany was reputed to have incurred twice
the normal capital  cost  for  cooling  towers  due  to  the
installation  of  noise  control  equipment.  This is a most
unusual case indeed.  The plant cited is in West  Berlin,  a
politically  land  locked  community  isolated  from outside
power sources.  Increased demand and a paucity of  available
sites  required  that  a  new  plant be constructed in close
proximity to  residences  in  an  area  of  high  population
density,  hence,  the  need  for noise abatement technology.
Furthermore, it is  significant  that  cooling  towers  were
employed  with  noise suppressors in order to take advantage
of the site while accomodating the need to reduce  noise  to
locally required levels.

(J)  Miscellaneous Factors

Certain   additional   site-dependent   factors   have  been
suggested  by  commenters  which  should  be  considered  in
subcategorization  for  effluent limitations on heat because
they can materially affect  cost;  existing  system  layout,
soil  conditions, site geology, and topography.  While it is
acknowledged that  these  factors  may  affect  case-by-case
costs,  the  costs  attributable  to  these  and other site-
dependent factors have been assumed in  the  computation  of
the economic costs of thermal control.  All evaporative heat
rejection  systems consume water.  Even once-through systems
result  in  water  consumption  by  evaporation  during  the
transfer  of  heat  from  the  receiving  water  body to the
atmosphere.  Consumptive use of water  by  mechanical  draft
towers exceeds that of once-through systems by approximately
50-75  percent.   Evidence  received by the Agency suggested
that were  all  existing  and  new  plants  covered  by  the
                            697

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proposed  regulation  to  install  close  cycle cooling,  the
increase in water consumption by the  year  2000  over  that
which  would be consumed by extrapolation of the 1970 mix of
cooling systems to the generating capacity expected to be on
line in that year, would approximate 8.5 billion gallons per
day.  This  projected  increase,  which  was  based  on  the
assumption  that  no  plants  would qualify for an exemption
under section 316 (a) of the Act during the  next  25  years,
was  conceded to be relatively insignificant compared to the
total water available in the United  States  during  average
flow   conditions.    Federal   Power   Commission  supplied
estimates  of  water  consumption  attributable  to   closed
cycling  cooling  suggest that the actual consumption may be
significantly lower.

However, for certain regions, the  projected  increase  when
compared  to  the  10 and 20 years drought conditions, would
increase water deficits assumed to exist even in the absence
of closed  cycle  consumptive  use.   The  regions  of  most
concern are Southern California and the Texas Gulf.

Much  of  the 3.8 percent increase in deficit for California
under  the  20  year  low  flow  conditions  appears  to  be
attributable  to  the  assumption  that  coastal plants will
convert  to  freshwater  rather  than  saline  towers.   The
deficiencies   of   this   assumption  have  been  discussed
previously.  In addition, however, the final regulation  has
been  revised  to  exempt most units constructed before 1974
from thermal control.   Virtually  all  presently  operating
coastal  units  (which  represent nearly half of the present
generating capacity in California) will thus be exempt.   To
the extent that expansion of generating capacity is composed
of new coastal units, the utility is free to select sites at
which  the  discharge  would protect the balanced indigenous
aquatic community,  thus  qualifying  for  exemptions  under
section   316 (a)   and   avoiding  any  consumptive  use  of
freshwater.  Moreover, saltwater  cooling  towers  could  be
used  at  coastal  sites  with the result that no freshwater
would be consumed.

In other arid regions, such as Texas,  use  of  closed-cycle
evaporative  cooling systems (both towers and cooling ponds)
is  already  widespread  for   technological   rather   than
environmental  reasons,  since  the  available surface water
supply is  not  adequate  for  once-through  cooling  to  be
effective.    Much   of   the   increase  in  the  projected
consumptive use appears attributable to the assumption  that
cooling  towers would have to be constructed at existing man
made  cooling  lakes  and  offstream  cooling  ponds.    The
regulation has been revised to make clear that cooling lakes
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and  ponds  meeting  certain  specifications  are considered
acceptable heat abatement mechanisms and  that  towers  need
not be constructed if such a system is in operation.

Powerplants  normally  place generating units out of  service
on a scheduled basis for periods of a month or more in order
to perform necessary maintenance.  Units may  also  be  shut
down  from  time  to  time  for unplanned maintenance.  When
units  are  shut  down,  the  lost  generating  capacity  is
supplied  by somewhat less efficient units within the system
or by purchase  of  power  from  outside  the  system.   The
installation  of  new  generating capacity in a system takes
into account, on a projected basis, the user demand  in  its
service  area  and  such  additional  factors  as  scheduled
outages and probabilities of unscheduled outages.   A  well-
engineered  retrofit design could be scheduled for tie-in to
an existing system in from one week to five weeks of   actual
unit  outage  time.   The  regulation  has  been  revised to
exclude most existing units  from  thermal  control  and  to
defer  the  date  of  conversion  for the remaining affected
units from 1978 to 1981.   Moreover,  the  final  regulation
incorporates  commenters1  suggestions  for  flexibility  in
further  extending  compliance  dates  in  order  to   avoid
adversely  impacting  regional  reliability.  The Agency has
determined that tie-in outages can be scheduled concurrently
with planned maintenance in such a  manner  that  one  month
outage   time  would  be  required  in  addition  to  normal
maintenance and that replacement power  during  this  period
can be supplied by the system's cycling units.  Since no net
loss in generating capacity need occur for closed-cycle tie-
ins, there is no need for capital expenditures to be debited
against outages during construction.

The  Agency  estimates that the effluent limitations on heat
will increase the utility industry's capital requirements by
an additional 5.2 billion dollars by 1983, without  allowing
for the reduction in capital cost which may be expected as a
result  of  exemptions from the thermal limitations obtained
under section 316 (a).  (These and all  other  estimates  are
expressed   in   constant   197U  dollars).   The  operating
expenditures during the period 1974-1983 associated with the
thermal limitations are estimated to be 1.3 billion  dollars
before  316 (a)  exemptions, an increase O.U percent of total
industry operating expenses.

    The fuel penalty associated with the thermal limitations
consists of additional fuel required to operate the  closed-
cycle  cooling  system  and  additional  fuel  required  per
kilowatt-hour  resulting  from  efficiency  losses  due   to
increased  turbine  back-pressure.  The combined annual fuel
                           699

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penalty is approximately 3 percent.  In addition, there will
be a transient 2.1  percent  fuel  penalty  associated  with
generation  of  interim  replacement capacity during outages
for conversion to closed cycle.  The fuel penalty  estimated
represents  approximately  16  million  tons  of coal (a 1.6
percent increase in projected  1983  coal  consumption)   and
44,000  barrels  per  day  of oil  (a 0.2 percent increase in
projected 1983 oil consumption) .

The effect of  capital  and  generating  costs  for  thermal
control  would increase the cost of electricity to consumers
by a maximum of 2.2 percent by 1983.  This price increase is
not expected to have a significant affect on the  growth  of
demand  for  electricity.  Moreover, while the capital costs
are substantial in absolute terms, they  represent,  without
accounting for expected exemptions from thermal limitations,
approximately 3 percent of the capital which the industry is
planning to invest over the next decade for expansion of its
generating  capacity.   The  Agency  has  concluded that the
industry  will  be  able  to  obtain  sufficient  additional
capital  to  finance  the  expenditures  for water pollution
control.

    The costs of complying with the water pollution  control
requirements  are  not  expected  to  have any effect on the
production of electricity nor on employment in the industry.
                               700

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                         SECTON XII

                      ACKNOWLEDGMENTS

The development of this report was accomplished through  the
efforts  of  Burns and Roe, Inc., and Dr. Charles R. Nichols
of the Effluent Guidelines Division.   The  following  Burns
and  Roe,  Inc.,  technical  staff  members made significant
contributions to this effort:

    Henry Gitterman, Director of Engineering
    John L. Rose, Chief Environmental Engineer
    Arnold S. Vernick, Project Manager
    Phillip E. Bond, Senior Supervising Mechanical Engineer
    Suleman Chalchal, Chemical Engineer
    Ernst I. Ewoldsen, Senior Mechanical Engineer
    William A. Foy, Senior Environmental Engineer
    Dr. Benjamin J. intorre, Engineering Specialist
    Paul D. Lanik, Environmental Engineer
    Geoffrey L. Mahon, Mechanical Engineer
    Dr. Shashank S. Nadgauda, Senior Chemical Engineer
    Dr. Edward G. Pita, Senior Mechanical Engineer
    Richard T. Richards, Supervising Civil Engineer
    Harold J. Rodriguez, Senior Chemical Engineer

The physical preparation of this document  was  accomplished
through  the  efforts  of  the  secretarial  and  other non-
technical staff members at Burns  and  Roe,  Inc.,  and  the
Effluent  Guidelines  Division.   Significant  contributions
were made by the following individuals:

    Sharon Ashe, Effluent Guidelines Division
    Brenda Holmone, Effluent Guidelines Division
    Chris Miller, Effluent Guidelines Division
    Kaye Starr, Effluent Guidelines Division
    Alice Thompson, Effluent Guidelines Division
    Nancy Zrubek, Effluent Guidelines Division
    Marilyn Moran, Burns and Roe, Inc.
    Edwin L. Stenius, Burns and Roe, Inc.

The contribution of Ernst P. Hall, Deputy Director, Effluent
Guidelines Division, were vital to the publication  of  this
report.

The  members  of  the  working group/steering committee, who
contributed  in  the  preparation  of  this   document   and
coordinated the internal EPA review in addition to Mr. Cywin
and Dr. Nichols are:

    Walter J. Hunt, Chief, Effluent Guidelines
                            701

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      Development Branch, EGD
    Dr. Clark Allen, Region VI
    Alden Christiansen, National Environmental Research
      Center, Corvallis
    Swepe Davis, Office of Planning and Management
    Don Goodwin, Office of Air Quality Planning and Standards
    William Jordan, Office of Enforcement and General Counsel
    Charles Kaplan, Region IV
    Steve Levy, Office of Solid Waste Management Programs
    Harvey Lunenfeld, Region II
    George Manning, Office of Research and Development
    Ray McDevitt, Office of Enforcement and General Counsel
    Taylor Miller, Office of Enforcement and General Counsel
    James Shaw, Region VIII
    James Speyer, Office of Planning and Evaluation
    Howard Zar, Region V

Acknowledged are the contributions of Dennis Cannon, Michael
LaGraff,  Ronald  McSwiney,  and Lillian Stone, all formerly
with the Effluent  Guidelines  Division.   The  EPA  Project
Officer  also acknowledges the assistance of his wife, Janet
Nichols.

Other EPA and State personnel contributing  to  this  effort
were:

    Allan Abramson, Region IX
    Walter Barber, Office of Planning and Evaluation
    Ken Bigos, Region IX
    Paul Brands, Office of Planning and Evaluation
    Carl W. Blomgren, Region VTI
    Danforth G. Bodien, Region X
    Robert Burm, Region VIII
    Richard Burkhalter, State of Washington
    Gerald P. Calkins, State of Washington
    Robert Chase, Region I
    Barry Cohen, Region II
    William Dierksheide, Region IX
    William Eng, Region I
    Joel Golumbek, Region II
    James M. Gruhlke, Office of Radiation Programs
    Joe Hein, Office of Water and Hazardous Materials
    Joseph Hudek, Region II
    Victor Kimm, Office of Planning and Management
    William R. Lahs, Office of Radiation Programs
    Frederick D. Leutner, Office of Water and Hazardous
      Materials
    John Lum, Region II
    Dr. Guy R. Nelson, National Environmental Research
      Center, Corvallis
                             702

-------
    Dr. M. Perez, National Marine Water Quality Laboratory
    Dr. Jan Praeger, National Marine Hater Quality
      Laboratory
    Ms. Lillian Regelson, Office of Water and Hazardous
      Materials
    Dr. Courtney Riordan, Office of Technical Analysis
    Dr. Eric Schneider, National Marine Water Quality
      Laboratory
    William H. Schremp, Region III
    Edward Stigall, Region VIJ
    Dr. Bruce A. Tichener, National Environmental Research
      Center, Corvallis
    Dennis Tihanjky, Office of Planning and Evaluation
    Srini Vasan, Region V
    Dr. Joseph V. Yance, Office of Water and Hazardous
      Materials
    Michele Zarubica, Office of Planning and Evaluation

Additional comments were received from:

    Effluent Standards and Water Quality Information
      Advisory Committee
    Dr. William A. Brungs, National Water Quality Laboratory
      Duluth
    Dr. W. D. Rowe, Office of Radiation Programs
    E. David Harvard, Office of Radiation Programs
    Dr. A. Gordon Everett, Office of Technical Analysis
    Carl J. Schafer, Jr., Office of Enforcement and
      General Counsel
    Joel L. Fisher, Office of Program Integration
    Jerome H. Svore, Region VII
    John A. Green, Region VIII
    Richard L. O'Connell, Region IX
    Jack E. Ravan, Region IV
    Arthur W. Busch, Region VI

Federal agencies cooperating were:

    Atomic Energy Commission
    National Marine Fisheries Service, National Oceanographic
     and Atmospheric Administration, Department of Commerce
    Bureau of Land Management, Department of the Interior
    Bureau of Sport Fish and Wildlife, Department of the
      Interior
    Federal Power Commission  .
    Rural Electrification Administration, Department of
      Agriculture
    Tennessee Valley Authority
                             703

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Additional comments were received from:

    Honorable Mike McCormack
    Department of the Treasury
    Water Resources Council
    Department of Defense
    Honorable David R. Bowen
    Honorable Omar Burlesson
    Honorable Harold T, Johnson
    Honorable Edmund S, Muskie
    Honorable Charles Wilson
    Honorable James Wright

The Environmental Protection Agency also wishes to thank the
representatives  of  the steam electric generating industry,
including the Edison Electric Institute, the American Public
Power Association  and  the  following  utilities,  regional
systems  and governmental agencies for their cooperation and
assistance in arranging plant visits and furnishing data and
information.

    Alabama Power Company
    Bewag
    Canal Electric Company
    Central Hudson Gas and Electric Corporation
    Central Electricity Generating Board, United Kingdom
    Commonwealth Edison Company
    Consolidated Edison Company of New York, Inc.
    Consumers Power Company
    Duke Power Company
    Economic Commission for Europe, Committee on Electric
      Power
    Florida Power and Light company
    Fremont, Nebraska Department of Utilities
    MAPP Coordination center for the Mid-Continent
      Area Power Systems
    New England Power Company
    New York Power Pool
    New York State Electric and Gas Corporation
    Niagara Mohawk Power Corporation
    Nordostschweizerische Kraftwerke AG
    Omaha Public Power District
    Pacific Gas and Electric Company
    Pacific Power and Light company
    Pennsylvania Power and Light Company
    Portland General Electric company
    Potomac Electric Power Company
    Preussag AG
    Public Service Company of Colorado
    Public Service Electric and Gas Company
    Sacramento Municipal Utility District
                            704

-------
    Southern California Edison Company
    Taunton, Massachusetts Municipal Lighting Plant
    Texas Electric Service Company
    Vereninigte Elektrizitatswerke Westfalen AG
    Virginia Electric and Power Company
    Volkswagenwerk AG

Acknowledgment is also made to the  following  manufacturers
for  their  willing  cooperation  in  providing  information
needed in the course of this effort.

    Allen-Sherman-Hoff
    Balcke-Durr
    Butterworth System Inc.
    Ceramic Cooling Tower Company
    Ecodyne corporation
    GEA-Gesellschaft fur Luftkondensation m.b.H.
    General Electric Company
    Inland Environmental
    Research-Cottrell, Inc., Hamon Cooling Tower Division
    Resources Conservation Company
    Richards of Rockford, Inc.
    Stephens-Adamson
    The Marley Company

Additional comments were received from:

    State of California
    State of Colorado
    State of Illinois
    State of Indiana
    State of Iowa
    State of Maryland
    State of Michigan
    State of Minnesota
    State of Ohio
    State of New York
    Commonwealth of Puerto Rico
    State of Texas
    State of Wisconsin
    Mississippi Power and Light Company
    Arkansas Power and Light Company
    West Associates
    City of Colorado Springs Nebraska Public Power
      District
    American Electric Power Service Corporation
    The Dayton Power and Light Company
    International Ozone Institute, Inc.
    City Public Service Board of San Antonio, Texas
    The Toledo Edison Company
                              705

-------
Ford Motor company
Baltimore Gas and Electric Company
Jersey Central Power and Light Company
Metropolitan Edison Company
Pennsylvania Electric company
National Electric Reliability Council
Public Service Company of New Mexico
United Illuminating
Copper Development Association, Inc.
The Cincinnati Gas and Electric Company
Illinois Power Company
Indianapolis Power and Light Company
Tri-State Generation and Transmission Association,
  Inc.
western Illinois Power Cooperative, Inc.
Alabama Electric Cooperative, Inc.
Wisconsin Public Service Corporation
N.W. Electric Power cooperative. Inc.
American Cyanamid Company
Carolina Power and Light Company
Foote Mineral Company
Cooperative Farm Chemicals Association
Pollution and Environmental Problems
Ebasco Services Incorporated
Brazos River Authority
Dr. Charles C. Goutant
Mr. Basil A. Bonk
Diamond Shamrock Chemical Company
Offshore Power Systems
Hawaiian Electric Company, Inc.
United for Survival
Mr. James R. Raring
Nalco Chemical company
Dow Chemical U.S.A.
Dairyland Power Cooperative
St. Joseph Light and Power Company
Burns and McDonnell Engineering Company
Bethlehem Steel Corporation
The Metropolitan Water District of Southern
  California
Washington Public Power Supply System
Wright Chemical corporation
Mr. James W. Errant, Jr.
Texas Water Conservation Association
Ms. Constance A. Partious, League of Women Voters
Mr. David Allen
Mr. David B. Harvey
Mrs. Marvin Halye
Mr. Bruce Haflich
Mr. Samuel Labouisse, Jr.
                           706

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Connie Economy
Mr. Christopher A. Libby
Mr. Zachary A. Smith
Mr. Marion L. Sanford
Mr. Henry Peck
American Association of University Women
Ms. Lea P. Tonkin
Illinois Paddling Council
League of Women Voters
Mr. Roger H. Miller
Rohm and Haas Company
Mr. M. David Burghardt
Calgon Corporation
Stone and Webster Engineering Corporation
The Michigan Riparian, Inc.
Olin Water Services
Mrs. Martha K. Rudnicki
Don and Lynda Johnson
Mr. Lawrence D. Bahr
Mr. Harry L. Stout
Betz Laboratories, Inc.
Save the Dunes Council
Mr. and Mrs. John N. Lally
United Refining Company
Mr. J. C. Berghoff
Mr. Edward G. Talbot
Mr. Harlan Sandberg
Mr. Stephen C. Grado
Mr. Scott M. Bailey
Mr. David M. Peterson
Mr. David Levine
Mr. Don Pur it on
A. T. Economy and Tenya Economy
County of Monroe, New York
Mr. Steve Kraatz
Mr. R. Fenton Rood
Alaska Center for the Environment
Mrs. Marie B. Pettit
General Electric Company
Airco Alloys and Carbide
Johnson and Anderson, Inc.
Utah Power and Light Company
Middle South Services, Inc.
Natural Resources Defense Council, Inc.
Lake Michigan Federation
Mead
ECAR
Salt River Project
Houston Lighting and Power Company
Kansas City Power and Light Company
                            707

-------
Duquesene Light
Ohio Edison Company
Louisiana Power and Light
Arizona Public Service Company
Consolidated Edison Company of New York, Inc.
Wisconsin Electric Power Company
Toledo Edison
Arkansas Electric Cooperative Corporation
Northern States Power Company
Plains Electric Generation and Transmission
  Cooperative, Inc.
Houghton Cluck Coughlin and Riley
Consumers Power Company
Bechtel Power Corporation
Buckeye Power Incorporated
Association of California Water Agencies
New Orleans Public Service, Inc.
Minnkota Power Cooperative, Inc.
Associated Electric Cooperative
Continental Can Company, Inc.
Columbus and Southern Ohio Electric Company
Dolph Briscoe, Governor of Texas
San Diego Gas and Electric Company
Quirk, Lawler and Matusky Engineers
Department of Water and Power of the City of
  Los Angeles
Basin Electric Power Cooperative
Business and Professional People for the Public
  Interest
Gulf Power Company
Atlantic City Electric
Southern Services, Inc.
Union Electric Company
E.I. du Pont de Nemours Company, Incorporated
Tucson Gas and Electric Company
California Farm Bureau Federation
Regional Planning council
Mr. Mayne E. Boiling
University of Texas
Mr. & Mrs. William Morlock
Ms. Alice Thornycroft
Mr. & Mrs. Fred and Peggy McAllister
Mrs. Robert Burke
Ms. Catherine Benner
Mr. Frank Lahr
Mr. & Mrs. Robert Upton
Dr. & Mrs. Dean Asasselin
Dr. & Mrs. D. Steinberg
South Texas Electric Cooperative, Inc.
Olin Brass
                         708

-------
Eastern Iowa Light and Power Cooperative
Shoreline Garden Club
Mr. Lawrence C. Frederick
Edison Electric Institute
National Rural Electric Cooperative Association
The Utility Water Act Group
Newberry Electric Cooperative
State of South Carolina
State of Arizona
Atomic Industrial Forum, Inc.
Delaware River Basin Commission
Montana-Dakota Utilities
E. B. Puspley
West Texas Utilities Company
Southern Electric Generating Company
John Eric Edinger, Ph.D.
North Central Missouri Electric Cooperative, Inc.
NUS Corporation
Texas Power and Light Company
Tennessee Valley Public Power Association
Southwestern Electric Power Company
Allegheny Power Service Corporation
Southern Central Power Company
Interlakes, Inc.
Missouri Clean Water Commission
Dallas Power and Light Company
Cajun Electric Power Corporation
Crawford Electric Cooperative
Dixie Electric Membership Corporation
Association of Illinois Electric Cooperatives
Rural Electric Convenience Cooperative Company
People»s Cooperative Power Association, Inc.
Jefferson Davis Electric Cooperative, Inc.
State of North Carolina
State of Nebraska
State of Kentucky
State of Georgia
Golden Valley Electric Association, Inc.
Hudson River Fisherman's Association
North Pine Electric Corporation, Inc.
Carteret-Craven Electric Membership Corporation
State of Pennsylvania
Public Service Comapny of New Hampshire
Jo-Carroll Electric Cooperative, Inc.
Roanoke Electric Membership Corporation
Tri-county Electric Cooperative
Plains Electric Generation and Transmission
  Cooperative
Pierce-Pepin Electric Cooperative
Tri-County Rural Electric Cooperative, Inc.
                        709

-------
Union Rural Electric Association, Inc.
Western Illinois Power Cooperative, Inc.
Edgecomb-Martin County Electric Membership
  Corporation
Burke Divide Electric Cooperative
Renville Sibley Cooperative Power Association
State of Alaska
State of Hawaii
                          710

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                        SECTION XIII

                         REFERENCES
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2.    "A Method for Predicting the Performance of Natural Draft
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3.    "A Potassium Cycle Boosts Efficiency", Business Week,
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i*.    "A Report by MARCA to the Federal Power Commission
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5.    "A Summary of Environmental Studies on Water Problems",
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6.    "A Survey of Alternate Methods for Cooling Condenser
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7.    "A Survey of Alternate Methods for Cooling Condenser
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8.    "A Survey of Alternate Methods for Colling Condenser
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9.    "A Survey of Alternate Methods for Cooling Condenser
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10.   "A Survey of Thermal Power Plant Cooling Facilities",
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                               711

-------
11.   Abrahamson, D. E., "Environmental Cost of Electric Power",
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12.   "Advanced Nonthermally Polluting Gas Turbines In Utility
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13.   "Air Pollution & the Regulated Electric Power 6 National
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14.   Albrecht, A. E., "Disposal of Alum Sludges", Journal AWWA,
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15.   "An Engineering - Economic Study of Cooling Pond
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16.   "Annual Plant Design Report", Power, pp. S.l-S.24,
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17.   "1972 Annual Report of National Electric Reliability
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18.   Argo, D. G., and G. L. Gulp, "Heavy metals removal in
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19.   Aschoff, A. F., "Water Reuse in Industry", Mechanical
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20.   Askew, T., "Selecting Economics Boiler-Water Pretreatment
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21.   Aynsley, E., and M. R. Jackson, "Industrial Waste
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22.   Christiansen, P. B., and  D. R. Colman, "Reduction of Slowdown
      from Power Plant Cooling Tower Systems", American Institute
      of Chemical Engineers Seminar or Cooling Towers, Houston,
      Texas  (1968) .
                              712

-------
23.   Beall, S. E., Jr., "Uses of Haste Heat", Research
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2U.   Beall, S. E., Jr. and A. J. Miller, "The Use of Heat
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25.   Beardsley, J. A., "Use of Polymers in Municipal Water
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26.   Berthoulex, P. M., "Evaluating Economy of Scale",
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27.   Betz Handbook of Industrial Water Conditioning* Beta,
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28.   Bishop, D. F., et al, "Physical-Chemical Treatment of
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29.   Black, A. P., "Recovery of Calcium and Magnesium Values",
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30.   Boersma, L., "Beneficial Use of Waste Heat in
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31.   "Boiler-Water Treatment",  (source unknown).

32.   Brady, D. K., et al, "Cooling Water Studies for Edison
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33.   Browning, J. E., "Ash - The Usable Waste", Chemical
      Engineering,  (April 16, 1973).

3H.   Budenholzer, R. J., et al, "Selecting Heat Rejection
      Systems for Future Steam-Electric Power Plants".
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35.   Bugg, H. M., et al, "Polyelectrolyte Conditioning of Alum
      Sludges", Journal AWWA, pp. 792-795,  (December, 1970).

36.   Burd, R. S., "A Study of Sludge Handling and Disposal",
      U. S. Department of the Interior, Federal Water Pollution
      Control Administration Publication WP-20-4  (May, 1968).
                              713

-------
37.   "California's Projected Electrical Energy Demand and Supply"
      Assembly Science 6 Technology Advisory Council, A report
      to the Assembly General Research Committee California
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38.   "Canals Cool Hot Water for Reuse", Environmental Science
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39.   Cecil, L. K., "Water Reuse and Disposal", Chemical
      Engineering, (May 5, 1969).

40.   Cheremisinoff, P. N., et al, "Cadmium, Chromium, Lead,
      Mercury: A Plenary Account for Water Pollution.  Part I -
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      Techniques", Water and Sewage Works, (July - August, 1972).

41.   Christopher, P. J., and V. T. Forster, "Rugeley Dry Cooling
      Tower System", Proceedings of Institution of Mechanical
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42.   Christiansen, A. G., and B. A. Tichenor, "Economic
      Aspects of Thermal Pollution Control in the Electric
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      1969).

43.   Christiansen, P. B., and D. R. Colman, "Reduction of Blow-
      down from Power Plant Cooling Tower Systems", A.I.Ch.E.
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      Pollution Control, Houston, Texas (April 24-25, 1969).

44.   "Clean-Air Route Has Made-In Mexico Label", Chemical
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45.   "Cleaning Up SO2", Chemical Engineering,
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47.   Cohen, J. M., and I. J. Kugelman, "Wastewater Treatment -
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                              714

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50.   "Control of Air Pollution from Fossil Fuel-Fired Steam
      Generators Greater than 250 x 10* Btu/Hour Heat Input",
      Environmental Protection Agency, Durham, North Carolina.
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      The Marley Company (1969).
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      Money?", Electric Light and_Power, pp. 36-39, (October,
      1972).
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      Electric Light and Power, pp. 45-U8,  (November, 1972).
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57.   "Cooling Towers - Special Report", Industrial Water
      Engineering, (May, 1970) .
58.   "Cost of Wastewater Treatment Processes", Robert A. Taft
      Water Research Center, FWPCA Report No. TWRC-6,  (1968).
59.   Cox, R. A., "Predictions of Fog Formation Due to A Warm
      Water Lagoon Proposed for Power Station Cooling",
      Atmospheric Environment, Vol. 7, pp. 363-368, Pergamon
      Press,  (1973) .
60.   Culp, R. L., "The Operation of Wastewater Treatment
      Plants", Part I, II 6 III, Public Works,  (October,
      November and December, 1970).
61.   "Cumulative Research Index to FPC Reports", Vol. 19-35,
      (January, 1958 - June, 1966).
62.   Curtis, S. D., and R. M. Silverstein,   "Corrosion and
      Fouling Control of Cooling Waters", Chemical Engineering
      Progress, Vol. 67, No. 7, pp. 39-4U,  (July, 1971).
                               715

-------
63.   Cywin, A., "Engineering Water Resources of the Future",
      Paper presented at the ASME Winter Annual Meeting,
      (November, 1970).

64.   Cywin, A., "Engineering Water Resources for 2070",
      Mechanical Engineering, pp. 7-9, (July, 1971).

65.   Dallarie, E. E., "Thermal Pollution Threat Draws Nearer",
      Civil Engineering, ASCE, pp. 67-71 (October, 1970).

66.   Davis, J. C., "Scrubber-Design Spinoffs from Power Plant
      Units", Chemical Engineering, Vol. 79, No. 28,
      (December 11, 1972).

67.   Dean, J. G., et al, "Removing Heavy Metals from Waste-
      water", Environmental Science and Technology, Vol. 6,*
      No. 6, pp. 518-522, (June, 1972) .

68.   Decker, F. W.,  "Report on Cooling Towers and Weather"
      Report for FWPCA, Corvallis, Oregon.

69.   De Filippi, J. A., "Designing Filtration Plant Waste
      Disposal Systems", Journal AWWA, 64:3:185,  (March, 1972).

70.   De Flon, J. G., "Design of Cooling Towers Circulating
      Brackish Waters", Ind. & Proc. Design for Water Pollution
      Control, Workshop of AIChE,  (April 24-25, 1969).

71.   DeMonbrun, J. R., "Factors to Consider in Selecting a
      Cooling Tower", Chemical Engineering,  (September 9, 1968).

72.   Derrick, A. E., "Cooling Pond Proves to be the Economic
      Choice at Four  Corners", Power Engineering,  (November,
      1963).

73.   "Development and Demonstration of Low-Level Drift
      Instrumentation", Water Pollution Control Research
      Series, EPA, 16130 GNK 10/71  (October, 1971).

74.   Dickey J. B., Jr., "Managing Waste Heat with the Water
      Cooling Tower", The Marley Company (1970).

75.   "Directory", Public Power, Vol. 31, No. 1,  (January -
      February, 1973) .

76.   "Dive Into Those Intakes", Electric Light & Power,
      E/G edition, pp. 52-53,  (November, 1972).

77.   Donohue, J. M., and G. A. Woods, "Onstream Desludging
      Restores Heat Transfer", Betz Laboratories, Inc.,  (1967).
                              716

-------
78.    Doran, J. J., Jr., "Electric Power - Impact on the
      Envi ronmentn, Proceedings American Power Conference,
      32, pp. 1029-1036, (1970).

79.    Drew, H. R., and J. E. Tilton, "Statement of the Electric
      Reliability Council of Texas  (ERCOT)M at the Texas Water
      Quality Board Hearing on Texas water Quality Standards,
      (April 6, 1973) .

80.    Drew, H. R., and J. E. Tilton, "Review of Surface Water
      Temperatures and Associated Biological Data as Related
      to the Temperature Standards in Texas."  Presented at
      Texas Water Quality Board Hearing on Texas Water Quality
      Standards, (April 6, 1973).

81.    Drew, H. R., and J. E. Tilton, "Thermal Requirements
      to Protect Aquatic Life in Texas Reservoirs", Journal
      Water Pollutign^Control Federation,  (April, 1970).

82.    Eckenfelder, W.  w., Jr. and J. L. Barnard,  "Treatment -
      Cost Relationship for Industrial Wastes", Chemical
      Engineering Progress, Vol. 67, No. 69, (September, 1971).

83.    Eckenfelder, W.  W., Jr. and D. L. Ford, "Economics of
      Wastewater Treatment", Chemical Engineering,
      (August 25, 1969) .

8U.    Edinger, J. E.,  and J. C. Geyer, "Heat Exchange in the
      Environment", Cooling Water Studies for Edison Electric
      Institute  (RP-U9), The Johns Hopkins University  (1965).

85.    Edinger, J. E.,  et al, "The Variation of Water Temper-
      atures Due to Steam Electric Cooling Operations",
      Journal WPCF.pp.  1632-1639, (September, 1968).

86.    "Electric Power Statistics", Federal Power Commission,
      (January, 1972).

87.    "Electric Utility Depreciation Practices", Federal Power
      Commission,  (January, 1970).

88.    "Electric Utilities Industry Research and Development
      Goals Through the Year 2000", Report of the R&D Goal
      Task Force to the Electric Research Council.
                                        i
89.    "Electrical Power Supply  and Demand Forecasts for the
      United States Through 2050", Hittman Associates, Inc.,
      (February, 1972).
                               717

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90.   Electrical Wgrldj Directory of Electric Utilities,
      McGraw-Hill IncT, New York, 31st Edition, (1972-1973).

91.   Eller, 3., et al, "Water Reuse and Recycling in
      Industry", Journal AWWA, pp. 1U9-154, (March, 1970).

92.   Elliott, T. C., "Options for Cooling Large Plants in
      the 70's", Power, (December, 1970).

93.   "Energy Crisis", Consulting Engineer, pp. 97-192,
      (March, 1973).

94.   "Engineering Aspects of Heat Disposal from Power Genera-
      tion", Summer Seminar Program, MIT,  (June 26-30, 1972).

95.   "Engineering for Resolution of the Energy - Environment
      Dilemma",  Committee on Power Plant Siting, National
      Academy of Engineering, Washington, D.C., (1972).

96.   "Environmental Effects of Producing Electric Power:
      Hearings Before the Joint committee on Atomic Energy
      91st Congress, Second Session", Parts 162, Vol. I & II,
      (October and November, 1969 and January and February, 1970)

97.   "Environmental Protection Research Catalog", EPA, Office
      of Research & Monitoring, Research Information Division,
      Washington, D. C., Parts I 6 II, (January, 1972).

98.   "Estimating Costs and Manpower Requirements for Con-
      ventional Wastewater Treatment Facilities", EPA, Water
      Pollution Control Research Series, 17090 DAN 10/71,
      (October, 1971) .

99.   Evans, D. R., and J. C. Wilson, "Capital and Operating
      Costs - Advanced Wastewater Treatment", Journal WPCF,
      pp. 1-13,  (January, 1972) .

100.  "Experimental SO2 Removal System and Waste Disposal Pond
      Widows Creek Steam Plant", Tennessee Valley Authority,
      (January 15, 1973) .

101.  Fair, G. M., et al, "An Assessment of the Effects of
      Treatment and Disposal", Water and Wastewater Engineering*
      Vol. 2,  (November, 1967).

102.  Fairbanks, R. B., et al, "An Assessment of the Effects
      of Electrical Power Generation on Marine Resources in
      the Cape Cod Canal", Mass. Dept. of Natural Resources,
      Division of Marine Fisheries,  (March, 1971).
                               718

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103.  Farrell, J. B. , et al, "Natural Freezing for Dewatering
      of Aluminum Hydroxide Sludges", Journal AWWA, pp.787-791,
      (December, 1970).

IOH.  "Feasibility of Alternative Means of Cooling for Thermal
      Power Plants near Lake Michigan", U. S. Dept. of Interior,
      (September, 1970) .

105.  Feige, N. C., "Titanium Tubing for Surface Condenser
      Heat Exchanger Service", Titanium Metals Corp. of
      America, Bulletin SC-1, (January, 1971). .

106.  Feige, N. C., "Titanium Tubing Proves Value in Estuary
      Application", Power Engineering, (January, 1973).

107.  Ferrel, J. F., "Sludge Incineration", Pollution
      Engineering.  (March, 1973).

108.  Final Environmental Statement, USAEC, Directorate of
      Licensing;

    a)  Arkansas Nuclear One Unit 1
        Arkansas Power & Light Co.,  (February, 1973).

    b)  Arkansas Nuclear One Unit 2
        Arkansas Power & Light Co.,  (September, 1972).

    c)  Davis-Besse Nuclear Power Station
        Toledo Edison Company 6 Cleveland Electric
        Illuminating Company  (March, 1973) .

    d)  Duane Arnold Energy center
        Iowa Electric Light 5 Power Co.
        Central Iowa Power Cooperative
        Corn Belt Power Cooperative,  (March, 1973).

    e)  Enrico Fermi Atomic Power Plant Unit 2
        Detroit Edison Company  (July, 1972).

    f)  Fort Calhoun Station Unit 1
        Omaha Public Power District,  (August, 1972) .

    g)  Indian Point Nuclear Generating Plant Unit No. 2
        Consolidated Edison Co. of New York, Inc., Vol. 1
        (September, 1972) .

    h)  Indian Point Nuclear Generation Plant Unit No. 2
        Consolidated Edison Co. of New York, Inc., Vol. II
        (September, 1972) .
                              719

-------
i)   James A. Fitzpatrick Nuclear Power Plant
    Power Authority of the State of New York,
    (March, 1973) .

j)   Joseph M. Farley Nuclear Plant Units 1 and 2
    Alabama Power Company  (June, 1972).

k)   Kewaunee Nuclear Power Plant
    Wisconsin Public Service Corporation,
    (December, 1972) .

1)   Maine Yankee Atomic Power Station
    Maine Yankee Atomic Power Company (July, 1972).

m)   Oconee Nuclear Station Units 1, 2 and 3
    Duke Power Company  (March, 1972) .

n)   Palisades Nuclear Generating Plant
    Consumers Power Company  (June, 1972) .

o)   Pilgrim Nuclear Power Station
    Boston Edison Company  (May, 1972).

p)   Point Beach Nuclear Plant Units 1 and 2
    Wisconsin Electric Power Co. and
    Wisconsin Michigan Power Company  (May, 1972).

q)   Quad-Cities Nuclear Power Station Units 1 &  2
    Commonwealth Edison company and the
    Iowa-Illinois Gas and Electric Company
    (September,  1972).

r)   Rancho Seco Nuclear Generating Station Unit  1
    Sacramento Municipal Utility District,  (March, 1973)

s)   Salem Nuclear Generating Station Units 1 & 2
    Public Service Gas & Electric Company (April, 1973).

t)   Surry Power Station Unit 1                        *
    Virginia Electric and Power Co.,  (May,  1972).

u)   Surry Power Station Unit 2
    Virginia Electric & Power Co.,  (June, 1972).

v)   The Edwin I. Hatch Nuclear Plant Unit 1 & 2
    Georgia Power Company  (October, 1972).

w)   The Fort St. Vrain Nuclear Generating Station
    Public Service Company of Colorado,  (August, 1972).
                          720

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    x)   Three Mile Island Nuclear Station Units 1 and 2
        Metropolitan Edison Company Pennsylvania Electric
        Company Jersey Central Power and Light Co.,
        (December, 1972).

    y)   Turkey Point Plant
        Florida Power and Light Co., (July, 1972).

    z)   Vermont Yankee Nuclear Power Station
        Vermont Yankee Nuclear Power Corporation, (July, 1972)

   aa)   Virgil C. Summer Nuclear Station Unit 1
        South Carolina Electric 6 Gas Company (January, 1973) .

   bb)   William B. McGuire Nuclear Station Units 1 and 2
        Duke Power Company (October, 1972)

   cc)   Zion Nuclear Power Station Units 1 and 2
        Commonwealth Edison company (December, 1972).

   dd)   Monticellc Nuclear Generating Plant
        Northern States Power Company (November, 1972).

   ee)   Shoreham Nuclear Power Station
        Long Island Lighting Company (September, 1972) .

109.  Final Environmental statement, Watts Bar Nuclear Plant
      Units 1 and 2, Tennessee Valley Authority
      (November 9, 1972) .

110.  Fitch, N. R., "Temperature Surveys of St. Croix River",
      for Allen S. King Generating Plant, Minn.,
      (December 31, 1970) .

111.  Flaherty J. J., "Fiscal Year 1973 Authorization
      Hearings", by the Joint Committee on Atomic Energy
      pp. 1-12,  (February 3, 1972).

112.  Fosberg, T. M., "Reclaiming Cooling Tower Slowdown",
      Industrial Water Engineering, (June/July, 1972).

113.  Frankel, R. J-, "Technologic and Economic Inter-
      relationships Among Gaseous, Liquid and Solid Wastes
      in the Coal-Energy Industry",  Journal WPCF, Vol. *»0,
      No. 5, Part 1, pp. 779-788,  (May, 1968).

      Gambs, G. C., and A. A. Rauth,  "The Energy Crisis",
      Chemical Engineering, pp. 56-68, .(May, 31, 1971).
                              721

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115.  Carton, R. R. , "Biological Effects of Cooling Tower
      Slowdown", for Presentation at 71st National Meeting
      American Institute of Chemical Engineers.
      (February 20-23, 1972).

116.  Carton, R. R., and A. G. Christiansen, "Beneficial
      Uses of waste Heat - An Evaluation", Presented at
      Conference on Beneficial uses of Thermal Discharges,
      sponsored by New York State, Department of Environmental
      Conservation,  (September, 1970) .

117.  Carton, R. G. , and R. D. Harkins,  "Guidelines:
      Biological Surveys at Proposed Heat Dicharge Sites11,
      EPA Water Quality Office, Northwest Region, (April, 1970)

118.  Gartrell, F. E. , and J. C. Barber,  "Environmental
      Protection - TVA Experience", Journal of the Sanitary
           Division, ASCE, pp. 1321-1333, (December, 1970).
119.  "Geothermal Resources in California Potentials and
      Problems",  Assembly Science and Technology Advisory
      Council, A Report to the Assembly General Research
      Committee, California Legislature, (Nay, 1972) .

120.  Geyer, J. C., et al, "Field Sites and Survey Methods
      Report No. 3", Cooling Water Studies for Edison Electric
      Institute (RP-49) , The John Hopkins Univ., (1968).

121.  Gifford, D. C., "Will County Unit 1 Limestone Wet
      Scrubber",  Presented at American institute of Chemical
      Engineers, N. Y. , (November 28, 1972).

122.  "Gilbert Generating Station Units 4, 5, 6, 7, and 8
      Environmental Report", Jersey Central Power and Light.

123.  Goldman, E. , and P.  J. Kelleher,  "Water Reuse in Fossil
      Fueled Power Stations", Presented at Conference on
      Complete Water Reuse sponsored by AIChE and EPA,
      Washington, D. C. ,  (April 23-27, 1973).

124.  Golze, A. R., "Impact of Urban Planning on Electric
      Utilitiies",  (March, 1973).

125.  Hales, William W. , "Control Cooling Water Deposition",
      13th Annual International Water Conference,
      (October 28-30, 1969).

126.  Hallf W. A., "Cooling Tower Plume Abatement", Chemical
      Engineering Progress, Vol. 67, No. 7, (July, 1971).
                              722

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127.  "Handbook for Analytical Quality Control in Water and
      Wastewater Laboratories", Analytical Quality Control
      Laboratory, National Environmental Research Center,
      Cincinnati, Ohio,   (June, 1972).
                        •\
128.  Hansen, E. P., and R. E. Cates,  "The Parallel Path
      Wet-Dry Cooling Tower", The Marley Company,  (1972).

129.  Hansen, R. G., C. R. Knoll, and B. W. Mar, "Municipal
      water Systems - A Solution for Thermal Power Plant
      Cooling?", Journal AWWA, pp. 174-181, (March, 1973).

130.  Hansen, S. P., G. L. Culp, and J. R Stukenberg,
      "Practical Application of Idealized Sedimentation
      Theory in Wastewater Treatment", Journal Water Pollution
      Control Federation. Vol. 41, No. 8, pp. 1421-1444,  (1969)

131.  Harris, P. J., "A Case for Air-Cooling in Electric
      Power Generation", Gas & Oil Power, pp. 16-18,
      (January, 1969) .

132.  Hauser, L. G., et al, "An Advanced Optimization
      Technique for Turbine Condenser, Cooling System
      Combinations", American Power Conference, (1971).

133.  Hauser, L. G., and K. A. Oleson,  "Comparison of
      Evaporative Losses in Various Condenser Cooling
      Water Systems", American Power Conference,  (April
      21-23, 1970).

134.  Hauser, L. G., "Cooling Water Requirements for the
      Growing Thermal Generation Additions of the  Electric
      Utility Industry", American Power conference,
      (April 22-24, 1969) .

135.  Hauser, L. G., "Cooling Water Sources for Power
      Generation", Proceedings of the American Society
      of Civil Engineers, Journal of the Power Division,
      (January, 1971) .

136.  Hauser, L. G., "Evaluate Your Cost of Cooling Steam
      Turbines", Electric Light and Power,  (January, 1971).

137.  Hill, R. D., "Mine Drainage Treatment, State of the Art
      and Research Needs", U. S, Department of the Interior,
      Federal Water Pollution Control Administration,
      (December, 1968).

138.  Hirayama, K., and R. Hirano, "Influences of  High
      Temperature and Residual Chlorine on Marine  Phyto-
      plarikton". Marine Biology. Vol. 7, No. 3, pp. 205-213,
      (1970) .
                                723

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139.  Hollinden, G. A., and N. Kaplan,  "Status of Application
      of Lime-Limestone Wet Scrubbing Processes to Power Plants",
      Prepared for presentation at American Institute of
      Chemical Engineers, 65th Annual Meeting, N. Y.,
      (November 26-30, 1972).

140.  Holmberg, J. D. and O. L. Kinney, "Drift Technology
      for cooling Towers", The Marley Co.,  (1973).

141.  Horlacher, W. R. , et al, "Four SO2, Removal Systems",
      Chemical Engineering Progress, Vol. 68, No. 8,
      pp. 43-50,  (1972).


142.  "Industrial Waste Guide on Thermal Pollution", FWPCA,
      Northwest Region, Pacific Northwest Water Laboratory,
      (September, 1968) .

143.  "Inorganic Chemicals Industry Profile", EPA, Water
      Pollution Control Research Series, 12020 EJI 07/71,
      (July, 1971).

144.  "Reviewing Environmental Impact Statements: Power Plant
      Cooling Systems, Engineering Aspects", U.S. Environmental
      Protection Agency Report EPA-660/2-73-016,  (October, 1973).

145.  Jaske, R. T. and W. A. Reardon,  "A Nuclear Future in
      Water Resources Management:  A Proposal", Nuclear News,
      Vol. 15, No. 7,  (July, 1972).

146.  Jaske, R. T., "Heat as a Pollutant." Presented
      at Fall Water Quality Control Seminar, pp. 61-81,
      (November 11, 1964).

147.  Jaske, R. T., et al, "Heat Rejection Requirements of the
      United States", Chemical Engineering Progress, Vol. 66,
      No. 11, pp. 17-22,  (November,"l970) .

148.  Jaske, R. T., "Is there a Future for Once-Through Cooling
      in the Utility Industry?", Power Engineering,
      (December 1, 1971).

149.  Jaske, R. T., et al, "Multiple Purpose Use of Thermal
      Condenser Discharges from Large Nuclear Systems to
      Supplement Inter-Regional Water Supply", Chemical
      Engineering, Vol. 67, No. 107, pp. 26-39,  (1970).
                               724

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150.  Jaske, R. T., et al, "Methods for Evaluating Effects of
      Transient Conditions in Heavily Loaded and Extensively
      Regulated Streams", Chemical Engineering, Vol. 67,
      No. 107, pp. 31-39, (1970).

151.  Jaske, R. T., "Technical and Economic Alternatives in
      Multi-Purpose Development", Presentation at the Annual
      Meeting of the Washington State Reclamation Association,
      (October 22, 1971).

152.  Jaske, R. T., "Thermal Pollution and Its Treatment,
      The Implications of Unrestricted Energy Usage with
      Suggestions for Moderation of the Impact",
      (October 7, 1970) .

153.  Jaske, R. T., "Use of Simulation in the Development of
      Regional Plans for Plant Siting and Thermal Effluent
      Management", The American Society of Mechanical
      Engineers.  (1971).

154.  Jaske, R. T., "Water Resources Problems in Meeting
      The Nation*s Energy Needs", Presentation at Greater
      Portland Chamber of Commerce and the Professional
      Engineers of Oregon, (February 26, 1973).

155.  Jaske, R. T., "Water Reuse in Power Production an
      Overview",  Paper for publication in the Proceedings
      of the National Conference on Complete Water Reuse,
      (April 25,  1973) .

156.  Jenson, L.  D., and D. K. Brady,  "Aquatic Ecosystems
      and Thermal Power Plants",  Proceedings of the ASCE^
      (January, 1971) .

157.  Jimeson, R. M., and C. H. Chilton,  "A Model for
      Determining the Minimum Cost Allocation for Fossil
      Fuels", 2nd National Cost Engineering Congress and 1st
      International Cost Engineering Symposium, Mexico City,
      (October 29-November 1, 1972).

158.  Jimeson, R« M., and G. G. Adkins,  "Factors in Waste
      Heat Disposal Associated with Power Generation",
      Paper No. 6A, Presented at the 68th National Meeting,
      American Institute of Chemical Engineers, Houston,
      Texas,  (February 28-March U, 1971).

159.  Jimeson, R. M.,  "The Demand for Sulfur Control Methods
      on Electric Power Generation", Paper presented at
      American Chemical Society Conference, Division of Fuel
      Chemistry New York, New York,  (August 27-sept. 1, 1972).
                                725

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160.  Jimeson, R. M., and G. G. Adkins,  "Waste Heat Disposal
      in  Power Plants", Chemical Engineering Progress,
      Vol. 67, No. 7, (July, 1971).

161.  Jones, J. W., R. D. Stern, and F. T. Princiotta,
      "Waste Product from Throwaway Flue Gas Cleaning
      Processes - Ecologically Sound Treatment and Disposal",
      Office of Research & Monitoring, Environmental Protection
      Agency,  (January 1973).

162.  Kaup, E., "Design Factors in Reverse Osmosis", Chemical
      Engineering, Vol. 80, No. 8., pp. U6-55, (April 2, 1973).

163.  Kelley, R. B., "Large-Scale Spray Cooling", Industrial
      Water Engineering, pp. 18-20, (August/September, 1971).

164.  Kibbel, W. H., Jr., "Hydrogen Peroxide for Industrial
      Pollution Control", Presented at 27th Annual Purdue
      Industrial Waste Conference, Purdue University
      Lafayette, Indiana, (May, 2-4, 1972).

165.  Kleinberg, B., "Introduction to Metric or Si", Civil
      Engineering-ASCE, pp. 55-57,  (March, 1973).

166.  Kolflat, T. D., "Cooling Towers - State of the Art",
      Department of Interior/Atomic Industrial Forum Seminar,
      (February 13-1U, 1973).

167.  "Kool-Flow Thermal Pollution Control", Richards of
      Rockford, Mfr., Distr., R. Casper Swaney Inc.

168.  Krieger, J. H., "Energy:  "The Squeeze Begins", Chemical
      and Engineering News, pp. 20-37, (November 13, 1972) .

169.  Kumar, J., "Selecting and Installing Synthetic Pond
      Linings", Chemical Engineering, Vol. 80, No. 3,
      pp. 67-70,  (February 5, 1973).

170.  "Lake Norman Hydrothermal Model Study, for Duke Power
      Company", Alden Research Laboratories, (February, 1973) .

171.  LaMantia, C. R., "Emission Control for Small Scale
      Facilities", Proceedings for Control of Sulphur Oxide
      Emissions, AIChE Advanced Seminar,  (1973) .

172.  LaQue, F. L., and M. A. Cordovi, "Experiences with
      Stainless Steel Surface Condensers in the U.S.A.".
      Current Engineering Practice, Bombay India, Vol. 10,
      Nos. 11 and 12, (May, June, 1968) .
                                726

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173.  Leung, Paul, "Cost Separation of Steam and Electricity
      for a Dual-Purpose Power Station",  Combustion, Vol. 44,
      No. 8, (February, 1973) .
174.  Leung, P., and R. £. Moore,  "Thermal Cycle Arrangements
      for Power Plants Employing Dry Cooling Towers", ASME
      Trans. Jour, of Enq. for Power. Vol. 93, No. 2,
      (April, 1971) .
175.  Li, K. W., "Combined Cooling Systems for Power Plants",
      Prepared for Northern States Power Co., Minneapolis,
      Minnesota.
176.  Lof, G., and J. C. Ward,  "Economics of Thermal
      Pollution Control", Journal of WPCF. pp. 2102-2116,
      (December, 1970).
177.  Long, N. A., "Recent Operating Experience with Stainless
      Steel Condenser Tubes",  American Power Conference,
      Chicago, Illinois,  (1966).
178.  Long, N. A., "Service Conditions Influencing the Pitting
      Corrosion of Stainless Steel Steam Surface Condenser
      Tubes", The 4th Steel Congress, Luxembourg, (July, 1968).
179.  Loucks, C. M., "Boosting Capacities with Chemicals",
      Chemical Engineering, pp. 79-84,  (February 26, 1973).
180.  Lunenfeld, H., "Electric Power 6 Water Pollution
      Control".
181.  Lusby, W. S., and E. V.  Somers,  "Power Plant Effluent -
      Thermal Pollution or Energy at a Bargain Price?",
      Mechanical Engineering,  pp. 12-15,  (June, 1972).
182.  McCabe, W. L., and J. C. Smith,  Unit Operations of
      Chemical Engineering, McGraw-Hill Book Company Inc.,
      (1956) .
183.  McKee, J. E., and H. W.  Wolf,  "Water Quality Criteria,
      State of California", State water Resources Control
      Board, Publication No. 3A,  (April, 1971).
184.  McNeil, W. J., "Beneficial Uses of Heated Sea Water in
      Agriculture", .Presented to conference on Beneficial Uses
      of Waste Heat, Cak Ridge, Tennessee,  (April 20-21, 1970).
185.  McNeil, W., "Selecting and Sizing Cooling Towers",
      Pollution Engineering, pp. 31-32, (July/August, 1971).
                               727

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186.  "Typical LWR Nuclear Plant Project Schedule",
      Publication of NUS Corporation, (1973).

187.  Kolflat, T. , "Conventional Steam Cycle Unit Meets Need",
      Proceedings of the American Power Conference, Volume 35,
      (1973).

188.  "Meeting the Electrical Energy, Requirements for California",
      Assembly Science & Technology Advisory Council,. A report
      to the Assembly General Research Committee, California
      Legislature,  (June, 1971).

189.  "Methods for Chemical Analysis of Water & Wastes",
      Water, EPA, Series #16020 07/71,  (July, 1971).

190.  "Metric Practice Guide", (A Guide to the Use of Si - The
      International System of Units), American Society for
      Testing and Materials, Philadelphia, Pennsylvania.

191.  "Missouri River Temperature Survey Near United Power
      Association, Stanton, North Dakota Plant" for United
      Power Association, Minn., (January, 1973).

192.  Moore, F. K., and Y. Jaluria,  "Thermal Effects of Power
      Plants on Lakes", Transactions of the ASME Journal of
      Heat Transfer, pp. 163-168, (May, 1972).

193.  Moores, C. W., "Wastewater Biotreatment:  What It Can
      and Cannot Do", Chemical Engineering, Vol. 70,, No. 29,
      pp. 63-66,  (December 25, 1972).

19<*.  Morgenweck, F. E., "Performance Testing of Large
      Natural Draft Cooling Towers", ASME Paper No. 68-WA/
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                             728

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198.  Nelson, B. D., "The Cherne Fixed Thermal Rotor System
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           •                                             t
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                               729

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212.   Peterson, D. E.t and P. M. Schrotke, "Thermal Effects
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                              730

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225.  Rabb, A., "For Steam Turbine Drives... Are Dry Cooling
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                               731

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                          •
246.   Ryan, P. J., and D. R. F. Harleman, An Analytical
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247.   Ryan, W. F., "Cost of Power".
                             732

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248.  Schieber, J. R., "Control of Cooling Water Treatment -
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250.  Schoenwetter, H. D., "Indian Point Nuclear Station
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                              733

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261.   Shirazi, M. A., "Thermoelectric Generators Powered by
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                               734

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272.  Sonnichsen,  J. C., Jr. et al, "Cooling Ponds - A Survey
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                            735

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286.   "Summary of Recent Technical Information Concerning
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                             738

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                              739

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                               740

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363.   Wistrom, G. R., and J. C. Ovard, "Cooling Tower Drift -
      Its Measurement, Control, and Environmental Effects",
      Paper presented at cooling Tower Institute Houston
      Meeting,  (January, 1973) .

364.   Smith, W. s., et al, "Atmospheric Emissions from
      Coal Combustion - An Inventory Guide", U. S. Dept.
      of HEW., Publication No. 999 AP-24, (April, 1966).

365.   "Kool-Flow, Water Cooling System for Controlling
      Thermal Pollution", Richards of Rockford, Inc., 111.

366.   "An Evaluation of the Powered Spray Module for Salt
      Water Service for Turkey Point", Southern Nuclear
      Engineering, Inc., (May, 1970).

367.   Boyack, B. E., and D. W. Kearney, "Plume Behavior
      and Potential Environmental Effects of Large Dry
      Cooling Towers", Final Report - Gulf General Atomic,
      (February, 1973).
                              741

-------
368.  Jedlicka, C. L., "Nomographs for Thermal Pollution
      Control Systems", 0. S. Environmental Protection Agency,
      Report EPA-660/2-73-004, (September, 1973).

369.  Mulbarger, M. C., "Sludges and Brines Handling,
      Conditioning, Treatment and Disposal", Ultimate
      Disposal Research Activities, Division of Research,
      FWPCA Cincinnati Water Research Laboratory, (1968).

370.  "Considerations Affecting Steam Power Plant Site Slection",
      A report sponsored by The Energy Policy Staff, Office of
      Science and Technology, (1968).

371.  Curry, Nolan A., "Philosophy and Methodology of Metallic
      Waste Treatment", Paper Presented at the 27th Industrial
      Waste Conference, Purdue University, (May 2-U, 1972).

372.  Jones, D. B. and W. E. Wiehle, "Recovery of Chromate
      from Cooling Water System Slowdown Water", Goodyear
      Atomic Corp. for U.S. Atomic Energy Commission,
      (December 1, 1966).

373.  Richardson, E. W., et al, "Waste Chromate Recovery
      by Ion Exchange", Union Carbide Corp. for U.S. Atomic
      Energy Commission,  (April 3, 1968) .

374.  "Process Design Manual for Phosphorus Removal", Black and
      Veatch for U.S. Environmental Protection Agency
      (October, 1971) .

375.  "Development Document for Proposed Effluent
      Limitations Guidelines and New Source
      Performance Standards for the Basic
      Fertilizer Chemicals Segment of the Fertilizer
      Manufacturing Point Source Category"
      U.S. Environmental Protection Agency, (November,
      1973).

376.  Nelson, Guy R., "Predicting and Controlling Residual
      Chlorine in Cooling Tower Slowdown", U.S. Environmental
      Protection Agency,  (July, 1973).

377.  "Current Practices - Factors Influencing Need for Chemical
      Cleaning Boilers", ASME Research Committee Task Force
      on Boiler Feedwater Studies Presented to American Power
      Conference,  (May, 1973).
                              742

-------
378.  Goldman, E., and P. J. Kelleher, "Water Reuse in Fossil-
      Fueled Power Stations", Paper presented at the National
      Conference on Complete Watereuse sponsored by the
      American Institute of Chemical Engineers and the
      U.S. Environmental Protection Agency, (April, 1973).

379.  "Development Document for Proposed Effluent Limitations
      Guidelines and New Source Standards for the Copper,
      Nickel, Chromium, and Zinc Segment of the Electroplating
      Point Source Category", U.S. Environmental Protection
      Agency, (August, 1973).

380.  "Processes, Procedures and Methods to Control Pollution
      from Mining Activities", U.S. Environmental Protection
      Agency, (October, 1973).

381.  "Environmental Report, Beaver Valley Power Station
      Unit 1 - Operating License Stage", Duquesne Light Company,
      (September, 1971).

382.  "Processes, Procedures, and Methods to Control Pollution
      Resulting from All Construction Activity", U.S. Environ-
      mental Protection Agency, (October, 1973).

383.  Mercer, B. W., and R. T. Jaske, "Methods for Reducing
      Demineraliser Waste Discharges from Thermo-Electric
      Power Plants" Paper presented at National Conference
      on complete Watereuse, sponsored by the American
      Institute of Chemical Engineers and the U.S.
      Environmental Protection Agency,  (April, 1973).

38U.  Burns, V. T., Jr., "Reverse Osmosis Water Treatment at
      Harrison Power Station", Paper presented at American
      Power Conference,  (May, 1973).

385.  Roffman, A., et al, "The State of the Art of Saltwater
      Cooling Towers for Steam Electric Generating Plants"
      Prepared for the U.S. Atomic Energy Commission,  (February,
      1973).

386.  "Review of Wastewater Control Systems", Tennessee Valley
      Authority  (separate documents for each TVA powerplant).

387.  Hoppe, Theodore C., and Riley, D. Woodson,
      "Chemical and Mechanical Cleaning of Condenser Systems
      for Electric Generation", Black and veatch Paper presented
      at Joint U.S./U.S.S.R. Meeting on Heat Rejection Systems,
  *   (June, 197U) .
                                743

-------
388.   "Comments on EPA's Proposed Section 304 Guidelines
      and Section 306 Standards of Performance for Steam
      Electric Powerplants", Utility Water Act Group,
      (June, 1974).

389.   Boies, David B., James E. Levin and Bernard Baratz,
      "Technical and Economic Evaluations of Cooling Systems
      Slowdown Control Techniques", U.S. Environmental
      Protection Agency, EPA-660/2-73-026, (November, 1973).

390.   Roffman, A., et al, "The State of the Art of Saltwater
      Cooling Towers for Steam Electric Generating Plants",
      U.S. Atomic Energy Commission, WASH-1244, (February, 1973)

391.   Creel, G. C., and D. T. Snyder, "Major Design Criteria:
      Wet-Dry Mechanical Draft Cooling Towers: Brandon
      Shores Powerplant Units Nos. 1 and 2H, Paper presented
      at the U.S./U.S.S.R. Meeting on Thermal Powerplant Heat
      Rejection Systems,  (June, 1974).

392.   "Review of Overall Adequancy and Reliability of the
      North American Bulk Power Systems", National
      Electric Reliability Council,  (September, 1972).

393.   "A Report by MARCA to the Federal Power Commission
      Pursuant to FPC Docket R-362, Appendix A", Mid-
      Continent Area Reliability Coordination Agreement
      (April, 1973).

394.   "Impact of Increased Thermal Cooling Requirements
      on Reliability of the MARCA (Mid-Continent Area
      Reliability Coordinating Agreement) Region",
      Document submitted to EPA by MAPP coordination
      Center, (July, 1973).

395.   Buchmeir, F. A., Jr., "Scheduling Outages of Large
      Generating Units", Mechanical Engineering,  (July, 1974).

396.   "The 1964 National Power Survey", Parts I and II,
      Federal Power Commission.

397.   "Progress Reports of the Regional Organization to the
      Executive Board of National Electric Reliability
      Council", (April, 1973).

398.   "1967 Domestic Refinery Effluent Profile",
      American Petroleum Institute,  (September, 1968).

399.   "Development Document for Proposed Effluent
      Limitations Guidelines and New Source Performance
      Standards for the Petroleum Refining Point Source
      Category", Supplement B, U. S. Environmental
      Protection Agency,  (December,  1973).
                             744

-------
400.  "Balcke Cooling Towers for Power Stations",
      Machinenbau - Aktiengesellschaft
      Balke, Bochum.

401.  "Balcke Natural Draught Cooling Towers11,
      Machinenbau - Aktiengesellschaft Balke, Bochum.

402.  "Reference List KRL 39", Balke Durr
      Aktienges elIschaft.

403.  Industriespigel. No. 12 (1972).

404.  E.P.A. Project Officer's Notes on visit to
      the Lichterfelde Plant, (May, 1974).

405.  Rainwater, Frank H., " Environmental Consequences
      Of Spray Cooling Systems", Paper presented at the
      Seminar on Environmental Aspects of the Cooling
      Systems of Thermal Power Stations, Economic Commission
      For Europe, Committee on Electric Power, (May, 1974).

406.  "Fog Production Characteristics, Powered Spray Module
      Evaporative Water Cooling System", Ceramic Cooling
      Tower company Proposal PSM - 100 - RF1, (April, June,
      1972).

407.  "Final Test Report of the Cherne Fixed Thermal
      Rotor Demonstration Conducted at the Northern
      States Power Company Allen S. King Plant",
      Cherne Industrial, Inc.,  (September, 1973).

408.  "Interim Report on Meteorological Aspects of Operating
      the Man-Made Cooling Lake and Sprays at Dresden Nuclear
      Power Station", Murray and Trettel, Inc.,  (August, 1973)

409.  "PSM Draft Testing", Ceramic Cooling Tower Company
      CT-142-1 Rev. A,  (April, 1973).

410.  "Kool-Flow Water Cooling Systems, Specific Engineering
      Data", Richards of Rockford, Inc.

411.  "PSM Sound Testing" Ceramic Cooling Tower Company
      CT-142-1 Rev. 1,  (April, 1973).

412.  Hoffman, David P., "Spray cooling for Power Plants",
      Proceeding of the American Power Conference, Volume
      35, 702,  (1973) .
                             745

-------
413.  "Pollution Control Technology, for Fossil Fuel-Fired
      Stations", Draft Report by Radian Corporation for U.S.
      Environmental Protection Agengy, Contract No. 68-
      02-2008,  (April, 1974) .

414.  Carson, James E., "The Atmospheric Consequences of
      Thermal Discharges from Power Generating Stations11,
      Annual Report of the Radiological Physics Division,
      Argonne National Laboratory,  (1972).

415.  Hewson, E. Wendell, "Moisture Pollution of the.
      Atmosphere by Cooling Towers and Cooling Ponds",
      Bulletin of the American Meteological Society,
      Volume 51, No. 1,  (1970).

416.  Cox, R. A., " Prediction of Fog Formulation Due to
      Warm Water Lagoon Proposed for Power Station Cooling",
      Atmospheric Environment, Volume 7,  (1973).

417.  "Solid Waste Disposal", Radian Corporation, Draft Report
      submitted to EPA under Contract No. 68-02-2008,
      (March 8, 1974) .

418.  Baker, Robert, and Sid Cole,  "Residual Chlorine:
      Something New to Worry About", Industrial Water
      Engineering. (March/April, 1974).

419.  Brungs, W. A., "Effects of Residual Chlorine on
      Aquatic Life: Literature Review", unpublished.

420.  Baker, R. J., "Practical Aspects of Disinfection",
      Proc. of Water Pollution Control Association of
      Pa., University Park, Pa.,  (August, 1972).

421.  Baker, R. J., "Onstream Analysis of Free Chlorine",
      Industrial Hater .Engineering, (January, 1969).

422.  Knight, R. G. , and R. J. Baker,  "Evaluation of
      Factors Affecting Chlorination of Condenser Cooling
      Water", Proc. of 29th International Water Conference
      Pittsburgh, Pa., (November, 1968).

423.  Proceedings of the National Specialty Conference
      On Disinfection, University of Mass., Amherst, Mass.,
      "(July, 1970).

 24.  Griffin, A. E., and R. J. Baker, "The Breakpoint
      Process for Free Residual Chlorination", Jour.
      of the New England Water Works Association,  (September,
      1959) .
                                746

-------
425.  Draley J. E., "Chlorination Experiments at the John
      E. Amos Plant of the Appalachian Power Company
      April 9-10, 1973", Argonne National Laboratory
      Report No. ANL/ES-23, (June, 1973).

426.  Kothandaraman, V., and S. D. Lin,  "Air Agitation
      of Treatment Plant Effluents11, Public Works,
      (August, 1973).

427.  Burns and Roe, Inc. letter to EPA Project Officer,
      (September, 1974).

428.  Cole, S. A., "Control of Bryozoa and Shellfish in
      Circulating Water Systems", Engineering and Operation
      Section, Conference Southeastern Electric Exchange,
      (April, 1964).

429.  Comeaux, Roy V., and C.  P. Tyler, "ORP Control of
      Cooling Tower Chlorination", Proc.  of 23rd International
      Water Conferencef Pittsburgh, Pa.,  (1962).

430.  White, George C., "Chlorination and Dechlorination:
      A Scientific and Practical Approach", Jour^ AWWA. (May,
      1956).

431.  Collins, Harvey F., and David C. Deaner, "Sewage
      Chlorination Versus Toxicity - A Dilemma?",
      California State Department of Public Health,
      unpublished.

432.  Draft Environmental Statement for the Trojan Nuclear
      Plant, USAEC, Directorate of Licensing , Portland
      General Electric Company, (January, 1973).

433.  Applebaum, S. B., Demineralization by Ion Exchange,  ,
      McGraw-Hill, New York,  (1968).

434.  Powell, S. T., Water Temperature for Industry.
      McGraw-Hill, New York,  (1954).

435.  Kelly, B. J., " Removing Chromates", Industrial Water
      Engineering.  (September, 1968).

436.  Glover, G. E., " Cooling Tower Slowdown Treatment
      Cost", Industrial Process Design for Water
      Pollution Control. Volume 2, pages 74-81, Proceedings
      of the Workshop Organized and Held under the Auspices
      of the AICHE  Water Committee, Houston, Texas,
      (April 24-25, 1969).
                               747

-------
437.  Fosberg, T. M., "Reclaiming Cooling Tower Slowdown",
      Industrial Water Engineering, pp. 35-37, (June/
      July, 1972) .

438.  Yee, "Phosphate Adsorption by Activated Alumina",
      Amgrican Water Works Association, (February, 1966).

439.  Bischoff, A. E., and P. Goldstien, "Chemical Treatment
      for Cooling Tower and Related Systems", Materials
      Protection and Performance, Volume 10, No.  12, pp.
      26-28, (December, 1971).

440.  Christiansen, P. B., and D. R. Colman, "Reduction of
      Blowdown from Powerplant Cooling Tower Systems",
      AICHE Seminar on cooling Towers, Houston, Texas,
      (1968) .

441.  "Consumptive Water Use Implications of the
      Proposed EPA Effluent Guidelines for Steam-
      Electric Power Generation", Prepared for Utility
      Water Act Group and Edison Electric Institute
      Water Consumption Task Group by Espey, Houston and
      Associates, Inc.,  (May, 1974).

442.  "Steam-Electric Plant Air and Water Quality Control
      Data for the Year Ended December 31, 1970 Based on
      FPC Form No. 67, Summary Report", Federal Power
      Commission,  (July, 1973).


443.  Parker, Frank L. , and Peter A. Krenkel, "Thermal
      Pollution: Status of the Art", Vanderbilt University,
      (December, 1969).

444.  "Non-Thermal Discharges", Draft document submitted to
      Effluent Standards and Water Quality Information
      Advisory Committee by Edison Electric Institute,
      (May, 1973) .

445.  Awerbuch, L., and A. N. Rogers, "Advanced Desalting Program:
      Desalination of Cooling Tower Blowdown", Bechtel Corporation,
      (January, 1974).            4

446.  "Development of Decision Rules for Granting Variances to
      Thermal Power Plants on a Specific-Site Basis", Energy,
      Resources Co., report for E.P.A., Final Report,  (October,
      1974) .
                               748

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447.  "Study on the Cost of Backfitting From Open to Closed
      Cycle Cooling", Sargent and Lundy Engineers, Report SL-3111
      prepared for Utility Water Act Group, (June, 1974).

448.  Letter from Sargent and Lundy Engineers to National
      Economic Research Associates, Inc.,  (October, 1974).

449.  Telephone conference with R. Meyer, Pneutronics,
      (September, 1974).

U50.  NUS Corporation, "Report on Proposed Chemical Effluent
      Limitations Guidelines and Standards for the Steam
      Electric Power Generating Point Source Categories",
      Prepared for the Edison Electric Institute Ad Hoc
      Water Quality Group and the Utility Water Act Group,
      (June, 1974).

451.  Reisman, J. I., and J. C. Ovard, "Cooling Towers and the
      Environment - An Overview", Proceedings of the -American
      Power Conference, Volume 35, 713,  (1973).

452.  "Brine Concentration Application to Steam Electric
      Utility waste Streams", Comments submitted to EPA
      by Resources Conservation Co.,  (June, 1974).

453.  "Andco Chromate Removal System", Brochure Andco
      Environmental Processes, Inc., Buffalo, N.Y.

454.  White, James E., "Tube Settling of Power Plant
      Ash Sluice Water", Public Works, 71-73,
      (November, 1974).

455.  Monroe, R. C., "Fans Key to Optimum Cooling-Tower
      Design", The Oil and Gas Journal,  52-56,
      (May 27, 1964).

456.  Remeysen, J., J. VanDievort and G. Oplatka,
      "Economic Comparison of Different Cooling
      Systems According to Environmental Constraints",
      Report transmitted to the Economic Commission
      for Europe, Committee on Electric  Power,
      Seminar on Environmental Aspects of the Cooling
      Systems of Thermal Power Stations, (May, 1974) .

457.  Leimkuehler, K. C., "How NASA Removes Hexavalent
      Chrome from Cooling Tower Slowdown", Stanley
      Consultants,  (no date given).
                               749

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458.  "Development Document for Effluent Limitations
      Guidelines and New Source Performance Standards
      for the Cement Manufacturing Point Source
      Category", U.S. Environmental Protection Agency,
      (January, 1974) .

459.  "Dunkirk Steam Station Waste Water Control
      Facility", Report by Acres American Incorporated
      for the Niagara Mohawk Power Corporation,
      Project P2722.00, (December, 1972).

460.  "Development Document for Effluent Limitations Guidelines
      and Hew Source Performance Standards for the Phosphorus
      Derived Chemicals Segment of the Phosphate Manufacturing
      Point Source Category", U. S. Environmental Protection
      Agency,  (January, 1974).

461.  Nelson, Guy R., "Staff Report on Water Requirements
      for Power Plants with Wet Cooling Towers", E.P.A.
      Pacific Northwest Environmental Research Laboratory,
      (March, 1974) .

462.  Quirk, Lawler and Matusky Engineers, "Responses
      and Comments of Quirk, Lawler and Matusky Engineers
      to the U.S. Environmental Protection Agency,
      Relating to 40 CFR Part 423", (June 26, 1974).

463.  The Utility Water Act Group/Thermal Engineering
      Technical Advisory Group, "A Critique of the
      Burns and Roe Report and Development Document
      for Proposed Effluent Limitations Guidelines",
      (June 26, 1974) .

464.  "Preliminary Study - Effluent Control
      Systems Moss Landing Power Plant", Prepared by
      Kaiser Engineers for Pacific Gas and Electric
      Company,  (June, 1974).

465.  "Preliminary Study - Effluent Control Systems
      Pittsburg Power Plant", Prepared by Kaiser
      Engineers for Pacific Gas and Electric
      Company,  (June, 1974).

466.  Blecker, Herbert G., and Thomas M. Nichols,
      "Capital and Operating Costs of Pollution
      Control Equipment Modules, Volume II, Data
      Manual", U. S. Environmental Protection
      Agency, Report No. EPA-R5-73-023b,  (July, 1973).
                               750

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467.  Rosen, Richard H., "Discharge of Metallic Pollutants
      from Coal-Fired Power Plants11, Energy Resources Company
      memo to Fred Leutner, U.S. Environmental Protection
      Agency, (September, 1974).

468.  Cain, Carl, Jr., Joseph Greco and D. L. Paul, "The
      Chemical Cleaning Program for Browns Ferry Nuclear
      Plant", American Power Conference (May, 1973).

469.  "Current Practices-Factors Influencing Need for Chemical
      Cleaning of Boilers", ASME Research Committee Task Force
      Report on Boiler Feedwater Studies, American Power
      Conference, (May, 1973).

470.  "Factors Affecting Ability to Retrofit Flue
      .Gas Desulfurization Systems", Radian
      Corporation, EPA 450/3-74-015, (December, 1973).

471.  "Evaluation of Lime/Limestone Sludge
      Disposal Options", Radian Corporation,
      EPA 450/3-74-016,  (November, 1973).

472.  "Evaluation of the Controllability of
      Power Plants Having a Significant
      Impact on Air Quality Standards",
      M.W. Kellogg Co., EPA 450/3-74-002,
      (February, 1974).

473.  "Report on the Status of Lime/Limestone
      Wet Scrubber System", Radian Corporation,
      EPA 450/3-74-014,  (January, 1974).
                             751

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                        SECTION XIV

                          GLOSSARY
Absolute Pressure

The total force per unit area measured above absolute vacuum
as a reference.  Standard atmospheric ' pressure  is  101,326
N/sq  m  (14.696  psi)  above absolute vacuum (zero pressure
absolute) .

Absolute Temperature

The temperature measured from a zero at which all  molecular
activity  ceases.   The  volume  of an ideal gas is directly
proportional to its absolute temperature.  It is measured in
°K  (°R) corresponding to °C + 273  (°F + U59) .
A substance which dissolves in water with the  formation  of
hydrogen  ion.  A substance containing hydrogen which may be
displaced by metals to form salts.

Acidity

The quantitative capacity of aqueous solutions to react with
hydroxyl ions  (OH-) .  The  condition  of  a  water  solution
having a pH of less than 7.

Aqglomer at ion

The  coalescence  of  dispersed suspended matter into larger
floes or particles which settle more rapidly.

Alkali

A soluble substance which when  dissolved  in  water  yields
hydroxyl ions.  Alkalies combine with acids to yield neutral
salts.

Alkaline

The  condition of a water solution having a pH concentration
greater than 7.0, and having the properties of a base.
                             753

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Alkalinity

The capacity to neutralize acids,  a  property  imparted  to
water  by  its  content  of  carbonates,  bicarbonates,  and
hydroxides.  It is expressed  in  milligrams  per  liter  of
equivalent CaCO.3.

Anion

The  charged  particle in a solution of an electrolyte which
carries a negative charge.

Anthracite

A hard natural coal of high  luster  which  contains  little
volatile matter.

Approach Temperature

The  difference between the exit temperature of water from a
cooling tower, and the wet bulb temperature of the air.

Ash

The solid residue following combustion of a fuel.

Ash sluice

The transport of solid  residue  ash  by  water  flow  in  a
conduit.

Backwash

Operation  of  a  granular fixed bed in reverse flow to wash
out sediment and reclassify the granular media.

Bag Filters

A fabric type filter in which dust laden gas is made to pass
through woven fabric to remove the particulate matter.

Base

A compound which dissolves in water to yield  hydroxyl  ions
(OH-) .

Base-load Unit

An  electric generating facility operating continuously at a
constant output with little hourly or daily fluctuation.
                             754

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Biocide

An agent used to control biological growth.

Bituminous

A coal of intermediate hardness containing between 50 and 92
percent carbon.

Slowdown

A portion of water in a closed system  which  is  wasted  in
order to prevent a build-up of dissolved solids.

BOD

Biochemical  oxygen demand.  The quantity of oxygen required
for the biochemical oxidation of organic matter in a  sewage
or  industrial  waste  in  a  specific  time, at a specified
temperature and under specified conditions.  A standard test
to assess wastewater pollution level.

Boiler

A device in which a liquid is converted into its vapor state
by the action of heat.  In  the  steam  electric  generating
industry the equipment which converts water into steam.

Boiler Feedwater

The water supplied to a boiler to be converted into steam.

Boiler Fireside

The  surface of boiler heat exchange elements exposed to the
hot combustion products.

Boiler Scale

An incrustation of salts deposited on  the  waterside  of  a
boiler as a result of the evaporation of water.

Boiler Tubes

Tubes  contained  in  a  boiler  through  which water passes
during its conversion into steam.

Bottom Ash

The solid residue left from the combustion of a fuel,  which
falls to the bottom of the combustion chamber.
                               755

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Water  having  a  dissolved  solids  content between that of
fresh water and that of sea water, generally  from  1000  to
10,000 mg per liter.

Brine

Water saturated with a salt.

Bus Bar

A  conductor  forming  a common junction between two or more
electrical circuits.  A term commonly used in  the  electric
utility  industry  to  refer  to  electric  power  leaving a
station boundary.  Bus bar costs would refer to the cost per
unit of electrical energy leaving the station.

Capacity Factor

The ratio of energy actually produced to  that  which  would
have  been  produced  in  the  same period had the unit been
operated continuously at rated capacity.

Carbonate Hardness

Hardness of water caused by the presence of  carbonates  and
bicarbonates of calcium and magnesium.

Cation

The  charged  particles  in solution of an electrolyte which
are positively charged.

Chemical Oxygen Demand fCOD)

A specific test to measure the amount of oxygen required for
the complete oxidation of all organic and  inorganic  matter
in  a  water  sample  which is susceptible to oxidation by a
strong chemical oxidant.

Circulating Water Pumps

Pumps which deliver cooling water to  the  condensers  of  a
powerplant.
                             756

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Circulating Water System

A  system which conveys cooling water from its source to the
main  condensers  and  then  to  the  point  of   discharge.
Synonymous with cooling water system.

Clarification

A  process  for the removal of suspended matter from a water
solution.

Clarifier

A basin in which water flows at  a  low  velocity  to  allow
settling of suspended matter.

Closed Circulating Water System

A  system  which  passes  water through the condensers, then
through an artificial cooling device,  and  keeps  recycling
it.

Coal Pile Drainage

Runoff from the coal pile as a result of rainfall.

Condensate Polisher

An ion exchanger used to adsorb minute quantities of cations
and  anions  present  in condensate as a result of corrosion
and erosion of metallic surfaces.

Condenser

A device for converting a vapor into its liquid phase.

C on s tr uc ti on

Any placement, assembly or  installation  of  facilities  or
equipment  (including  contractual  obligations  to purchase
such facilities or equipment)  at  the  premises  where  the
equipment  will  be  used, including preparation work at the
premises.


Convection

The heat transfer mechanism arising from  the  motion  of  a
fluid.
                             757

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Cooling Canal

A  canal in which warm water enters at one end, is cooled by
contact with air, and is discharged at the other end.

Cooling Tower

A configured heat exchange  device  which  transfers  reject
heat from circulating water to the atmosphere.

Cooling Tower Basin

A  basin  located  at  the  bottom  of  a  cooling tower for
collecting the falling water.


Cooling Water System

See Circulating Water System

Corrosion Inhibitor

A chemical agent which slows down or prohibits  a  corrosion
reaction.

Counterflow

A  process  in  which  two  media  flow  through a system in
opposite directions.

Critical Point

The  temperature  and  pressure  conditions  at  which   the
saturated-liquid  and  saturated-vapor states of a fluid are
identical.  For water-steam these conditions are 3208.2 psia
and 705.U7°F.

Cycling Plant

A generating facility which operates between peak  load  and
base load conditions.

Cyclone Furnace

A  water-cooled  horizontal cylinder in which fuel is fired,
heat is released at extremely high rates, and combustion  is
completed.   The  hot  gases  are then ejected into the main
furnace.  The fuel and  combustion  air  enter  tangentially
imparting  a  whirling motion to the burning fuel, hence the
name Cyclone Furnace.  Molten slag  forms  on  the  cylinder
walls, and flows off for removal.
                              758

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Deaera-tion
A  process  by  which  dissolved air and oxygen are stripped
from water either by physical or chemical methods.
Deaerator
A device for the removal of oxygen, carbon dioxide and other
gases from water.
Degasification
The removal of a gas from a liquid.
Deionizer
A process for treating  water  by  removal  of  cations  and
anions.
Demine rali zer
See Deionizer
Demister
A  device  for trapping liquid entrainment from gas or vapor
streams.
Dewater
To remove a portion of the water from a sludge or a slurry.
Dew Point
The temperature of a gas-vapor mixture at  which  the  vapor
condenses when it is cooled at constant humidity.
Diesel
An  internal  combustion  engine in which the temperature at
the end of  the  compression  is  such  that  combustion  is
initiated without external ignition.
Discharge
To release or vent.
                               759

-------
Discharge Pipe or Conduit
A section of pipe or conduit from the condenser discharge to
the  point  of  discharge  into  receiving waters or cooling
device.
Drift
Entrained water carried from a cooling device by the exhaust
air.
Dry Bottom Furnace
Refers to a furnace in which the ash is collected as  a  dry
solid  in  hoppers at the bottom of the furnace, and removed
from the furnace in this state.
Dry Tower
A cooling tower in which the fluid to be cooled flows within
a closed system.  This type of tower usually uses finned  or
extended surfaces.
Dry. Hell
A  dry  compartment  of a pump structure at or below pumping
level, where pumps are located.
Economizer
A heat exchanger which uses the heat of combustion gases  to
raise  the boiler feedwater temperature before the feedwater
enters the boiler.
Electrostatic Precipj.tator
A device for removing particles from a stream of  gas  based
on  the  principle  that these particles carry electrostatic
charges and can therefore be attracted to  an  electrode  by
imposing a potential across the stream of gas.
Evaporation
The process by which a liquid becomes a vapor.
Evaporator
A  device  which  converts  a  liquid  into  a  vapor by the
addition of heat.
                           760

-------
 Feedwater Heater
 Heat exchangers  in which boiler feedwater  is  preheated  by
 steam extracted  from  the turbine.
 Filter Bed
 A   device   for  removing  suspended  solids  from  water,
 consisting  of granular  material placed  in  a  layer(s)  and
 capable   of being  cleaned  hydraulically  by reversing the
 direction of the flow.
 Filtration
 The process of passing  a liquid through a  filtering  medium
 for the  removal  of suspended or colloidal matter.
 Fireside Cleaning
 Cleaning   of  the  outside  surface  of  boiler  tubes  and
 combustion  chamber refractories to  remove  deposits  formed
 during the  combustion.
 Floe
 Small  gelatinous masses  formed  in a liquid by the reaction
 of a coagulant added  thereto, thru biochemical processes, or
.by agglomeration.
 Flue Gas
 The gaseous products  resulting from the  combustion   process
 after passage through the  boiler.
 Fly Ash.
 A  portion  of the non-combustible residue from a fuel which
 is carried out of the boiler by the flue gas.
 Fossil Fuel
 A natural solid, liquid   or  gaseous  fuel  such  as coal,
 petroleum or natural  gas.
 Generation
 The   conversion of  chemical  or  mechanical  energy  into
 electrical  energy.
                               761

-------
Heat Rate

The fuel heat input (in Joules or Btus) required to generate
a kwh.

Heating Value

The heat available from the combustion of a  given  quantity
of fuel as determined by a standard calorimetric process.

Humidity

Pounds of.water vapor carried by 1 Ib of dry air.

  ffi
A  charged atom, molecule or radical, the migration of which
affects the transport of electricity through an electrolyte.

Ion Exchange

A chemical process involving reversible interchange of  ions
between  a  liquid  and a solid but no radical change in the
structure of the solid.

Lignite

A carbonaceous fuel ranked between peat and coal.

Makeup Water Pumps

Pumps  which  provide  water  to  replace   that   lost   by
evaporation, seepage, and blowdown.

Mechanical Draft Tower

A  cooling  tower in which the air flow through the tower is
maintained by fans.  In  forced  draft  towers  the  air  is
forced  through  the  tower  by  fans  located  at its base,
whereas in induced draft towers the air  is  pulled  through
the tower by fans mounted on top of the tower.

Mill

One thousandth of a dollar.

Mine-mouth Plant

A  steam electric powerplant located within a short distance
of a coal mine and to which the coal is transported from the
mine by, a conveyor system, slurry pipeline or truck.
                            762

-------
Mole
The molecular weight of a substance expressed in  grams  (or
pounds).
Name Plate
See Nominal Capacity
Natural Draft Cooling Tower
A cooling tower through which air is circulated by a natural
or  chimney  effect.   A hyperbolic tower is a natural draft
tower that is hyperbolic in shape.
Neutrali zation
Reaction of acid or alkaline  solutions  with  the  opposite
reagent  until  the  concentrations of hydrogen and hydroxyl
ions are about equal.
New Source
Any source, the construction of which is commenced after the
publication of proposed Section 306 regulations,  (March  4,
1974  for  the  Steam Electric Power Generating Point Source
Category).
Nominal Capacity
Name plate - design rating of a plant, or specific piece  of
equipment.
Nuclear Energy
The  energy  derived  from  the  fission  of nuclei of heavy
elements such as uranium or thorium or from  the  fusion  of
the nuclei of light elements such as deuterium or tritium.
Once-through Circulating Water System
A  circulating water system which draws water from a natural
source, passes it through the main condensers and returns it
to a natural body of water.
Overflow
(1)   Excess water over the normal operating limits  disposed
of by letting it flow out through a device provided for that
purpose;   (2)  The device itself that allows excess water to
flow out.
                             763

-------
Osmosis

The process of  diffusion  of  a  solvent  through  a  semi-
permeable membrane from a solution of lower to one of higher
concentration.

Osmotic Pressure

The   equilibrium   pressure  differential  across  a  semi-
permeable membrane which separates a solution of lower  from
one of higher concentration.

Oxidation

The addition of oxygen to a chemical compound, generally any
reaction which involves the loss of electrons from an atom.

Package Sewage Treatment Plant

A  sewage  treatment  .facility contained in a small area and
generally prefabricated in a complete package.

Packing (Cooling Towers^

A media providing large surface  area  for  the  purpose  of
enhancing  mass  and heat transfer, usually between a gas or
vapor, and a liquid.

Peak-load Plant

A  generating  facility  operated  only  during  periods  of
maximum demand.

Penalty

A sum to be forfeited, or a loss due to some action.

EH Valug

A  scale  for  expressing  the  acidity  or  alkalinity of a
solution.   Mathematically  it  is  the  logarithm  of   the
reciprocal of the gram ionic hydrogen equivalents per liter.
Neutral water has a pH of 7.0 and hydrogen ion concentration
of 10~7 moles per liter.

Placed in Service

Refers    to   the  date  when  a  generating   unit   initially
generated electrical  power  to service customers.
                             764

-------
Plant Code Number

A four-digit number  assigned  to  all  powerplants  in  the
industry inventory for the purpose of this study.

Plume {Gas)

A  conspicuous  trail of gas or vapor emitted from a cooling
tower or chimney.

Powerplant

Equipment  that  produces  electrical  energy  generally  by
conversion  from heat energy produced by chemical or nuclear
reaction.

Precipitation

A phenomenon that occurs when a substance held  in  solution
in a liquid phase passes out of solution into a solid phase.

Preheater

A  unit  used  to  heat  the  air  needed  for combustion by
absorbing heat from the products of combustion.

Psychrometric

Refers to air-water vapor mixtures and their properties.   A
psychrometric  chart  graphically  displays the relationship
between these properties.

Pulveriged Coal

Coal that has been ground to a powder,  usually  of  a  size
where 80 percent passes through a #200 U.S.S. sieve.

Pyrites

Combinations of iron and sulfur found in coal as FeS2.

Radwaste                      .

Radioactive waste streams from nuclear powerplants.

Range

Difference between entrance and exit temperature of water in
a cooling tower.
                            765

-------
Rank of Coal

A  classification  of  coal based upon the fixed carbon on a
dry weight basis and the heat value.

Rankine Cycle

The thermodynamic cycle which is the  basis  of  the  steam-
electric generating process.

Recirculation System

Facilities  which  are  specifically  designed to divert the
major portion of the cooling water discharge back for reuse.

Reduction

A chemical reaction which involves the addition of electrons
to an ion to decrease its positive valence.

Regeneration                        •

Displacement from ion exchange resins of  the  ions  removed
from the process solution.

Reheater

A  heat  exchange device for adding superheat to steam which
has been partially expanded in the turbine.


Reinfection

To return a flow, or portion of flow, into a process.

Relative Humidity

Ratio of the partial pressure of  the  water  vapor  to  the
vapor pressure of water at air temperature.

Reverse Osmosis

The  process  of  diffusion  of  a solute    through a semi-
permeable membrane from a solution of lower to one of higher
concentration, affected by raising the pressure of the  less
concentrated solution to above the osmotic pressure.
                             766

-------
Saline Wateg

Water containing salts.

Sampling Stations

Locations   where   several  flow  samples  are  tapped  for
analysis.

Sanitary Wastewater

Wastewater  discharged   from   sanitary   conveniences   of
dwellings and industrial facilities.
                                                            i
Saturated Air

Air in which water vapor is in equilibrium with liquid water
at air temperature.

Saturated Steam

Steam  at  the  temperature and pressure at which the liquid
and vapor phase can exist in equilibrium.
Generally insoluble deposits on heat transfer surfaces which
inhibit the passage of heat through these surfaces.

Scrubber

A device for removing particles or objectionable gases  from
a stream of gas.

Secondary Treatment

The  treatment  of  sanitary waste water by biological means
after primary treatment by sedimentation.

Sedimentation

The process of subsidence and deposition of suspended matter
carried by a liquid.

Sequestering Agents

Chemical compounds which  are  added  to  water  systems  to
prevent the formation of scale by holding the insoluble com-
pounds in suspension.
                               767

-------
Service Water Pumps                              *

Pumps  providing  water  for auxiliary plant heat exchangers
and other uses.

Slag Tap Furnace

Furnace in which the temperature is high enough to  maintain
ash  (slag)  in  a  molten state until it leaves the furnace
through a tap at  the  bottom.   The  slag  falls  into  the
sluicing water where it cools, disintegrates, and is carried
away.

Slimicide

An agent used to destroy or control slimes.

Sludge

Accumulated   solids   separated   from   a   liquid  during
processing.

Softener

Any device used to remove hardness from water.  Hardness  in
water is due mainly to calcium and magnesium salts.  Natural
zeolites,  ion  exchange resins, and precipitation processes
are used to remove the calcium and magnesium.

Spinning Reserve

The power generating reserve connected to the  bus  bar  and
ready to take load.  Normally consists of units operating at
less than full load.  Gas turbines, even though not running,
are  considered spinning reserve due to their quick start up
time.

Spray Module {Powered Sp.ray. ModuleL

A water cooling device consisting of a pump and spray nozzle
or nozzles mounted on floats and moored in the body of water
to be cooled.  Heat is transfered principally by evaporation
from the water drops as they fall through the air.

Station

A plant comprising one or several units for  the  generation
of power.
                              768

-------
Steam Drum'

Vessel  in  which  the saturated steam is separated from the
steam-water mixture and into which the feedwater  is  intro-
duced.

Supercritical

Refers  to  boilers  designed  to  operate  at  or above the
critical point of water 22,100 kN/sq m and '374.0°C  (3206.2
psia and 705. 4°F) .


Superheated Steam

Steam  which  has  been  heated  to a temperature above that
corresponding to saturation at a specific pressure.

Thermal Efficiency

The efficiency of the thermodynamic cycle in producing  work
from  heat.   The  ratio  of  usable  energy  to  heat input
expressed as a percent.

Thickening

Process of increasing the solids content of sludge.

Total Dynamic Head
Total energy provided by a pump consisting of the difference
in elevation between the suction and discharge levels,  plus
losses due to unrecovered velocity heads and friction.

Turbidity

Presence  of  suspended  matter such as organic or inorganic
material, plankton  or  other  microscopic  organisms  which
reduce the clarity of the water.

Turbine

A  device  used  to  convert the energy of steam or gas into
rotational mechanical energy and  used  as  prime  mover  to
drive electric generators.
                             769

-------
In  steam  electric  generation,  the basic system for power
generation consisting of a boiler and its associated turbine
and generator with the required auxiliary equipment.
Utility

(Public utility) A company either investor-owned or publicly
owned which provides service to the public in general.   The
electric utilities generate and distribute electric power.

Volatile Combustion Matter

The  relatively  light  components  in  a fuel which readily
vaporize at a relatively  low  temperature  and  which  when
combined or reacted with oxygen, give out light and heat.

Wet Bottom Furnace

See slag-tap furnace.

Wet Bulb Temperature

The  steady-state,  nonequilibrium  temperature reached by a
small mass of water immersed under adiabatic conditions in a
continuous stream of air.

Wet Scrubber

A device for the collection of particulate matter from a gas
stream or absorption of certain gases from the stream.

Zeolite

Complex sodium aluminum silicate materials, which  have  ion
exchange  properties  and  were  the  original  ion exchange
materials before synthetic resins were processed.
                               770

-------
APPENDIX 1

-------
INVENTORY NOTES







1.  Unless otherwise noted,  the generating capacity given



    is the installed capacity based on Federal Power



    Commission data of June  30, 1970,  updated to Janu-



    ary 1, 1972 through the  Electrical World Directory of



  fc  Electric Utilities, 1972-1973,  published by McGraw-Hill,



    Inc.







2.  Plants under construction are indicated by (*).







3.  Plant types indicated are as follows:



       F - Fossil fuel plant



       N - Nuclear plant



       G - Gas turbine unit  within a fossil fuel plant







4.  Unless otherwise indicated 60 Hz is the frequency of



    electricity generated.

-------
                              EPA REGION I

               Region:   Connecticut,  Maine,  Massachusetts
                        New Hampshire,  Rhode Island,  Vermont

        Region Office:   Boston,  Massachusetts
                              CONNECTICUT

Utility
Conn. Light & Power
Company




Conn. Yankee
Atomic Power Co .
Hartford Electric
Light Company




Norwich Department
Of Pub. Utilities
United Illuminating
Company



U. S. Navy

Plant
Devon

Montville
Norwalk Harbor

Millstone Point
Conn. Yankee Atomic

Middletown

Stamford
South Meadow
Millstone No. 2

Norwich

English Plant
Steel Point
Bridgeport Harbor

Derby Station
New London Sub. Base

Locat ion
Milford

Montville
Norwa Ik

Waterford
Haddam

Middletown

Stamford
Hartford
Waterford

Norwich

New Haven
Bridgeport
Bridgeport

Derby
New London
Gen. Capacity
(MW)
454
16.3
577.4
326.4
16.3
661.5
600.0

422
18.6
52.5
216.8
180
828
14.3

163.2
174.5
660.5
18.6
20.0
10.5

Type
F
G
F
F
G
N
N

F
G
F
F
G
N
F

F
F
F
G
F
F
Wallingford
  Electric Div.
Alfred L. Pierce
Wallingford
                                                                22.5
                                    Al-1

-------
                              EPA REGION I
                             NEW HAMPSHIRE
Utility

Public Service Co.
  of New Hampshire
Utility
Blackstone Valley
  Electric Co.

The Narragansett
  Electric Co.

Newport Electric
  Corp

U. S. Navy
Utility
  Light Dept.

Central Vermont

Plant
Daniel Street
Kelley Falls
Manchester Steam
Merrimack
Schiller

RHODE ISLAND
Plant
Pawtucket
South Street
Manchester Street
Newport
Quonset Point
VERMONT

Plant
J. Edward Moran

Milton Steam
Rutland

Location
Portsmouth
Manchester
Manchester
Bow
Portsmouth

Location
Pawtucket
Providence
Providence
Newport


Location
Burlington

St. Albans

Gen. Capacity
(MW)
21
18.8
20
459
37.2
178.8
Gen. Capacity
(MW)
33.5
188.6
132
11.0
5.0
Gen. Capacity
(MW)
30
28
4.0
31.2

Type
F
F
F
F
G
F
Type
F
F
F
F
F

Type
F
G
F
F
Vermont  Yankee        Vermont  Yankee
  Nuclear Power Corp.
Vernon
                 513
N
                                     Al-2

-------
                               EPA REGION  I
                                  MAINE
 Utility

 Bangor Hydro Electric  Graham
   Company

 Central Maine Power     Cape
   Company
 Maine  Public
   Service  Co.

 Maine  Yankee
   Atomic Power Co.

 U. S.  Navy
Utility

Boston Edison Co.
 Braintree Electric
   Light Dept.

 Brockton Edison Co.

 Cambridge Electric
   Light Company

 Canal Electric Co.

Plant
Graham

Cape
Mason
W. F. Wyman
Caribou
Bailey Point No. 1
Kittery

MASSACHUSETTS

Plant
New Boston Sta.No. 400
L Street Sta. No. 4

Edgar Station No. 75

Mystic Sta. No. 200

Leland St. Sta. No. 240.
Pilgrim
Allen Street
N.P. Potter
East Bridgewater
Blackstone Street
Kendell Square

Location
Bangor

South Portland
Wiscasset
Yarmouth
Caribou





Location
South Boston
South Boston

N. Weymouth

Everett

Framingham

Braintree
Braintree
Gen. Capacity
(MW)
57.5
12.0
22.5
146.5
213.6
19
855*
7
4.3

Gen. Capacity
(MW)
717.75
153.75
18.6
457.9
33.5
618.8
16.8
33.5
650*
21.0
12.5
East Bridgewater 20
Cambr idge
Cambridge
24.8
67.5

Type
F
G
F
F
F
F
N
F
F


Typ
F
F
G
F
G
F
F
F
N
F
F
F
F
F
Canal
Sandwich
542.5
                                     Al-3

-------
                                 EPA REGION I

                                MASSACHUSETTS  (continued)
Utility

Fall River Electric
  Light Company

Fitchburg Gas &
  Electric Light Co.

Holyoke Munic. Gas
  & Electric Dept.

Holyoke Water Power Co.
Mass. Bay Trans.
  Authority

Mass. Electric Co.
Montaup Electric Co.
New Bedford Gas &
  Edison Light Co.

New England Power Co.
Taunton 'Municipal
  Lighting Plant

U. S. Navy

Western Massachusetts
  Electric Co.
Gen. Capacity
Plant
Hathaway Street
Sawyer Passway
Holyoke

Mt. Tom Power Pit.
Riverside Station
South Boston
Lincoln
Webster Street
Lynnway
Somerset Station

Cannon Street
•Salem Harbor
Brayton Point
Westwater Street
B. F. cleary
Boston Navy Yard
West Springfield

Location
Fall River
Fitchburg
Holyoke

Holyoke
Holyoke


Worcester
Lynn
Fall River

New Bed ford
Salem
Somerset
Taunton
Taunton

West Springfield

MW
14.3
61.4
30
10
136
44.8
120
60
34.5
49.0
344
48
115.5
319.9
1124.7
49
28.3
22
209.6
18.6
Type
F
F
F
G
F
F
F
F
F
F
F
G
F
F
F
F
F
F
F
G
Yankee Atomic
  Electric Co.
Yankee Atomic
                    Rowe
185
                                         Al-4

-------
                                 EPA REGION  II
            Region:  New Jersey, New York, Puerto Rico, Virgin  Islands
     Region Office:  New York, New York
                                   NEW JERSEY
Utility

Atlantic City Elec: Co.
Jersey Central Power
 & Light Company
New Jersey Power &
 Light Company

Public Service Elec.
 s Gas Company

Plant
Missouri Ave.

Deepwater

Greenwich
B.L. England
•
E. H. Werner
Sayreville
Oyster Creek
Gilbert
Bergen

Burlington
Essex

Hudson

Kearny

Linden

Marion
Mercer

Sewaren

Salem 1
Salem 2

Location
Atlantic City

Penns Grove

Gibbstown
Bees leys Pt.
South Amboy
Sayreville
Lacey Township
Milford
Ridgef ield

Burlington
Newark

Jersey City

Kearny

Linden

Jersey City
Hamilton

Sewaren


Gen. Capacity
MW
50
55.8
308.3
18.6
10
299.2
116.3
343.8
640
126.1
640.4
18.6
490.5
329
417
1114.5
115.2
598.5
311.2
519.4
113.8
125
652.8
115.2
820
115.2
1090*
1115*

Tyj
F
G
F
G
F
F
F
F
N
F
F
G
F
F
G
F
G
F
F
F
G
F
F
G
F
G
N
N
Vineland Electric
 Utility
Vineland
Vineland
67.3
                                      Al-5

-------
Utility

Central Hudson Gas &
 Electric Corp.
Consolidated Edison
 Co. of N. Y.,  Inc.
Consolidated Edison
 Co. of N. Y.
Jamestown Board of
 Public Utilities
                                  EPA REGION II

                                    NEW YORK
Gen. Capacity
Plant
Danskammer Point

Rivers ide
Arthur Kill

Astoria


East River

Hell Gate

Hudson Ave .

Indian Point

Kent Avenue

Ravenswood

Sherman Creek
Waters ide # 1 & 2


74th Street


59th Street

Location
Roseton

Poughkeeps ie
New York

Queen


New York

New York

Brooklyn

New York

Brooklyn

New York

New York
New York


New York


New York

MW
531.9
5.5
12
911.7
16.3
1550.6
496
119.8
773.7
60
541.3
70
845
846
275
2138*
107.5
28
1827.7
481.8
216.5
140
572.3
14
125
144
37.2
184.5
34.2
Type
F
G
F
F
G
F
G
G
F
F 25
F
F 25
F
G
N
N
F 25
G
F
G
F
F 25
F
G
F 25
F
G
F 25
G










Hz

Hz




Hz




Hz


Hz


Hz

Samuel A. Carlson   Jamestown
Lawrence Park
 Heat, Light & Power Co. Lawrence Park
                    Lawrence Park
82.5
 1.1
                                      Al-6

-------
                                   EPA REGION II
                                     NEW YORK (continued)
 Utility
 Plant
   Location
Gen. Capacity
     MW         Type
 Long  Island Lighting Co.  E.  F.  Barret     island Park
                          Glenwood         Glenwood Landing
                          Port Jefferson   Port Jefferson
                          Far Rockaway
                          Northport
 New York State  Elec.
  S  Gas  Corporation
Goudey

Greenridge
Jennison
Hickling
Milliken
Bell
Niagara Mohawk Power Corp. Albany
Orange & Rockland
 Utilities  Inc.

Power Authority
 State of N. Y.
                          Charles  L.
                          Huntley
                          Oswego
Lovett
Bowlin
                  Far  Rockaway
                  Northport
Johnson City

Dresden
Bainbridge
East Corning
Ludlowville
Near Ludlowville

Albany
                 Buffalo
                          Dunkirk           Dunkirk
                          Nine Mile Point    Oswego
                 Oswego
Tonkins Cove
Near New Milford
375
258
403
467
16
113.6
774.2
387.0*
16
145.8
30.0
160
60
70
270
853*
400
155
828
0.7
628
642
5.7
376
0.7
489.5
1246*
F
G
F
F
G
F
F
F
G
F
F
F
F
F
F
N
F
G
F
G
F
N
G
F
G
F
F
J.A. Fitzpatrick    Oswego
                       800.*
                                     Al-7

-------
                                  EPA REGION II
                                     NEW YORK (continued)
 Utility

 Rochester Gas & Elec.
   Corp.
Plant
 Rochester #3

 Rochester #7
 Rochester #8
 Rochester #9
 Rochester #12
 Ginna R.G.
Location
Gen. Capacity
   MW
Rochester

Greece
Rochester
Rochester
Ontario
Rochester
206.2
18.0
252.6
8
3
420
517.1
F
G

F
F
F
N
U.S. Military Academy
  (Light & Power Plant)
Light Power
 U.S. Military
 Academy
West Point,N.Y.
                                                                   4.5
                                PUERTO RICO
Utility

Puerto Rico Water
 Resources Auth.

Plant Location
San Juan San Juan

South Coast Guayanilla



Palo Seco Catano

Gen. Capacity
MW
640
30
287.5
10
820*
40
657
30

Tyj
F
G
F
G
F
G
F
G
U.S. Navy
                         Ceiba
                 Ceiba
                                VIRGIN ISLANDS
Utility

Virgin Island Water &
 Power Authority

Plant
St. Thomas/
St Johns

St. Croix

Gen. Capacity
Location MW
Virgin Island 29.2

15.1
Virgin Island 25.5
18

TVP«
F

G
F
G
                                      Al-8

-------
                                EPA REGION III

                   Region:  Delaware, Maryland, Pennsylvania, Virginia
                            West Virginia, District of Columbia

            Region Office:  Philadelphia, Pennsylvania

                                    DELAWARE

-Utility
Delmarva Power & Light Co.






Dover Munic. Power Plant



Utility
Baltimore Gas & Elec. Co.











Delmarva Power & Light
Co. of Maryland


Plant
Delaware City

Indian River

Edge Moore


McKee Runn
St . Jones River
MARYLAND
-
Plant
Westport

Gould Street
Pratt Street
Riverside

Wagner, Herbert, A .


Crane P. Charles
Calvert Cliffs


Vienna


Location
Delaware City

Millsboro

Edge Moore


Dover
Dover


Location
Baltimore

Baltimore
Baltimore
Baltimore

Ba It imore


Baltimore
Nr. Annapolis


Vienna

Gen. Capacity
MW
130
18.6
330.2
18.6
389.8
15
378*
37.5
8.8

Gen. Capacity
MW
194
121.5
173.5
20
333.5
173.5
627.8
16
414.7*
399.8
16
1804*

244.5
18.6

Type
F
G
F
G
F
G
F
F
F


Type
F
G
F
F
F
G
F
G
F
F
G
N

F
G
Hagerstown Munic. Elec.
and Light Plant
Hagerstown
Hagerstown
                                         38.8
                                      Al-9

-------
                                 EPA REGION III

                                   MARYLAND (continued)
Utility

The Potomac Edison Co.



Potomac Elec. Power Co.
Utility

Chambersburg Municipal
 Electric Dept.

Duguesne Light Co.
Lansdale Elec. Dept.
Metropolitan Edison Co.
Plant
Smith, R . Paul
Cumberland
Celanese
Dickerson

Chalkpoint
Morgantown
PENNSYLVANIA
Plant
Chambersburg
Elrama
Frank R. Phillips
James H . Reed
Co If ax
Shippingport
Cheswick
Lansdale
Portland

Titus
Crawford
Eyler
Three Mile Island
Location
Williamsport
Cumberland
Amcella
Dickerson

Aquasco
Newburg
Location
Chambersburg
Elrama
Wireton
Pittsburg
Cheswick
Shippingport
Springdale
Lansdale
Portland

Reading
Middletown
Reading
Nr . Harrisburg
Gen. Capacity
MW
159.5
30
10
586.5
16.2
726.6
16.1
1146
35.8
Gen. Capacity
MW
15
525
411.2
180
262.5
100
525
24.5
11.3
426.7
37.6
225
18
116.8
84
1780*
Type
F
F
F
F
G
F
G
F
G
Type
F
F
F
F
F
N
F
F
G
F
G
F
G
F
F
N
                                      Al-10

-------
                                EPA REGION III
                                 PENNSYLVANIA  (continued)
Utility

Pennsylvania Power Co.

Pennsylvania Power s
 Light Co.
Philadelphia Elec. Co.
Philadelphia Elec. Co.
Plant
New Castle
Burner Island

HoItwood
Keystone Plant
Martins Creek

Stanton
Sunbury

Suburban
Montour

Schuylkill
Chester

Delaware    '

Richmond


Barbadoes

Southwark

Cromby

Eddystone
                           Peach Bottom 1
                           Peach Bottom 2
                           Peach Bottom 3
                           Limerick 1
                           Limerick 2
Locat ion
Gen. Capacity
    MW
U.G.I. Corporation
Hunlock Creek
West Pittsburgh
York Haven

Ho It wood
Schelocta
Martins Creek

Harding
Shamokin Dam


Washingtonville
Philadelphia


Chester

Philadelphia

Philadelphia

Norristown

Philadelphia

Phoenixville

Eddystone

Delta

Philadelphia

Hunlock
425.8
1577.7
1064*
105
1872
312.5
5
140.5
409.8
6.0
29.3
822.7*
50.0
275.4
18.6
256
55.8
439.3
76.2
594.0
487.2
155
65.4
345
74.4
417.5
275
707.2
37.2
40
18I!*3*
1065*
1065*
93.0
— — r-
F
F
F
F
F
F
G
F
F
G
F
F
F 25 Hz
F
G
F
G
F
G
F
G
F
G
F
G
F
G
F
G
N
N
N
N
F
                                     Al-11

-------
EPA REGION III





PENNSYLVANIA  (continued)
Gen. Capacity
Utility
Pennsylvania Elec. Co.








Pennsylvania State Uni.
Quakertown Mun. System
Saxton Experimental Corp.
Weatherly Borough
Elec . Dept .
West Penn Power Co.







Utility
Appalachian Power Co.

The Potomac Edison Co.
of Virginia
Virginia Elec. & Power Co.



Plant
Shawville
Seward
Warren
Front street
Saxton
Williamsburg
Homer City
Conemaugh

Central
Generating plant
Saxton

Weatherly
Springdale
Mitchell
Armstrong ,
Milesburg
Hartfield's Ferry

VIRGINIA

Plant
Glen Lyn
Clinch River

Riverton
Bremo
Chesterfield
Portsmouth

Location
Shawville
Seward
Warren
Erie
Saxton
Williamsburg
Homer city


University Park
Quakertown


Weatherly
Springdale
Courtney
Reesedale
Milesburg
Mansontown



Location
Glen Lyn
Cleveland

Riverton
Bremo Bluff
Chester
Norfolk

MW
640
268.3
73.4
118.8
30
39
1320
936
936*
7.5
9.9
10

1.5
416
448.7
326.4
46
576
1000*

Gen. Capacity
MW
401.1
669

34.5
284.3
1434.5
649.6
195.4
TyP'
F
F
F
F
F
F
F
F
F
F
F
N

F
F
F
F
F
F
F


Tyj
F
F

F
F
F
F
G
      Al-12

-------
                                 EPA REGION III
                                   VIRGINIA (continued)

Utility
Virginia Elec. & Power Co.







Danville Water, Gas &
Electric Dept.
Virginia Polytechnic
Heat & Power Plant
Potomac Electric Power Co.
U. S. Navy
Davi (MUN)

Plant
Possum Point

Reeves Ave.
12th street
Yorktown

Surry
North Anna

Brantley Steam St.

VPI Central Heat
Potomac River
Portsmouth
Brantley

Location
Dumfries

Norfolk
Richmond
Hornsbyville


Nr . Richmond




Alexandria


Gen. Capacity
MW
491
96
100
102.5
375
845*
1600*
1750*

29.0

1.8
514.8
27
29

Type
F
G
F
F
F
F
N
N

F

F
F
F
. F
WEST VIRGINIA

Utility
Monongahela Power Co.




Appalachian Power Co.



Ohio Power Co.



Plant
Albright
Riversville
Willow Island
Fort Martin
Harrison
Kanahwa River
Cabin Creek
Philip Sporn
John Amos
Krammer
Windsor
Mitchell

Locat i on
Albrighi-
Riversv-lle
Willow Island
Maidsville
Shinnston
Glasgow
Cabin Creek
New Haven
Winfield
Capt ina
Power
Capt ina
Gen. Capacity
MW
263
174.8
215
1152
1950*
426
273.6
1960
2950
675
300
1600

Type
F
F
F
F
F
F
F
F
F
F
F
F
* under construction
                                    A1.-13

-------
                                 EPA REGION III
                                  WEST VIRGINIA (continued)
Utility
Plant
Virginia Elec. & Power Co. Mount Storm
Location
                    Mount Storm
 Gen. Capacity
     MW	

     1140.5
       18.6
      555*
                                F
                                G
                                F
Utility

Potomac Elec. Power Co.
                                 DISTRICT OF COLUMBIA
Plant               Location
Benning
                           Buzzard Point
Washington
                    Washington
Gen. Capacity
    MW	

      553.6
      289*
       50
      270
      288
Type

 F

 F 25 Hz
 F
 G
                                      Al-14

-------
                                  EPA REGION IV
                Region:  Alabama, Florida, Georgia, Kentucky, Mississippi,
                         North Carolina, South Carolina, Tennessee
         Region Office:  Atlanta, Georgia
Utility
Alabama Elec.Coop.,Inc.



Alabama Power Co.
Southern Elec.Gen. Co.
Tennesee Valley Auth.
Utility

Florida Pwr. & Light Co.
                                    ALABAMA
Gen. Capacity
Plant
McWilliams

Tombigee
Barry

Chickasaw
Gorgas
Gadsden 1 & 2
Green County
Farley Unit 1
Farley Unit 2
Gaston C. Ernest


Colbert
Widows Creek
Brown's Ferry
FLORIDA
Location
Andalusia

Leroy
Bucks

Chickasaw
Gorgas
Gadsden
Demopolis
Nr. Cedar Springs
ii it ii
Wilsonville


Pride
Bridgeport
Near Decatur

MW
40
11.05
75
1770
60
138
756
138
568.5
820*
820*
1060.8
850
21.3
1396.5
1978
3456*

Gen. Capacity
Plant
Sanford
Palatka
Fort Myers
Port Everglades
Lauderdale
Riviera
Miami
Cutler
Cape Kennedy
Turkey Point
Turkey Point, 3 &
Hutchinson Island
Fort Pierce
Al-15
Location
Sanford
Palatka
Fort Myers
Port Everglades
Dania
Riviera
Miami
Cutler
Cape Kennedy
Florida City
4 Nr. Miami
Hutchinson Is .
Fort Pierce

MW
156.3
109.5
558.3
1254.6
312.5
739.6
46
346.3
804
817.5
1456.6*
892.5*
1500*

Type

  F
  G
  F

  F
  G
  F
  F
  F
  F
  N
  N

  F
  F
  G

  F
  F
  N
  F
  F
  F
  F
  F
  F
  F
  F
  F
  F
  N
  N
  N

-------
                                   EPA REGION IV
Utility

Florida Power Corp.
Tampa Elec. Co.
Gainsville Utilities
Jacksonville Elec. Auth.
Plant
FLORIDA (continued)

          Location
Gen. Capacity
    MW          Type
Bayboro
Paul L. Bartow

Higgins

Inglis
Suwannee River
Avon Park
George E. Turner

Crystal River
Port St. Joe
Rio Pinar
Anclote
St. Petersburg
St . Petersburg

Oldsmar

Inglis
Live Oak
Avon Park
Enterprise

Red Level
Port St . Joe
Rio Pinar
Tarpon Springs
51.3
494.4 .,
-
138
131.9
53.8
147
61
201.6
34
964.3
40.5
15
886*
F
F
G
F
G
F
F
F
F

F
F
F
N
Florida Public Utiilites   Marianna
Gulf Power Co.
                    Marianna
                              2.0
Crist

Lansing Smith
I
Scholz
Big Bend

Hookers Point
Francis J. Gannon

Peter 0. Knight
John R. Kelly

DeEr haven
J. Dillon Kennedy

Norths ide

Souths ide

Pennsecola

Pannama city

Chattahoochee
Tampa

Tampa
Tampa

Tampa
Gainsville

Hague
Jacksonville

Jacksonville

Jacksonville

651
578*
340
40
98
869.2
18
232.6
1270.4
18
60
99
43.5
81
356.6
40
560
32.9
356.6
34
F
F
F
G
F
F
G
F
F
G
F
F
G
F
F
G
F
G
F
G
                                      Al-16

-------
EPA REGION IV
  FLORIDA  (continued)
                            Gen. Capacity
Utility
Key West Utility Board
Lakeland Dept. of Elec.
& Water Utilities



New Smyrna Utilities
Tallahassee Elec. Dept.



Vero Beach Mun. Utilities
Orlando Utilities Coiran.




Utility
Georgia' Power Co.












Plant
City Elect . System

Larsen Memorial

Power Plant #3
Lake Mirror
Swoope
S. O. Purdom

Aruah B. Hopkins

Vero Beach
Orlando

Lake Highland
GEORGIA

Plant
Arkwright

Atkinson

Bowen

Hammond
Harlee Branch
Jack McDonough

McManus

Mitchell
Location
Key West

Lakeland

Lakeland
Lakeland
MW
70

120
33.8
90
10
New Smyrna Beach 7.5
St. Marks

Tallahassee

Vero Beach
Titusville

Orlando


Location
Macon

Smyrna

Catersville

Coos a
Milledgeville
Smyrna

Brunswick

Albany
130
25
80.9
17.0
62
294.3
317*
103.8

Gen. Capacity
MW
181.3
32.6
258
83.7
771.6
39.4
953
1539.7
598.4
80
143.8
159
218.3
Type
F

F
G
F
F
F
F
H
F
G
F
F
F
F
*•

Type
F
G
F
G
F
G
F
F
F
G
F
G
F
     Al-17

-------
                                   EPA REGION IV
Utility

Georgia Power Co.
Plant

Yates
Etowah

Hatch.
Wansley
Savannah Elec. & Power Co. Riverside
                           Port Wentworth
                           Effingham

Thomasville"Water & Light  Thomasville
                                    GEORGIA  (continued)
                                               Location
               Gen. Capacity
                  MW           Type
Newman


Nr. Jessup

Savannah
Port Wentworth


Nr . Guyton
Thomasville
680
2470*
40
1701*
1760*
111
207.9
21.6
120.3
158*
15.5
F
F
G
N
F
F
F
G
F
F
F
Crisp Co. Power Comm.
Crisp
Warwick
    10.0
                                    KENTUCKY
Utility
Plant
Locat ion
Gen. Capacity
    MW       .   Type
Kentucky Utilities Co.





Louisville Gas & Elec. Co.





Owensboro Mun. Utilities


Green River
Tyrone
E. W. Brown
Pieneville
Ghent
Hae fling
Canal
Cane Run

Paddy's Run

Millcreek
Owensboro
Elmer Smith

Central City
Versailles
Bur gin
Four Mile
Nr. Madison
Lexington
Louisville
Louisville

Louisville

Louisville
Owensboro
Owensboro

236.7
137.5
724.1
37.5
500
51
50
1016.7
16.3
337.5
48.5
642.2*
52.5
151
265
F
F
F
F
F
F
F
F
G
F
G
F
F
F
F
                                      Al-18

-------
EPA REGION IV
   KENTUCKY (continued)

Utility
Henderson Mun. Light

Big River Rural Elec.


E. Kentucky Rural Elec.


Tennessee Valley Auth.

Kentucky Power Co.


Utility
Mississippi Power & Light





Greenwood Utilities


Yazoo City - Public
Service Commission

South Mississippi Elec.
Power Association
Clafksdale Public Utility
Commiss ion


Plant
Henderson

Robert Reid
Coleman

Wm. C. Dale
Cooper John Sherman
Ohio River
Paradise
Shawnee
Big Sandy
MISSISSIPPI

Plant
Rex Brown

Delta
Natchez
Baxter Wilson

Wright
Henderson


Yazoo City


Moselle

Clarksdale


Location
Henderson

Sabree
Hanesville

Ford
Burns ide
Near Boone
Paradise
Paducah
Louisa


Location
Jackson

Cleveland
Natchez
Vicksburg

Greenwood
Greenwood


Yazoo City


Hattiesburg

Clarksdale

Gen. Capacity
MW
50.6
2
80
340
160
196
322
450*
2558.2
1750
1003

Gen. Capacity
MW
383.2
10
220.5
66
544.6
700
23.5
12.6
11.5

19
12.5

177

29.5
14.3

Typi
F
G
F
F
G
F
F
F
F
F
F


TyjDi
F
G
F
F
F
F
F
F
G

F
G

F

F
G
    A-19

-------
                                  EPA REGION IV
                                  NORTH CAROLINA
Utility

Carolina Power & Light
Duke Power Co.
Gen. Capacity
Plant
Cape Fear

H. F. Lee


W. H. Weatherspoon

Louis V. Button


Asheville

Roxboro


Brunswick
Riverbend

Buck

Dan River

Cliff side

Allen
Marshall
Be lews Creek
McGuire
Location
Moncure

Goldsboro


Lumberton

Wilmington


Asheville

Roxboro


Tranquil Harbor
Mount Holly

Spencer

Draper

Cliff side

Be Imont
Terrell
Near Greensboro
Near Mooresville
MW
421
72
402.5
16.3
89.9
165.5
79.5
225
91.3
420*
206.6
200.0
1067.8
720*
16.3
1642*
631
120
440
112.5
290
85
210
570*
1155
200
2160*
2300*
Type
  F
  G
  F
  G
  G
  F
  G
  F
  G
  F
  F
  F
  F
  F
  G
  N

  F
  G
  F
  G
  F
  G
  F
  F
  F
  F
  F
  N
                                      Al-20

-------
                                   EPA REGION IV
                                   SOUTH CAROLINA
Utility
Lockhart Power Co.
Plant
Lockhart
Location
Lockhart
Gen. Capacity
    MW
South Carolina Elec. &
 Gas Co.
So. Carolina Public
 Service Authority
Duke Power Co.
Greenwood Mills
Carolina Power & Light
McMeekin
Hagood
Canadys


Urquhart

Parr

Wateree
Buahy Park

Jef feries

Grainger
Lee

Tiger
Buzzard Roost

Melhews No. 1
Melhews No. 2
H. B. Robinson


Brunswick 1 & 2
Irmo
Charleston
Canady


Beech Island

Parr

Wateree
Nr. Moncks Corner

Moncks Corner

Conway
Pelzer

Duncan
Chappels

Greenwood
Greenwood
Hartsville


Wilmington
293.8
94.4
489.6
16.3
34.5
250
75.8
72.5
74
700
550*
60
272.8
172.8
163.2
345
90
30.0
16.1
196
25
32.5
206
21.3
700
1641*
F
F
F
G
G
F
G
F
G
F
F
G
F
P
F
F
G
F
F
G
F
F
F
G
N
N
                                      Al-21

-------
                                    EPA REGION IV
                                     TENNESSEE
Utility

Tennessee valley Auth.
Plant

Thomas H. Allen
Bull Run
Gallatin
John Sevier
Johnsonville
Kingston
Walts Bar
Cumberland.
Seguoyah
                                               Location
                Gen.  Capacity
                    MW
Type
 Memphis           990
 Clinton           950
 Gallatin         1255.2
 Rogersville        823.3
 New Johnsonville 1485.2
 Kingston         1700
.Walts Bar Dam     240
 Cumberland       2600*
 Daisy            2441.2*
  F
  P
  F
  F
  F
  F
  F
  F
  N
                                     Al-22

-------
                                 EPA REGION V
        Region:  Illinois, Indiana, Michigan, Minnesota, Ohio, Wisconsin

 Region Office:  Chicago, Illinois

                                   ILLINOIS
Utility
Central 111. Light Co.
Central Illinois Public
  Service Co.
Commonwealth Edison Co.
Plant
Locat ion
Gen. Capacity
    MW
R. S. Wallace
Liberty Street
E . D . Edwards

Keystone
Coffeen

Grand Tower
Hutsonville
Meredosia
Ridge land
Powerton

Joliet

Fisk


Dresden Nuclear #1
Dresden #2 & 3
Fordom
Crawford

Ca lumet

Waukegan

Dixon
Will County
Sabrooke

East Peoria
Peoria
South of Peoria

Bartonville
Coffeen

Grand Tower
Hutsonville
Meredos ia
Stickney
Pekin

Joliet

Chicago

•9
Morris
Morris
Rockford
Chicago

Chicago

Waukegan

Dixon
Joliet
Rockford

351.4
25
416
350*
54.4
389
600*
232.66
212.5
354.4
690
315
840*
1862
144
546.6
25
226.1
208
1620
75.3
701.5
192
174
292
1042
113
119
1258.9
196.4
148
F
F
F
F
F
F
F
F
F
F
F
F
F
F
G
F
F
G
N
N
F
F
G
F
G
F
G
F
F
F
G
                                     Al-23

-------
                                 EPA REGION V
                                   ILLINOIS  (continued)
Utility

Commonwealth Edison Co.
Electric Energy, Inc.

Illinois Power Co.

Plant
Kincaid
Quad Cities
Zion
LaSalle County
Joppa
Havana
Hennepin
Vermilion

Wood River
Baldwin


Location
Kincaid
Near Albany
Waukegan
Seneca
Elen
Havana
Hennepin
Oakwood

East Alton
Baldwin

Gen. Capacity
MW
1319.4
1618*
2100*
1156*
1078*
1100
230
306.3
182.3
15.0
650
623
1246.1*

Typ<
F
N
N
N
N
F
F
F
F
G
F
F
F
Mt. Carmel Public          Mt. Carmel
  Utility Co.

Carlyle Municipal          Carlyle
  Utilities

Highland Electric          Highland
  Light Dept.

Mascoutah Munic. Light     Mascoutah
  & Water Dept.

McLeansboro Munic. Light   McLeansboro
  & Power Plant
Mt. Carme1
Carlyle
Highland
Mascoutah
McLeansboro
 20.5
 12.5
  0.75
Rochelie Municipal         Rochelie
  Utilities

Springfield Water,         Lakeside
  Light & Power Dept.      Dallman
Rochelie
Springfield
Springfield
 12.5
155
 70.2
F
F
                                       Al-24

-------
                                 EPA REGION V
                                   ILLINOIS   (continued)
Utility

Winnetka Municipal
  Electric & Water Dept.

Southern Illinois
  Power Cooperative

Western Illinois Power
  Cooperative, Inc.

University of Illinois

Union Electric Co.


Peru Light Dept.

Iowa-Illinois Gas &
  Electric Company
Chicago, Metropolitan
  Sanitary District
Utility

Indiana & Michigan
  Electric Co.
Indianapolis Power &
  Light Company

Plant
Winnetka
Marion
Pearl
Abbott
Cahokia
Venice No. 1 & 2
Peru
Mo line
Chicago
INDIANA

Plant
Twin Branch
Tanners Creek
Breed
H. T. Pritchard
Elmer W. Stout
C. C. Perry
(Sec. K)
C. C. Perry
(Sec. W)
Petersburg

Location
Winnetka
Gen. Capacity
MW
25.5
South of Marion 94
Jacksonville
	
Sauget
Venice
Peru
Moline
Chicago


Location
Mishawka
Lawre ncebur g
Sullivan
Martinsville
Indianapolis
Indianapolis

Indianapolis

Petersburg
27.2
27.2
304
529
15.3
99.1
30.5

Gen. Capacity
MW
384
1098
450
393.6
372.6
47.5

11

724.4

Typ<
F
F
F
F
F
F
F
F
F


Typ<
F
F
F
F
F
F

F

F
                                     Al-25

-------
                                 EPA REGION V
                                   INDIANA  (continued)
Utility

North Indiana Public
  Service Company  .
Public Service Co.
  of Indiana, Inc.
Southern Indiana Gas &
  Electric Company
Logansport Municipal
  Utilities
Plant
Location
                                                              Gen. Capacity
                                                                   MW
Michigan City
Dean H. Mitchell

Bailly


Dresser
Edwardsport
Noblesville
Wabash River

Robert A. Gallagher
Rushville
Cayuga

Ohio River
Culley

Warrick Unit #4
Logansport

Michigan City
Gary

Dune Acres


Terre Haute
Edwardsport
Noblesville
West Terre Haute

New Albany
Rushville
Cayuga

Evansville
Newburgh

Yankeetown
Logansport

211
529.4
52.2
615.6
33.9
535*
210
146.8
100
962
8
600
8.25
500
500*
121.5
153.7
250*
150
55.5
18
F
F
G
F
G
F
F
F
F
F
G
F
F
F
F
F
F
F
F
F
G
Peru Electric Light &
  Power Dept .

Indiana Statewide Rural
  Electric Corp., Inc.

Indiana -Kentucky
  Electric Corp.

Frankfort Light &
  Power Dept.
Peru
Petersburg
Clifty Creek
Frankfort
Peru
Petersburg
Madison
Frankfort
                   40
                                      200*
                                     1303.6
                                       32.5
                                       16.5
F
G
                                      Al-26

-------
                                 EPA REGION V
                                   INDIANA  (continued)
Utility

Crawfordsville Elec.
  Light & Power Co.

Commonwealth Edison Co.
  of Indiana, Inc.
Plant
Crawfordsville
State line
               Gen. Capacity
Location        	MW	   Type

                   40.2          F
Crawfords ville
Hammond
                  972
Richmond Power and
  Light Dept.
Whitewater Valley   Richmond
Johnson Street      Richmond
                    Richmond
                   30
                   30
                   66*
                                 F
                                 F
                                 F
                                   MICHIGAN
Utility
Consumer Power Co.
Plant
               Gen. Capacity
Location           MW          Type
John C. Weadock

Saginaw River
Dane E. Karn

Bryce E. Morrow

Kalamazoo .
Elm street
Justin R. Whiting

B. C. Cobb
Wealthy Street
J. H. Campbell

Big Rock
Palisades
Midland
Essexville

Saginaw
Essexville

Comstock

Kalamazoo
Battle Creek
Erie

Muskegon
Grand Rapids
West Olive

Charlevoix
Palisades
Free Pond
614.5
' 20.6
100
530
615*
186
35
20
30
325
20.6
510.5
20
650
20.6
75
811.7*
1381.3*
F
G
F
F
F
F
G
F
F
F
G
F
F
F
G
N
N
N
                                      Al-27

-------
                                 EPA REGION V
Utility

Detroit Edison Co.
Indiana & Michigan
  Power Co.
Plant
                                   MICHIGAN  (continued)
Location
Gen. Capacity
     MW
Donald C. Cook
Upper Peninsula Power Co.  Escanaba
                           John H. Warden
                           Presque Isle
Bridgman
                    Escanaba
                    L'Anse
                    Marquette
  2200*
                   25.3
                   15.6
                  174.7
                  170*
Beacon St.
St. Clair

River Rouge
Greenwood Energy
Center
Conners Creek
Trenton Channel
Delray
Marysville
Pennsalt
Wyandotte North
Wyandotte South
Port Huron
Harbor Beach
Monroe
Fermi


French Island
Detroit
Bell River

River Rouge

Detroit
Detroit
Trenton
Detroit
Marysville
Wyandotte
Wyandotte
Wyandotte
Port Huron
Harbor Beach
Monroe
Detroit



27.8
1905
18.6
933.2

800*
585
1075.5
391
300
37
54.1
18.5
11.75
121
3000*
158
64
1075*
136
F
F
G
F

N
F
F
F
F
F
F
F
F
F
F
N
G
N
F
                  F
                  F
                  F
                  F
Coldwater Board of
  Public Utilities
Coldwater
Coldwater
    11.125
Detroit Public Lighting
  Commission
Mistersky
Detroit
   174
Escanaba Municipal
  Electric Utility
Escanaba
Wells
    25
                                      Al-28

-------
                                 EPA REGION V
                                   MICHIGAN  (continued)
Utility

Grand Haven Board of
  Light & Power
Plant
Location
Island Steam Plant  Grand Haven
Gen. Capacity
	MW	   Type

    20            F
Holland Board of
  Public Works
James De Young      Holland
                   77.2
Lansing Board of Water
  and Light
Marquette Board of
  Light & Power
Ottawa
Eckert
Delta
Lansing
Lansing
Lans ing
Marquette Gen.Pit.  Marquette
    81.5
   381
   160*

    34.5
F
F
F
Traverse City Light
  & Power Dept.
Traverse City Pit.  Bay
                   35
Northern Michigan
  Electric Coop., Inc.
Advance
Boyne City
    41.8
Michigan State Univ.

Wyandotte Munic.
  Service Commission
Utility

Minnesota Power &
  Light Co.
Northern State Power
  Co. (Minn.)
Sixty- five
Wyandotte

MINNESOTA

Plant
Aurora
Clay Boswell
M. L. Hibbard
Black Dog
High Bridge
Island
East Lansing
Wyandotte



Location
Aurora
Cohasset
Duluth
Nichols
St. Paul
St. Paul
31
41.5
23

Gen. capacity
MW
116.1
150
122.5
480.7
458.8
16
F
F
G


Type
F
F
F
F
F
F
                                      Al-29

-------
                                 EPA REGION V
                                  MINNESOTA  (continued)
Utility

Northern State Power
  Co.  (Minn.)
Otter Tail Power Co.
Alexandria Board of
  Public Works

Austin Utilities
Plant
Locat ion
Gen. Capacity
    MW
King
Mont ice llo
Red Wing
Minnesota Valley
Rivers ide
South East
Whitney
Wilmarth
Winona
Prairie Island
Crockston
Hoot Lake
Canby
Ortonville
Bemid j i
Alexandria
Austin


Bayport
Mont ice llo
Red Wing
Granite Falls
Minneapolis
Minneapolis
St. Cloud
Mankato
Winona
Near Hasting
Crockston
Fergus Falls
Canby
Ortonville
Bemid j i
Alexandria
Austin


598.4
569
28
65
506.4
30
21
25
26
1186*
10
136.9
7.5
15
37
5.25
27.5
6
30
F
N
F
F
F
F
F
F
F
N
F
F
F
F
F
F
F
G
N
Benson Water & Light
  Dept.

Blue Earth Power &
  Water Dept.

Detroit Lakes Public
  Utilities Dept.

Fairmouht Public
  Utilities Commission
Benson
Blue Earth
Detroit Lakes
Fairmount
Benson              0.45
Blue Earth          5.0
Detroit Lakes       6.0
Fairmount          26.5
Jackson Electric Light
  Dept.
Jackson
Jackson
    2.0
                                      Al-30

-------
                                 EPA REGION V
                                  MINNESOTA  (continued)
Utility

Litchfield Public
  Utilities Commission

Luverne Municipal util.    Luverne

Madison Munic. Util.

Marshall Munic. Util.
Moorhead Public
  Service Dept.

Mountain Iron (MUN)

New Ulm Public Util.
  Commission

Owatonna Municipal         Owatonna
  Public Utilities

Redwood Falls Public       Redwood
  Utilities Comm.

Rochester Public           Rochester
  Utility Dept.

Sleepy Eye Munic.Util.     Sleepy Eye

Springfield Pub. Util.     Springfield

Two Harbor Municipal       Two Harbors
  Water & Light Plant

Virginia Dept. of          Virginia
  Public Utilities
Plant
Litchfield
Luverne
Madison
Marshall
Moorhead
Mountain Iron
New Ulm
Location
Litchfield
Luverne
Madison
Marshall
Elm St. South
Mountain Iron
New Ulm
Gen. Capacity
MW
3.5
3.0
1.85
3.0
16.5
34
10
1.2
27
Type
F
F
F
F
G
F
G
F
F
Owatonna           34.5


Redwood Falls       2.0


Rochester         113


Sleepy Eye          3.25

Springfield         2.75

Two Harbor          6.0
              F

              F

              F
Virginia
34.5
                                      Al-31

-------
                                 EPA REGION V

                                  MINNESOTA (continued)
Utility

Willmar Municipal
  Utilities Commission

Windom Munic. Util.

Worthington Munic.
  Public Utilities

Northern Minn. Power
  Association
  Assn.
Interstate Power Co.
Utility

Cincinnati Gas &
  Electric Co.
Cleveland Electric
  Illuminating Co.

Plant
Willmar
Windom
Worthington
Kettle River
Elk River


Albert Lea
Fox Lake
OHIO

Plant
West End
Miami Fort

W. C. Beckjord

J. M. Suaurt

Zimmer
Ashtabula
Avon Lake
East Lake

Lake Shore

Location
Willmar
Windom
Worthington
Kettle River
Elk River


Albert Lea
Sherburn


Location
Cincinnati
North Bend

New Richmond

Aberdeen

Near Berlin
Ashtabula
Avon Lake
East Lake

Cleveland
Gen. Capacity
MW
32.4
3.0
16.5
4.25
45.0
22
17.2
18.5
104

Sen. Capacity
MW
219.3
519.2
182
760.5
460.8*
1830
610*
1756*
456
1275
577
680*
514

Type
F
F
F
F
F
N
G
F
F


Type
F
F
G
F
F
F
F
N
F
F
F
F
F
                                      Al-32

-------
                                 EPA REGION V
Utilities

Columbus & Southern
  Ohio Electric Co.
The Dayton Power &
  Light Co.
Ohio Edison Company
Ohio Power Company
Plant
                                     OHIO  (continued)
Location
Gen. Capacity
     MW
Poston

Conesville


Picway

Walnut

Miamisburg
J. M. Straut
Frank M. Tait
O. H. Hutchings

Troy
W. H. Sammis

R. E. Burger
Toronto
Niles
Edgewater
Gorge
Mad River
Scioto
Muskingum River
Woodcock
Tidd
Philo
Cardinal
Genl. James M.Gavin
Caldwell
Martins Ferry

Athens

Conesville


Columbus

Columbus

Miamisburg
Aberdeen
Dayton
Dayton

Troy
Stratton

Shady Side
Toronto
Niles
Lorain
Akron
Springfield
Scioto
Beverly
Bluffton
Brilliant
Philo
Brilliant
Near Gallipolis
Caldwell
Martins Ferry

232
13.8
433.5
842*
13.8
230.8
251.28
75
65.3'
6.4
610.2
444.1
414
32.6
24
1979
323*
544
315.8
250
174.9
87.5
75
40.3
1466.8
42.5
222.2
500
1270.5
2600*
2.8
6.5
2.0
F
G
F
F
G
F
G
F
G
F
F
F
F
G
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
G
                                     Al-33

-------
                                 EPA REGION V
                                     OHIO (continued)
Utility

Ohio Valley Elec. Corp.

Toledo Edison Co.
Cleveland Div. of
  Light & Power
Columbus Munic. Electric   Columbus
  Light Dept.

Celina Munic. Util.
Dover Electric Dept.

East Palestine Munic.
  Elect. Dept.

Hamilton Dept. of
  Public Utilities

Napoleon Munic. Util.

Norwalk Municipal
  Elect. Dept.

Orriville Munic. Util.
                                                              Gen. Capacity
Plant
Kyger Creek
Bay Shore
Acme

Clyde
Davis -Bee se

Lake Rd.
East 53rd St.
West 41st St.
Columbus

Celina

Dover
East Palestine
Hamilton

Napoleon
Wood lawn Ave.
Orriville

Location
Gallipolis
Oregon
Toledo

Clyde
Toledo

Cleveland
Cleveland
Cleveland
Columbus

Celina

Dover
East Palestine
Hamilton

Napoleon
Norwalk
Orriville

MW
1086.3
639.5
16
307
30
1
2
870*
172.5
50
35.6
43.5
14.5
25
20*
33.2
16.5
84
28.9
22.65
31.3
38.5
62.5*
Typ«
F
F
G
2'
F'
F
F
N
F
F
F
F
G
F
G
F
F
F
G
F
F
F
F
                                                                                 5 Hz
Painesville Electric
  Power Dept.
Painesville
Painesville
38
                                      Al-34

-------
                                 EPA REGION V
                                     OHIO  (continued)
                                                              Gen. Capacity
Utility

Piqua Munic. Power Plant   Piqua

Reading Municipal Water    Prospect
  and Light Plant

St. Marys Munic. Light
  & Power

Shelby Munic. Elect.
  Plant
Utility

Lake Superior District
  Power Co.

Madison Gas G Elect.Co.

Northern States Power
  Co.  (Wisconsin)
Superior Water, Light &
  Power Co.

Wisconsin Electric
  Power Co.
Plant
Piqua
Prospect

St. Marys
Shelby



WISCONSIN
Location
Piqua
Read ing

St. Marys
' Shelby




MW
53
9.5
14*
22
26.5
12.5*
3
2600*

Type
F
F
F
F
F
F
G
N

Gen. Capacity
Plant
Bay Front
Blount
Edison
French Is land
Sherbourne
Wins low
Lakeside
Commerce
East wells
Port Washington
Port Washington
North Oak Creek
South Oak Creek

Location
Ashland
Madison
La Crosse
La Crosse

Superior
St. Francis
Milwaukee
Milwaukee
Port Washington
Port Washington
Oak Creek
Oak Creek

MW
82.2
195.5
5
25
1360*
25.2
344.7
35
13.7
400
19
500
1170
19
Type
F
F
F
F

F
F
F
F
F
G
F
F
G
                                      Al-35

-------
                                  EPA REGION V
                                   WISCONSIN (continued)
Utility
Plant
Location
Gen. Capacity
     MM         Type
Wisconsin Electric
Power Co .

Wisconsin Power & Light
Company






Wisconsin Public Service
Corp.

Manitowoc Public Util.
Marshfield Electric &
Valley
Point Beach
Point Beach 1 & 2
Edgewater

Rock River

Black Hawk
Nepson Devy
Kewaunee
Columbia
Pulliam
Weston

Manitowoc
Wildwood
Milwaukee
Two Creeks
Manitowoc
Sheboygan

Beloit

Beloit
Cassville
Kewaunee
Near Portage
Green Bay
Rothschild

Manitowoc
Marshfield
269.7
19.6
1005.7
351
129
159.4
46.8
57.5
227.3
527*
527*
392.5
135
19.6
75
50.2
F
F
N
F
F
' F
G
F
F
N
F
F
F
G
F
F
  Water Dept.

Menasha Electric &
  Water Utilities
Menasha
Menasha
    29.2
Richland Center Munic.
  Utilities
Richland Center
Richland Center
    14.2
Dairyland Power Coop.
Alma
Stoneman
Genoa St. #1
Genoa St. #2
Genoa St. #3
Alma
Cassville
Genoa
Genoa
Genoa
   187
    51.8
    14.0
    50
   300
F
F
F
N
F
Oconto Elec. Coop.
Stiles
Stiles
                                      Al-36

-------
                                 EPA REGION VI

            Region:  Arkansas, Louisiana, New Mexico, Texas, Oklahoma
     Region Office:  Dallas, Texas
                                   ARKANSAS
Utility
Plant
Location
Gen. Capacity
     MW         Type
Arkansas Power & Light Co.







Hope Water & Light Pit.
Jonesboro Water & Light
Plant
Arkansas Electric Coop.
Corp.


Robert Ritchie

Lake Catherine
Cecil Lynch
Harvey Couch
Hamilton Moses
Russellville

Hope
Jonesboro

Fitzhugh
Bailey

McClellan
Helena

Hot Springs
N. Little Rock
Stamps
Forest City
Russellville

Hope
Jonesboro

Ozark
Augusta

Camden
903.6
18
756.0
259.8
187.5
138
793*
920*
6
27.7

59.8
122
200*
134
F
G
F
F
F
F
N
N
F
F

F
F
F
F
Utility

Central Louisiana
  Elec. Co., Inc.
New Orleans Public
  Service, Inc.
                                  LOUISIANA
Plant

Coughlin
Teche
Little Gypsy
Nine Mile Point
Sterlington

Mark St. Station
A. B. Patterson
Michoud
Location
Gen. Capacity
     MW         Type
St. Landry
Baldwin
La Place
Westwego
Sterlington
New Orleans
New Orleans
New Orleans
483.3
428
1250.8
1101
351.5
96.3
218.3
959.3
F
F
F
F
F
F
F
F
                                      Al-37

-------
                                 EPA REGION VI
                                  LOUISIANA  (continued)
Utility

Southwestern Electric
  Power Co.

Alexandria Munic. Power
 & Light Dept.

Homer Light & Power
  Dept.

Houma Munic. Light Pit.

Lafayette Util. System
Minden Light s Power
  Dept.
Monroe Util. Comm.
Morgan City Munic.
  Electric Plant

Natchitoches Munic.
  Elec. Light & Water

Ruston Munic. Light Dept.  Ruston

Opelousas Munic. Elec.
  Dept.

Plaquemine Light Dept.
New Orleans Sewage &
  Water Board

Plant
Arsenal Hill
Liberman
Alexandria

Homer
Houma
Rodemacher
Louis "Doc" Bonin
Minden
Park Ave.

Morgan
Natchitoches
Ruston
Opelousas

Plaquemine

Power House No. 2


Location
Shreveport
Mooringsport
Alexandria

Homer
Houma
Lafayette
Lafayette
Minden
Monroe

Morgan City
Natchitoches
Ruston
Opelousas

Plaquemine

New Orleans

Gen. Capacity
MW
170.0
277.3
97.5
80*
8.7
40.7
45.7
143.3
25
172
10
31
55.8
41.4
12.7
26*
20.5*
10.8
47.0
20

Type
F
F
F
F
F
F
F
F
F
F
G
F
F
F
F
F
F
G
F-25 Hz
G-25 HZ
                                      Al-38

-------
                                 EPA REGION VI
Utility

Gulf State Utilities Co.
Louisiana Electric
  Coop., Inc.
Utility

New Mexico Electric
  Service Co.
Public Service Co. of
  New Mexico
Clayton Municipal
  Electric System

Farmington Electric
  Utility

The Raton Public
  Service Company

Lea County Electric
  Cooperative, Inc.

Plains Elec. Generation
  & Trans. Coop., Inc.
Plant
                                  LOUISIANA  (continued)
Location
Gen. Capacity
    MW         Type
Louisiana St. #1&2
Roy S. Nelson
Willow Glen

River Bend #1&2
New Roads
NEW MEXICO

Plant
Maddox
Reeves
Person
Prager
Santa Fe
Baton Rouge
Westlake
St. Gabriel

Baton Rouge
Near Morganza


Location
Hobbs
Albuquerque
Albuquerque
Albuquerque
Santa Fe
428
920.5
994.4
530*
1880*
230*

Gen. Capacity
MW
118
175
125
35
12
F
F
F
F
N
F


Type
F
F
F
F
F
Clayton
Animas
Raton
Lea County
Plains
Clayton
Farmington         28.5
Raton              12
N. Lovington       59.6
Algodones          51.8
                                     Al-39

-------
                                  EPA REGION VI
                                 NEW MEXICO  (continued)
                           Plant
Utility

Southwestern Public
  Service Co.
Arizona Public Service Co. Four Corners

U.S. Atomic Energy         TA-3
  Commission

Gallup Electric Light      Gallup
  & Power System
                                               Locat ion
                                                              Gen. Capacity
                                                                   MW
                                               Nr.Farmington    2369.8

                                               Los Alamos         20
                                               Gallup
                   16.1
Cunningham
Carlsbad
Roswell

Hobbs
Carlsbad
Roswell

265.4
44.3
24.2
11.5
F
F
F
G
                                    TEXAS
Utility
Central Power & Light Co.
Dallas Power & Light Co.
El Paso Electric Co.
                           Plant
Locat ion
Gen. Capacity
     MW         Type
La Palma
Victor P.S.
Nueces Bay
Lon C. Hill
Laredo P.S.
J. L. Bates
E. S. Jospin
Dallas
Mountain Creek
Parksdale
North Lake
Lake Hubbard

Big Brown
Rio Grande
Newman
San Benito
Victoria
Corpus Christ i
Calallen
Laredo
Mission
Point Comfort
Dallas
Dallas
Dallas
Dallas
Dallas

Dallas
El Paso
El Paso
217
553.5 .
244.5
574.2
72
188.7
234.9
223.5
989.7
340.6
708.6
396.5
526.0*
83.3
235
265.8
F
F
F
F
F
F
F
F
F
F
P
F
F
F
F
F
                                      Al-40

-------
                                 EPA REGION VI
                                    TEXAS  (continued)
Utility

Gulf State util. Co.
Houston Lighting &
  Power Company
Southwestern Electric
  Service Co.
Plant
               Gen. Capacity
Location            MW         Type
Neches
Sabine

Lewis Creek
Deepwater
Gable Street
Deepwater -Champion
Hiram O. Clarke

Greens Bayou
Cedar Bayou

Webster

Bertrom, Sam

T. H. Wharton

W. A. Parish

P. H. Robinson

Beaumont
Bridge City

Willis
Houston
Houston
Houston
Houston

Houston
Bayton

Webster

Houston

Houston

Richmond

Bacliff

452.3
952
580*
500
334.125
84.1
334.9
210
96
375
692
823*
614
16.3
826.3
49
322.8
16.3
1255.4
16.3
1549.5
16.3
.. ifl -. ..
F
F
F
F
F
F
F
F
G
F
F
F
F
G
F
G
F
G
F
G
F
G
Jacksonville
Alabama
11.0
Southwestern Public
  Service Co.
Plant "X"
Nichols
Denver City
East Plant
Riverview
Jones.
Moore County
Tuco
Earth, Tex.       434.4
Amarillo, Tex.    474.8
Denver City,Tex.   87.5
Amarillo           71
Borger             69.5
Lubbock           235.2
Sunray             68.2
Abernathy          40
              F
              F
              F
              F
              F
              F
              F
              F
                                     Al-41

-------
                                 EPA REGION VI
                                    TEXAS (continued)
Utility

Texas Electric Service
  Company
Texas Power s Light Co.
West Texas Util. Co.
Austin Electric Dept.
Plant
                                               Location
               Gen. capacity
                   MW          Type
Graham
Eagle Mountain
Hand ley
North Main
Wichita Falls
Permian Basin

Morgan Creek
Big Brown
Collin
Lake Creek
River Crest
Stryker Creek
Trading House Creek

Trinidad
Valley
Waco
De Cordova
Abilene
Concho
Pauline
Oak Creek
Paint Creek
Rio Pecos

San Angelo

Seaholm Station
Holly Street
Decker Creek
Graham
Fort Worth
Fort Worth
Fort Worth
Wichita Falls
Monahans

Colorado City
Fair fie Id
Frisco, Tex.
Waco , Tex .
Bogata
Rusk, Tex.
Waco, Tex.

Trinidad, Tex.
Savoy, Tex.
Waco, Tex.

Abilene, Tex.
San Angelo
Quanah
Bronte
Stamford
Girvin, Tex.

San Angelo

Austin
Austin
Austin
634.8
706.2
523.4
116.3
25
165
535.5*
845.8
593
156.3
315.6
112.5
703.5
588.2
799.2*
413.3
1175
13
775*
26.3
52.5
44.5
81.6
241.6
136.5
5.0
100.8
32.6
134
416
300
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F


F
G
F
G
F
F
F
Bryan Municipal
  Elect. System
Bryan
Bryan
128.7
                                      Al-42

-------
                                  EPA REGION VI
                                    TEXAS (continued)
                                                              Gen. Capacity
Utility

Coleman Munic. Power
  & Light Dept.

Denton Munic. Util.

Garland Electric Dept.
Greenville Munic. Light
  s Power Dept.

Lubbock Power & Light
  Dept.

San Antonio Public
  Service Board
Brownsville Public
  Utilities Board

Brazos Electric Power
  Coop., Inc.
South Texas Electric
  Coop., Inc.

Texas ASM University

Lower Colorado River
  Authority
Plant
Coleman
Denton
C. E. Newman
Ray Olinger
Greenville
Holly Ave.

Leon Creek
Mission Rd.
W. B. Tuttle
W. H. Brattnig
Owsommers
Pearsall
Comal
Silas Ray

Poage
Worth Tex.
Randle W. Miller
Sam Rayburn

Univ. Utilities
Comal
Sim Gideon

Granite Shoals
Location
Coleman
Denton
Garland
Garland
Greenville
Lubbock

San Antonio
San Antonio
San Antonio
San Antonio
San Antonio
San Antonio
San Antonio
Brownsville

Belton
Weathorford
Palo Pinto
Nursery

College Station
New Braunfels
Bastrop

Marble Falls
MW
9.2
123.8
96.5
187
48.2
130.5
29.5
263.6
163.6
493.9
882
430
75
60
53.0
15.0
23
81.6
166
25
23
22.25
60
250
315*
408*
Type
F
F
F
F
F
F
G
F
F
F'
F
F
F
F
F
G
F
F
F
F
G
F
F
F
F
F
                                      Al-43

-------
                                  EPA REGION VI
Utility

Southwestern Electric
  Power Co.
Utility

Oklahoma Gas & Elect.Co.
Public Service Co. of
  Oklahoma
Kingfisher Munic. Light
  Dept.

Ponca City Munic.
  Water  & Light  Dept.

Stillwater Water &
  &  Light Dept.
                           Plant
                                    TEXAS (continued)
                                               Location
                                   Gen.  Capacity
                                        MW         Type
Knox Lee
Lone Star

Wilkes
OKLAHOMA

Plant
Seminole Sta .

Horse Shoe Lake

Mustang

Arbuckle
Belle Isle

Riverbank
Osage
Byng
Southwestern
Tulsa
Weleetka
Northeastern
Lawton
Long view
Lone Star

Jefferson


Location
Konawa

Harrah

Okla. City

Sulphur
Okla. City

Muskogee
Ponca City
Byng
Washita
Tulsa
Weleetka
Oolagah
Lawton
186
50
49
869.5

Gen. Capacity
MW
567
22
916.2
27.2
509.3
80
73.5
55.0
8.0
195.9
40
14
482.7
482
83
642.5
29.5
F
F
G
F


Type
F
F
F
G
F
G
F
F
G
F
F
F
F
F
F
F
F
Kingfisher
Ponca City
Boomer Lake
Kingfisher
Ponca City
Stillwater
                                       16.5
                                       22.65
                                       Al-44

-------
                                 EPA REGION VI

                                   OKLAHOMA (continued)

                                                               Gen. Capacity
Utility                    Plant               Location       	MW	  Type

Western Farmers            Anadarko            Anadarko           83            p
  Electric Coop.           Mooreland           Mooreland         191            F

Grand River Dam            Chouteau            chouteau           56.3          F
                                     Al-45

-------
                                 EPA REGION VII

                    Region:  Iowa, Kansas, Missouri, Nebraska

             Region Office:  Kansas City, Missouri
                                      IOWA
Utility
Interstate Power Co.
Iowa Electric Light
  & Power Co.
Iowa, Illinois Gas &
  Electric Co.

Iowa Power & Light Co.
Iowa Public Service Co.
Iowa Southern Util. Co.

Plant
M. L. Kapp
Dubuque
Lans ing
Mason City
Sutherland
Boone
Iowa Falls
Cedar Rapids
Duane Arnold
Rivers ide

Des Moines Pwr.
Station #2
Council Bluffs
Neal

Maynard
B ig S ioux
Kirk
Hawkeye
I.P.S. Gen. Pit.
I.P.S. Gen. Pit.
Charles City

Burlington
Bridgeport

Location
Clinton
Dubuque
Lans ing
Mason City
Marshaltown
Boone
Iowa Falls
Cedar Rapids
Cedar Rapids
Beltendorf

Des Moines

Council Bluffs
Sioux City

Waterloo
Sioux City
Sioux City
Storm lake
Caroll
Eagle Grove


Burlington
Eddyville
Gen. Capacity
MW
237.2
91.3
64
23.5
156.6
34.3
12.8
92.3
550*
237
72
324.6

103.6
147
300*
107.4
41
17.5
19
> 10.75
7.5
4.5
36.0
212
71

Type
F
F
F
F
F
F
F
F
N
F
G
F

F
F
F
F
F
F
F
F
F
F
G
F
F
                                      Al-46

-------
                                 EPA REGION VII
                                      IOWA (continued)
                                                             Gen. Capacity
Utility

Ames Electric Utility

Atlantic Munic. Util.

Cedar Falls Munic. Util.


Denison Munic. Util.

Grundy Center Munic.
  Light & Power

Harlan Munic. Util.

Mt. Pleasant Util.

Muscatine Power &
  Water Dept.

Pella Munic. Power &
  Light Dept.

Sibley Munic. Util.

Spencer Munic. Util.


Trear Munic. Util.

Webster City. Munic.
  Light & Power Dept.

Central Iowa Power Coop.


Corn Belt Pwr. Coop.
Plant
Ames Municipal
Atlantic
Streeter
Denison
Grundy Center
Harlan
Mt. Pleasant Munic.
Muscatine
Pella
Sibley
Spencer
Trear
Webster City
Prairie Creek
Summit Lake
Location
Ames
Atlantic
Cedar Falls
Denison
Grundy Center
Harlan
Mt. Pleasant
Muscatine
Pella
Sibley
Spencer
Trear
Webster City
Cedar Rapids
MW
63.7
14.75
31.3
22
4.5
1.25
6.4
13.3
108
17.0
2.5
17.5
22.4
1
15.4
20.6
244.7
22.5
Typt
F
F
F
G
F
F
F
F
F
F
F
F
G
F
F
G
F
F
Humbolt
43.8
                                     Al-47

-------
                                 EPA REGION VII
Utility

Central Kansas Power Co.



Kansas Gas & Elec. Co.
Plant
                                               Location
Gen. Capacity
      MW_  	    Type
Kansas Pwr. & Light Co.
Western Power Div.
Central Telephone &
Utilities Corp.

Anthony Electric Dept.

Chanute Munic. Elec.Dept.

Clay Center Munic.
  Electric Dept.

Coffeyville Munic. Water
  & Light Dept.

lola Electric Dept.

Kansas City Board of
  Public Utilities
Lamed Elec. Light Dept.   Larned
Hays
Ross Beach
Colby
Gordon Evans
Murray Gill
Neosho
Ripley
Wichita
Tecumseh
Lawrence
Hutch ins on
Abilene
Phillipsburg
Arthur Mullergren
Power Station
Chanute
Clay Center
Coffeyville
Municipal
KAW
Quindaro
Hays
Hill City
Colby
Wichita
Wichita
Parsons
Wichita
Wichita
Tecumseh
Lawrence
Hutchinson
Abilene
Phillipsburg
Great Bend
Anthony
Chanute
Clay Center
Coffeyville
lola
Kansas City
Kansas City
17
35
12
539.3
348.3
113.5
87.3
22.8
346.1
613.4
252.2
33.8
3.0
133.5
5.25
19
12.5
40.25
15.5
161.3
331.6
15
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
G
                    Larned
                                                                   12.8
                                     Al-48

-------
                                 EPA REGION VII
                                     KANSAS  (continued)
Utility
Plant
Location
Gen. Capacity
     MW          Type
Mepherson Board of
of Public Utilities
Ottawa Water & Light
Dept.
Pratt Munic. Elect. Dept.
Washington Munic . Light
Plant
Winfield Munic. Elec.


Wheatland Elec. Coop., Inc.

Sunflower Elec. Coop.
Empire Dist. Elec. Co.




Utility
Empire Dist. Elec. Co.
Kansas City Power &
Light Co.



Mepherson #1
Mepherson #2
Ottawa

Pratt
Washington

Winfield

Winfield
Garden City

Ross Beach
Riverton


MISSOURI

Plant
Asbury
Motrose
Hawthorn
Northeast
Grand Avenue

Mepherson
Mepherson
Ottawa

Pratt
Washington

Winfield

Winfield
Garden City

Ros£ Beach
Riverton




Location

Clinton
Kansas City
Kansas City
Kansas City

25.5
32
7.25
11.8
23.8
4.8

18
11.3
26.5
28.5
15
25
42.5
112.5
12.5

Gen. Capacity
MW
200
563.1
887
156
116.8
10
F
F
t
F
G
F
F

F
G
F
F
G
F
F 25 Hz
F
G


Type
F
F
F
F
F
F 25 Hz
                                     Al-49

-------
                                 EPA REGION VII
                                    MISSOURI  (continuted)
Utility
Plant
Location
Gen. Capacity
     MW          Type
Missouri Public Service
  Inc.

St. Joseph Light &
  Power Co.

Union Electric Co.
Chillicothe Munic.Util.

Columbia Water & Light
  Dept.

Fulton Board of Public
  Works

Hannibal Board of Public   Hannibal
  Works

Independence Power &
  Light Dept.

Macon Municipal Util.

Sikeston Board of
  Munic. Utilities

Springfield City Util.

Northeast Missouri
  Elec. Power Corp.
Gen. Plant
Gen. Plant
Sibley
Ralph Green
St. Joseph Gen. Pit.
St. Joseph Gen. Pit.
Labad ie
Meramec
Ashley
Mound
Sioux

Chillicothe
Columbia
Fulton Pit. #1
Fulton Pit. #2
Hannibal
Blue Valley
Dodgion Street
Macon
Coleman
James River
Gen. Plant
Jefferson City
Mexico
Sibley
Pleasant Hill
St . Joseph
St . Joseph
Labad ie
SE St. Louis Co.
St. Louis
St. Louis
Near Portage Des
Sioux
Wabash Tracks
Columbia
Fulton
Fulton
Hannibal
Independence
Independence
Macon
S ikes ton
K is sick
South River Sta.
12.7
19
518
49.5
42.5
150.5
1110
923
70
40
1099.6

15
90
11.5
8.3
34
115
. 10
4.5
6.25
268
15
F
F
F
F
F
F
F
F
F
F
F

F
F
F
F
F
F
F
F
F
F
F
                                     Al-50

-------
Utility
                                 EPA REGION VII
                                    MISSOURI  (continued)
Plant               Location
Gen. Capacity
	MW	    Type
N.W. Electric Pwr. Coop.,  Generation Pit.     Missouri City      40
  Inc.
Arkansas-Missouri
  Power Co.
Jim Hill
     33
ASEC
Thomas Hill
Central Elec. Power Coop.  Chamois
    440*

     59
  F

  F
                                    NEBRASKA
Utility                    Plant

Alliance Munic. Elec.      Alliance
  Dept.

Fairbury Light & Water     Fairbury
  Dept.
                    Location
                    Alliance
                    Fairbury
Gen. Capacity
    MW	

     16.5
     21.5
Type

  F
Fremont Dept. of Util.
Grand Island Elec. Dept.

Hasting Utilities Dept.
Schuyler Dept. of Util.
Central Nebraska Public
Power & Irrigation Dist.
Nebraska Public Power
District




Fremont
C. W. Brudick

Hasting
Schuyler
Canady

Bluffs
Gen. Plant
Sheldon
Kramer
K Street
Cooper
Fremont
Grand Is land

Hasting
Schuyler
Lexington

Scottsbluff
Ogallala
Hallam
Bellevue
Lincoln
Nr. Nebraska City
70.0
70.5
60*
54
9
100

42.4
9
228.6
113
31.1
800*
F
F
F
F
F
F

F
F
F
F
F
N
                                     Al-51

-------
                                 EPA REGION VII

                                    NEBRASKA (continued)

                                                             Gen. Capacity
Utility                    Plant               Location      	MW	    Type

Omaha Public Pwr. Dist.    Jones Street        Omaha             173.5          F
                           North Omaha         Omaha             644.7          F
                           South Omaha         Omaha              20            F
                           Ft. Calhoun         Omaha             455*           N
                                     Al-52

-------
                                EPA REGION VIII

                Region:  Colorado, Montana, North Dakota, South Dakota,
                         Utah, Wyoming

         Region Office:  Denver, Colorado


                                   COLORADO
Gen. capacity
Utility
Public Service Co. of
Colorado







Central Telephone &
Utilities Corp.


Western Colorado Power Co.


Colorado Springs Dept.
of Public Utilities

Burlington Municipal
Light & Power
Ft. Collins Light & Power
Lamar Utilities Board
Plant

Valmont
Zuni
Alamosa
Arapahoe
Cameo
Cherokee
Ft. St. Vrain
Comenche

Pueblo
Canon C:ty
Rocky Ford
J. Bullock
Durango
Oliver

G. Bridsall
Martin Drake

Burlington
Ft. Collins
Lamar
Location

Va Imont
Denver
Alamosa
Denver
Cameo
Denver
Plattsville
Comenche

Pueblo
Canon City
Rocky Ford
Mont rose
Durange
Paonia

Colorado Springs
Colorado Springs

Burlington
Ft. Collins
Lamar
MW

281.8
115.3
18.9
250.5
75
250.5
330*
350

30
43.8
7.5
10
5
3

62.5
150

7.5
8.0
34
Typ

F
F
F
F
F
F
N
F

F
F
F
F
F
F

F
F

F
F
F
Trinidad Municipal
Power & Light
Trinidad
Trinidad
7.5
                                      Al-53

-------
                                      DRAFT
Utility

Walsenburg Utilities

Colorado utilities
Elec. Assn. Inc.
Utility

Montana-Dakota
Utilities Co.
Montana Light & Power
Montana Power Co.
Utility

Montana-Dakota
Utilities Co.
Valley City Municipal
Utility
                                EPA REGION VIII
                                  COLORADO (Continued)
Plant
Welsenburg
Hayden
Nucla
McGregor
MONTANA
Plant
Lewis & Clark
Glendive
Miles City
Baker
Libby
Troy
Frank Bird
J.E. Corette
NORTH DAKOTA
Plant
R. M. Heskett
Beulah
Williston
Location
Welsenburg
Hayden
Nucla
McGregor
Location
Sidney
Glendive
Miles City
Baker
Troy
Troy
Billings
Billings
Locat ion
Mandan
Beuhla
Williston
Gen. Capacity
MW
11.0
163.2
34.5
5.3
Gen. Capacity
MW
50
7
2
1
12.6
3.5
69
172.8
Gen. Capacity
MW
100.1
13.5
2
Type
F
F
F
F
Type
F
F
F
F
F
F
F
F
Type
F
F
F
Valley City
Valley City
Basin Electric Power Coop. Leland Olds
                    Stanton
                   240
                                      Al-54

-------
                                 EPA REGION VIII
                                  NORTH DAKOTA  (continued)

Utility
Central Power E lee. Coop.
Minnkota Power Coop., Inc.

United Power Assoc.


Utility
Black Hills Power & Light

Northern States Power Co .



Northwestern Public
Service Co.

Rushmore Elec . Power
Coop . , Inc .



Utility
Utah Power & Light




Plant
Wm. J. Neal
F. P. Wood
Milton R. Young
Stanton
SOUTH DAKOTA

Plant
Kirk
Ben French St.
Lawrence
Path Finder

Sioux Falls

Aberdeen
Mitchell

Kirk

UTAH

Plant
Carbon
Gads by
Hale
Jordan

Location
Velva
Grand Forks
Centre
Stanton


Location
Lead
Rapid City
Sioux Falls
Sioux Falls

Sioux Falls

Aberdeen
Mitchell

Near Whitewood



Location
Castle Gate
Salt Lake City
Or em
Salt Lake City
Gen. Capacity
MW
38
21.5
234.5
172

Gen. Capacity
MW
31.5
22
48
66
72
16

12.5
12.5

15
16.5

Gen. Capacity
MW
188.6
251.6
59
25.0

Type
F
F
F
F


Type
F
F
F
F
N
F

F
F

F
F


Type
F
F
F
F
Provo City Power

California-Pacific
Utilities Co.
Provo
Cedar
Provo
Cedar City
14
 7.5
                                      Al-55

-------
                                EPA REGION VIII
                                    WYOMING
Utility
Plant
Montana-Dakota Utilities   Acme

Black Hills Power & Light  Neil Simpson
                           Osage

Pacific Power & Light Co.  D. Johnaron

                           Trona
                                               Location
Gen. Capacity
     MW         Type
Sheridan
Wyodak
Osage
Glenrock

Near Green River
12
27.7
34.5
456.7
330*
15.6
F
F
F
F
F
F
Utah Power & Light Co.     Naughton

Rushmore Elec. Power
Coop., Inc.                Naughton

Sinclair Refining Co.      Sinclair
                                               Kemmerer
                                               S incla ir
                                                                  707
                                       380.8
                                       200*
                                         6.2
                 F
                 F
                 F
                                      Al-56

-------
                                 EPA REGION EC

                  Region:  Arizona, California, Hawaii, Nevada

           Region Office:  San Francisco, California
                                    ARIZONA
Utility
Tucson Gas & Elec. Co.
Arizona Elect. Power
  Coop., Inc.

Salt River Project
  Agricultural Impr. &
  Power District

Southern Calif. Edison
Plant
Location
Gen. Capacity
    MW
Yuma Axis
Saguaro
Ocotillo
Cholla Point
Phoenix
DeMos s - Pe tr ie
Irving ton
Apache

Agua Fria
Crosscut
Kyrene
Navajo
Yuma Axis
Yuma
Red Rock
Tempe
Joshep City
Phoenix
Tucson
Tucson
Cochise

Glendale
Tempe
Tempe
Paige
Yuma
86.7
250
227.3
113.6
116.0
104.5
504.5
75
11.3
390.5
30
108
2310
75
F
F
F
F
F
F
F
F
G
F
F
F
*F
F
Utility
Pacific Gas & Elec. Co.
                                   CALIFORNIA
Plant
Location
Gen. Capacity
    MW           Type
Avon
Contra Costa
Humboldt Bay

Hunters Point
Kern
Avon
Antioch
Eureka

San Francisco
Bakers fie Id
40
1253.6
102.4
60
391.4
152
F
F
F
N
F
F
                                     Al-57

-------
                                 EPA REGION EC
Utility

Pacific Gas & Elec. Co.
   (cont.)
San Diego Gas & Elec.Co.
Southern California
  Edison Co.
Burbank Public Service
  Dept.
Plant
                                   CALIFORNIA  (continued)
                                               Location
                                  Gen. Capacity
                                       MW          Type
Martinez
Morro Bay
Moss Landing
Oleum
Pittsburg
Potrero
Geysers
Diablo Canyon
Station B
Silver gate
Encina

South Bay

Redondo Beach
Long Beach
Etiwanda

Alamitos

El Segundo
Huntington Beach

Mandlay Steam

Ormond Beach
Highgrove
San Bernardino
Cool Water
San Onofre
Mangolia

Olive
Martinez
Morro Bay
Salinas
Oleum
Pittsburg, Cal.
San Francisco
Geysers
Near Oceano
San Diego
San Diego
San Diego

Chula Vista

Redondo Beach
Long Beach
Etiwanda

Long Beach

El Segundo
Hermosa Beach

Oxnard

Ormond Beach
Colton
Loma Linda
Dagget
San Clemente
Burbank

Burbank
40
1056.3
2152.2
80
1277.8
317.9
190
1134*
93
247
330.8
20
738.0
18.6
1579.4
180
911
138.1
1982.4
138.0
996.5
870.4
121
435.2
121
750
169
130.6
146.9
450
70
21
99
F
F
F
F
F
F
F
N
F
F
F
G
F
G
F
F
F
G
F
G
F
F
G
F
G
F
F
F
F
N.
F
G
F
                                      Al-58

-------
                                 EPA REGION DC
                                   CALIFORNIA (continued)
                                                             Gen. Capacity
Utility

Glendale Public Service
  Dept.

Los Angeles Dept. of
  Water and Power
Pasadena Water & Power
  Dept.

Imperial Irrigation Dist.

Sacramento Municipal
  Utility District
Utility
Hawaiian Electric Co.
Kauai Electric Co.
Maui Elec. Co.,, Ltd.
Plant
Glendale
Harbor
Valley
Scattergood
Haynes
Broadway
Glenram
El Centre Steam PI.
Rancho Seco
HAWAII
Plant
Honolulu
Waiau
Kahe
Hilo

Maui
Location
Glendale
Wilmington
Sun Valley
Playa Del Rey
Seal Beach
Pasadena
Pasadena
El Centre
Rancho Seco

Location
Honolulu
Waiau
Kahe
Hilo

Maui
MW
163
355
512.5
312.5
1606
171
65.3
187.6
913*

Gen. Capacity
MW
168.2
394.5
239.0
37.5
11.7
35
Type
F
F
F
F
F
F
F
F
N

Typ*
F
F
F
F
G
F
Port Allen

Kahului
Kauai

Maui
10
38.5
                                     Al-59

-------
                                 EPA REGION DC
Utility
Nevada Power Co.
                                     NEVADA
Plant

Clark Station
Sunrise Station
Reid Gardner St.
Sierra-Pacific Power Co.   Tracy Steam Pit.
                           Fort Churchill
                             Steam Plant
Location
                                                             Gen. Capac ity
                                                                *MW
East Las Vegas
Las Vegas
Moapa
Sparks

Yerington
190.3
81.6
227.3
135
25
110
Type

  F
  F
  F

  F
  G
  F
Southern California
  Edison Co.
Mohave
Near Big Bend    1210
                                     Al-60

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                                   EPA REGION X

                       Region:  Alaska, Idaho, Oregon,  Washington

                Region Office:  Portland,  Oregon
                                    ALASKA
Utility

Fairbanks Municipal
 Utilities System
Qhugach Electric
 Association Inc.

Golden Valley Electric
 Association Inc.
U. S. Air Force
U. S. Army
U. S. Navy
Utility

Potlatch Forests Inc.
Plant
               Gen.  Capacity
Location          MW          Type
Fair Banks

Kink Arm
Fairbanks

Healy
Elmendorf West
Elmendorf Central
Fort Wainwright
Eielson
Clear AFB
Ft. Richardson
Ft. Greely
Port Whit tier
Kodiak
Adak
IDAHO

Plant
Lewinston
Fa ir banks

Anchorage
Fairbanks

Healy
Elmendorf
Elmendorf
Near Fairbanks
Eielson
Near Nenana
Anchorage
Ft. Greely
Portage
Kodiak
Adak


Location
Lewinston
8.5
7.0
14.5
9.5
17.5
22
22.5
9.0
23.5
10
22.5
18.0
2.0
6.5
4.0
15.9

Gen. Capacity
MW
10
F
G
F
F
G
F
P
F
F
F
F
F
N
F
F
F


Tyj
F
                                     Al-61

-------
                                   EPA REGION X
                                     OREGON
Utility
Plant
                                               Location
Gen. Capacity
     MW         Type
Pacific Power & Light Co.



Portland Gen. Elec. Co.
Eugene Water & Elec . Board


Utility
Seattle Dept. of Light.

Tacoma Public Utilities-
Light Division

Pacific Power & Light Co.

Public Utility Dist . No. 1
of Cowlitz County
Public Utility Dist.. No. 1
of Pend Dreille Co.
Puget Sound Power & Light
Lincoln
North Bend
Astoria
Springfield
Station L
Eweb
WASHINGTON

Plant
Lake Union
Georgetown

Steam Plant #1
Steam Plant #2
Centralia


Long ViiiW

Box Canyon
Shuffleton
Portland
North Bend
Astoria
Springfield
Portland
Eugene


Location
Seattle
Seattle

Tacoma
Tacoma
Centralia


Lewis River

Lone
Renton
35
15
8
5
75.5
25

Gen. Capacity
MW
30
22

9
50
700
700*

26.7

77.2
87.5
F
F
F
F
F
F


Type
F
F

F
F
F
F

F

F
F
Washington Public Power
Supply System              Hanford
                    Hanford
    860          N
    1135*         N
                                     Al-62

-------
APPENDIX 2

-------
                FORMAL COORDINATING ORGANIZATIONS OR POWER  POOLS  292
1. New England
2. New York
3. P-J-M Interconnection
4. California
5. The Southern Company System
6. American Electric Power System
7. Allegheny Power System
 8. Central Area Power Coordination
 9. Kentucky •  Indiana
10. Michigan
11. Cincinnati, Columbus, Dayton
12. Illinois • Missouri
13. Iowa
14. Upper Mississippi Valley
15. Wisconsin
16. Missouri Basin  Systems Group
17. Missouri -  Kansas
18. Middle South Utilities System
19. Texas Utilities Company System
20. South Central Electric Companies
21. Pacific Northwest Coordination
NOTE: Not ill systems operitini ii cadi of Hie 21 wets ire formil power pool members.
                                  Figure  A-2-1
                                       A2-1

-------
                                 INFORMAL COORDINATING GROUPS   292
                                                 January 1, 1970
 10,12
   Associated Mountain Power Systems
   Colorado Power Pool
   Colorado Systems Coordinating Council
   Florida Operating Committee
   Joint Power Planning Council
   Mid-Continent Area Power Planners
    New Mexico Power Pool
    Northwest Power Pool
    Rocky  Mountain Power Pool
    Southern California Municipal Group
11.  The Intercompany  Pool
12.  Western Energy Supply & Transmission Associates
13.  Wisconsin Upper Michigan Systems
 7.
 8.
 9.
10.
NOTE: Are* boundaries are only general; not id system
     within a boundary ire members of the designated orpniutions
                                 Figure  A-2-2
                                      A2-2

-------
            NATIONAL ELECTRIC RELIABILITY  COUNCIL REGIONS
                           Canadian Portions Net Included
                                                                         292
WSCC    Western Systems
           Coordinating Council

MARCA  Miittontinent Area Reliability
           Coordination Agreement

SPP      Southwest Power Pool

ERCOT   Electric Reliability Council Of Texas

MAIN    Mid-America Interpool Network
                                           NPCC
         Northeast Power
          Coordinating Council
MAAC   Mid-Atlantic Area
          Coordination Group

ECAR    East Central Area Reliability
          Coordination Agreement

SERC    Southeastern Electric
          Reliability Council
                        Figure  A-2-3
                       A2-3

-------
                                                                  Table   B-2-l
                                                       Mambera of Formal Coordinating Ora.anli«tr»lis •» *owaf Pswjlt        O Q O

                                                                                Ijaaiury  I. I'JTO)
.H,. A>(I«W rwv> JW (NKPOOI.) '

    Nlllllf.**! Clllilirt '
    lb»HNi l^liixa Company ,
    New l.«.ifl-nd Meurk System *
    Omul M.«inJe»-«s.y.W ;«*rr««rr». (PJM)

    Pulitir S^rviie IJeetrie and Cas Company
    I'liil.t-l'iiii.ia Kktrik Company
    Cener;il r..Un  Utilities Crirpnralinn
       Mrli'.f*i.liiin  felbun Company
       IVnmylv.mil  Ueclric Company
       Jersey Central Power ami Light Compaay
       New Jeney Power ft Light Company
Public Setvice Omiiiany of New MampshM
tjMtrra Ulilitirl AaM.Ulr* •
Nrw rJiKluxl CM ft Klrctfk AMDC.'
Central Vcrrn.  n Public Sen*c Co.
Onlral lludxxi Ca! A r^ectrk Corp.
Korhrilrr (iai an>l Klrclrie Corp.
(haniir and Ruralaml UliliuVl, Inc.
Powef Authority ul tl>e .Suu of N. V.
 Pronsrlvuiia Po^r » IJirkl Company
 Baltimorr Oji and Kktlrie Company
'Potomac rUeetric Power Company
   oxi-rauai /W (MOKAN) •

     Kinuire Mavfal Klnlik Cumpmy
     K»nta> itnpxiiy
     Huhlii: Service <4>. of < >kUlH.ina
     SuulJiwrnrrn Wei Irk- I'uwer (>Nnpany
    ICaiMaa Pow*v and IJtli* f^Mwpany
    MianMiri PuUic Vrvkr
   . MiwiMippj Power A IJ«I|I Company
    New (likana Pul^k Service. Inc.
    Araanus Power aod tiithl Company
    LAuiaiana Power and l.ferhl Ojntpany
    Mi«KMtpf>i Power and l.ighl Cnmpany
    KanMa Cat and FJeclrie Company
    Lmpire Ubiricl FJectric Company
                                                  Dallas Power (k l^lil Ctimpiay
                                                  'IVxaa l-Jectrtc S«rvire Company
                                                  Teua Power and Light CbmpMr
       r-furu.* />Mm JW (CARVA) •
     Virxir.il F.lrctric ft Power Company
     Carolina Power i IJfhl Company
     Alabama Power Company
     Georgia Power Compaay
 Duke Power Company •
 South Carolina Electric & CV»r {MM (APS) (HMut C—f-,)

     Monongahela Power Company
     Potomac Cdijon Company
     W« Penn Power Company

       Art* ftuMt CWAjHTM Citmp (CAPCO)
  Mklugan Power Co.
  Scwell Valley Utilitid Co.
  Wheeling Electric Co.
  Ohio Power Company
    Central lUiaoaf Pofalk Service Co.
    Illinoii Power Company
    Union FJeetrie Compaay

Uff* MimiiiHi VJU, /Wr> /W
    CooperativcB
     . Cooperative Power Aanclatko
      Dabylaad'Power Cooperative
      Mmnfcota Power Cooperative
    rnverua
               edCompaniei
      Intentate Power Company
      Lake Superior District Power Co.
      Minaeaou Power & Light Compaay
                                                Iowa FJectnc I Jghl and Power Co.
                                                lowa-IUinoia Ca« and Eire. Co.
                                                Iowa Power and Light Company
     Cleveland fjectric lUumuiating Company
     Duquetoe Ljfht Company
 Cw»-a. draarfu. D.*. IW (CCO)
 Ohio Edaon System (Hotding Company)
 1  Ohio Prison Cnmpany
   Pennsylvania Power Company
 Toledo Cdisoa Company
              * Soothem Ohio FJectric Co.
     Daytoa Power a Light Co.
     Ciacinaati Cas ft Ekctric Co.
     rWrr *i«l (KIP)
             !:. power ft Lajbt Co.
     Public Service Co. at Indiana
     Kentucky Utilities Coaspaay
   Wawaa P.btk Service Corporalloa
   Wlaconain Power and Li, hi Company
   Madison Cas and Elecinc Company
 nsart ahna Sj*m, CVsap (MBSC)

   U. S. Bureaa of Reclamation
   Basin Electric rower Cooperative
   Central Power Elecuk Cooperative
                                                                                        Northern Minnesota Power Assoe.
                                                                                        Rural Cooperative Power Assoc.
                                                                                        United Power Aasociatina '
Mcntana-Oaiota Utilities Ca.
Northern Stairs Power Compaay
Northwestern PuMk Service Cump.M
Oiler Tail  Power Company
                                          Iowa Public Service Company
                                          Iowa Southern Utilities Company
                                          Com Belt Power Cooperative
                                                                                       Nebraska Public Power System
                                                                                       Other Members
     Oetroa Edaon Coeapaay
                                                                                               Suuthrro California Edison Company
                                                                                               Pacific Cai and Klrclrk Company
                                                                                               Sjn Diego Gas ft Electric Company
                                                                                               nonsicville Power Adminiatralion
                                                                                               City of F.ugene, Oregon
                                                                                               City of VatuV, Waihinglnn
                                                                                                   anaa Traasmiviwjn Company
                                                                                               Montana Hnwrr Company  .
                                                                                               Paeifk Power a I jfthl CVrtnpany
                                                                                               Piirlbjnd Cmrtal l.leclric aall.4ding..«npany.
                                       . • Power Aulht»ily rf the Sute ol New York lakes part in pool planning and operations, but DM In commercial trana-
                                    actions of Ihr p>>4.
                                        • hvaing agieiustal lerminated as of rsrmher 2H, 1470.
                                        • There are akn liv« uteltile memhrrs: *t. jiarjili IJghl ft f>mn Co.; Board a( Puljk Utllilln of Kansas (Sly. Kansas:
                                    Uty W l»drpn>.leate, Mi^iurii fVnlral Ttkphoae aad Utilities Corp.- Western Power Uiviamai and Asaocialeit rJrilric
                                    raiasnaiive. Inc.
                                                                  A2-4

-------
fc
171
                                              Table   A-2-2
                                                                                                                                (January I. 1970)
                                                            PLANNING ORGANIZATIONS AND THEIR MEMBERS
              Aovr Sftwiu (AMPS)
 Idaho Power Co.
 Montana Power Co.
 Pacific Power ft Ughi Co.


* Pmv Fiatmf C*aHn7(JPPC)
 Pacific Power ft Light Company
 Portland General Electric Co.
 Puget Sound Power ft Light Co.
                                                                                             Uuh Power ft Light Co.


                                                                                Total 3 System


                                                                                             Washington Water Power CD.
                                                                                             BonoevUle Power Administration
                                                                                             Publicly  Owned  UtIHtks  in  Oregon, Washrngfaa,
                                                                                               Idaho and Montana {104 System)
                                                                               Total 109 Systems
/•Cfi.'iwwl Arn Ptx.tr Pt**xtrt (MAPP)
  Bljrk Hilli Power ft Light Co.
  NwthwraterD Witronwn Electric Co.
  Omaha Public Power Dblrkt
 .NVbraika Publk Power Diitrict
  Central Iowa Power Cooperative
  Eaitrm Iowa Light ft  Power Coop.
  Iowa Power Pool Members
    owa r'lectrif t.irht  and Power Co.
    owa-lllinou Oaj and Klrrtric Co.
    o«a Power and Light Co.
       t Publk Service Co.
       s SoulSrm Utilities Co.
    Corn Belt Power Gxiper.itive
  Union r'leetric Otnpjuiy
  Munu-ipil Syiienu in  Nebraska. South Dakota, Iowa

  Manitoba Hydro-Electric  Board
Upper Mivlanppi Valley Power Pod
  Cooperatives
    Cooperative Power AasneUUoa
    Dalryland Power Cooperative
    Minnkota Power Cooperative
    Northern Minnesota Power Aane.
    Rural Cooperative Power Aasoc.
               lnvettor-o
                 Intrntate Power Company
                 Lake Superior Dbtrtct Power Co.
                 Mlnnoota Power & Light Company
                 Montana-Dakota Utilities Company
                 Northern Siata Power Company
                 North wo i cm Public Service Co.
                 Otter T*il Power Company
                                                                                Total 34 Syrtems
                                         E.vf\ Sffftt & Trwiitrion Ainrittn (WEST)
                                      Arizona Public Service Co.
                                      Lo« Anseln Prui. of Water & Power
                                      EJ PA» tl«tric Co.
                                      Nr*-jd* Power Co.
                                      Public Service Company of Colorado
                                      San Pirtro G« &  tier trie  Co.
                                      Sierra Pjcine Power Co.
                                      Southern California T(]i*oa Co.
                                      Tueioa CM ft Flecirie Co.
                                      t't»h Po»er A I ieht Co.
                                      Arizona Flectric Power Coop.
                                      Public Service'Co. of New Mexico
             Arizona Power Authority
             Burbank Publir Servke Dept.
             City of Colorado Spring*         ,
             Colorado-Uie Electric Awoclation, Inc.
             ClemJale Public Service Departmeat
             Imperial Irrigation Dbuki
             Pacific Power ft Light Co.
             PaudenA Municipal Light & Power Dept.
             Plain* Electric C.&T. Coop., Inc..
             Salt River Project
             Central Telephone A Utilities Corp. (Soulhen Goto.
                Power Div.)
Total n Syttemi
                                                                                                                                                                 OTHER INFORMAL COORDINATING CROUPS AND THEIR MEMBERS
                                                                 CWaraA P*~f /W (COLOPP)
                                                                     Publk Vrviee Company of Colorado
                                                                     City of Coltjrado Springs
                                                                     Southern Colorado Power Div. of C.T.U.
                                                                               P*W (INTKHPOOL)
                                                                           Power & l.i*ht fVmipany
                                                                             (irn-r.il Metric Co.
                                                                                                              Total SSrrtetm
                                                           Pufet Sound Power ft Light Co.
                                                           Washington Watirr Power Co.
                                                                                                              Total 4 System*
                                                                                                                                                                UwW.>«/ Onmp (SCMO)
                                                                                                                                                     \f* Angelet Departmeni of Wafer and Power
                                                                                                                                                     Gkndale Public Service Dept.
                                                                                                                            Burbank Public Service D-pf
                                                                                                                            Paiadena Municipal Light &  Power Drpt.
                                                                                                                                                                                              Total4Syite»
CWwaA Sgitmi CWA'Minv Cmmi( (CSCC)
    Centra] Munkrpal Light ft Power System
    Colorado Spring* Dept. of Public Utility
    Town of Etie* Park
    Fort Oollim Light & Power Depanment
    City of Fort Morgan
    Clenwoort Spring! Municipal FJec. System
    Julrtburg Power ft Light Department
    U Junta  Municipal Utilities
    Utilitiei Board or*r Mkkigm fytumt (WUMS)
    Wiacoetin-Mkhigan Power Co.
    Upper Prnmiula Power Co,
                                                                 Xar*s A/M0tf«M Aowr /W (RMPP)
                                                                     Public Service Company of Colorado
                                                                     Pacific Power Ik Light Co.
                                                                     USBR Region*  4 and 7
                                                                     Montana Power Co.
                                                                     OuMumen Public Power Dlilrief
                                                                     Southern Colorado Power Division of C.T.U.
                                                                     CJly of Colorado Spring*
                                                                                                                                                                       Tamp* FJECIKC O».
                                                                                                                                                                       City of Jark.«mvUle
                                                                                                                                                                       Orlando L'tiliii^i CumraiMion
                                              ToUlS Systems
                                                                                                                                                                       Wisconsin Power P'xri (3 S«!-r
                                                                                                                                                                       Wbeoniin tlrc*ric Pcw-r Co.
                                              Total 6 Syrtctm
                                                                                                                                                                                                            Utah Power & Light Company
                                                                                                                                                                                                            Black Ililli Pnw«r ft Ligl.t Co.
                                                                                                                                                                                                            TrvSute G. ft T. Aaue.. Inf.
                                                                                                                                                                                                            Colorado-t_'te Elec. Aworiation, f
                                                                                                                                                                                                            CrKycnne I.^M. F*ir| ft V'.^-r
                                                                                                                                                                                                            Western Co'era'Jo r*oi*er O>
                                                                                                                                                                                              Total 13 Synems
                                                                                                                                                     ,tf/m» /Wrr /W (NMPP)
                                                                                                                                                     Comanmity Public Service Compaay
                                                                                                                                                     El Paso Electric Company
                                                                                                                                                     Plain* F4ectrie O. ft T. Coop.
                                                                                                                            USBR Rio Grande Project
                                                                                                                                                                                               Total 3 Syttf ma
                                                                                                                                                    fA.I*rf /'«*A /W (SWPP)
                                                                                                                                                     Bnnnrvilk Power Administration
                                                                                                                                                     Eugene Water &  Eleciric Hoard
                                                                                                                                                     Idaho Power Co.
                                                                                                                                                     Montana Power Co.
                                                                                                                                                     Pacifr Power ft I^ght Co.,
                                                                                                                                                     Portland Cenrral Electric Co.
                                                                                                                                                     Pugrt Sound Power ft Light Co.
                                                                                                                                                     P.L'.D. No. 1 of Chelan County
                                                                                                                                                     P.U.D. No. I ofDoutlj* County
                                                                                                                            P.U.D. No. 7 of Trant O»J. Pacific I>v.
                                                                                                                            ITSBR-BPA'tSouthern Ida^sl
                                                                                                                                                                                              Total 18 S

-------
                              Table A-2-3
                                                                                                OQO
            Multiple Membership* in Informal Coordinating Organizations or Power Pools
                            System
                                                               |.   H  O
El Paso Electric Co .............................................  X  X
Public Service Co. of N.M .......................................  X  X
Plains Electric G. & T. Coop ...................................... X  X
City of Los Angeles .................................................  X  X
City of Glendale [[[  X  X

City of Burbank [[[ .'X  X
City of Pasadena [[[  X  X
Pacific P. & L. Co. (Wyoming) ........................ ...............  X ............ X
Utah Power & Light Co .............................................  X ........ X  X ..... ."..../. X
Public Service Co. of Colorado .......................................  X ....  X .... X  X

City of Colorado Springs ............................ .................  X ____  X ____ X  X
Central  Telephone & Utilities Corp. (Southern Colorado Power
  Division) [[[  X ____  X ____ X  X
Colorado-Ute Electric Association ............ .........................  X ....  X .... X
Western Colorado Power Co .................................................  X ____ X
Tri-State G. & T. Association ................................................  X .... X

Bureau of Reclamation ................. .........................  X ........  X ____ X
Portland General Electric Co [[[ X ........ X  X
Puget Sound Power & Light Co .................................................. X ........ X  X
Pacific Power & Light Co [[[ X ........ X  X  X
Washington Water Power Co.  [[[ X ........ X  X  X


-------
                                                                                Table   A-2-4
                                                                        brfWMiMl M.mW. W (.gUMl I
                                                                                                                            ncUl1
                                                                                                                                    292
BM« KJntrir ftmu Cbepcnttvt
U«k 1Mb IWcT ttt U|W Ok
Crttlr*! luwa ftf^rr CVM»
Guoprralnc Powrt Amc.
COCK Hrll Pow^r Coop.
IteirvUnd Powrr OH^.
burn l IJ^ki mt NMT Che*.
Inunuic Fbvcr O*.
low* Ekcltk l.«ht ft r»«r OK
lOM-a-Iltinoil <*as & Ekctm QK
lo»> i'uwn «od Uflrl Co.
low. Publk Soviet Ot.
Iowa Soudteni Utilidn OK

Aaoei«tn: Uni(MI Ekclfk Ok.
           Muiiuba H)dn>-EJ«ctric limd ofCu>a>
        er rW ^iiinwnl tfPT)
Arkansas-Electric Coop. Corp.
Arkamas-Mitsouri rWe» Co.
Arkarua* Power ft Lif bt Co,
Associated Electric Coop., lac.
Boaid of Public CtiBtks. Kaasas Otr. Ka*.
CratraJ Loukiaaa Uecflrk Co.. lac. (TV)
City Powrr & U*tu Dept.. Independence, Mo.
Giy Liilmes of Springfield. MisMtiri
Empire Dbtrici tUectric Co. (The)
Cnml River Dun Authority
Cutf States UtUitks Cunapsny
K*eu* GIT Powrr * IJffcl Oh
KaiUM Uai and Electric Co.
KaniM Power * Light Co. (The)
AiUmk City Electric Co.
Baltimore Cai and Electric Co.
Delmarva Power & I-ighi Co.
Jrrwy Central Powrr ft Lifffal Ch
.M^tnipoliua Cdboa Co.
Nrw jemy Pow«r & Lifbt Oh
 Alabama l!>rlt k Cknprraiive
 AUbkma Power (kxnpany
 Carotin. Po*rr & L^ht Co,
 CrUp t'ounty I'u
 l>ukc Puwer f^mipany
 flotilla Power ( :>ir|*rr.ittan
 rU-«i* Power & l^hl Co.
 (((•urgta Puwrr O>.
        illr Kli'Ctrir Autliurily
          l>pi. i^ I Or. & Water
 A,.,MU-|»..n IWr, (i,
 CiiKJiuuli (•;<« •"-• I.)" Ifif. iiiiinMtinK ('•"•
 f >4'imlMr> A; .S.»II|M-III Oluo KWtric (
           Pi«w<-r (ij.
                                                          Nrw rjlfflMMt |>* hi
                                                          Nrw l^iciMft f ;«• A  r>rt(ir
                                                          Nrw Viwk S»,,ir l>rlnr
                                                          Nnrlliraat l.'lUtlin
                                                          Onetr •ml KirklaMl Dlitil**. lac.
                                                          Pow-« Aulhiirity itf th*> .Sl.M «f New V<-fc
                                                          KorhrMrr Gu and Kkciric Ctvp.
                                                          Tl«r tinned lUwmmalMia; .tny
 I^NUKMH" lJi;t"t C^fiii|Mny
 l_^i Kmiixky kiii.il t. W »ik- ti-
 liHtMn^-Krnno ky IJ'i nk (inp.
 IlKlbna A Mfl.iit^n l.l-'l. (-.
                                                          Lake Swprrkir DMtrirt Powrr Co.
                                                          Uinnrvxa Ptiwrr ft IJajbl CM.
                                                          Minnkoia P«mrr f *Akirta Utility Co.
                                                          Nrliraiaa Pnhlir Pawn District
                                                          Norilvrn Minor«uU fawtt AaMxia
                                                          Northrto States Puwrr Co.
                                                          Northwrflrm Puhlk Service Co.
                                                          Onaba Publk Power District
                                                          Onrr Tail Puwer Co.
                                                          Rural Coop. Power AsMciation
                                                          U. S. Bureau of Reclamation
                                                           Loumaaa Power ft .   Co.
                                                           Mawsnppi Power * t.ight Co.
                                                           Minouri EdiMn Co.1
                                                          . Miaouri Tower & Liffht Co.1
                                                           Misnuri Public Service Co.
                                                           Mivouri Utilitiei Corapany
                                                           New Ortrattt Publk Service, Inc.
                                                           Oklahoma Gas & Electric Co.
                                                           Publk Scrvke Co. of OVUhoma
                                                           St. joaeph Ufhi  &  Power Co.
                                                           Southweiiem Elevtrk Power Go.
                                                           Southwestern Power Admimitranon
                                                           WeMem Fannen Electric Coop.
                                                           Wotera Power Uviiioa—CT & U
                                                           Pew»ylv»oia Electric Co.
                                                           PenosyrvaoU Power & Light Co.
                                                           PhiUdrlphi* F.leeiric Cov
                                                           Potomac Klectric Power Co.
                                                           Pttblk SenHre  Ekctrie «nd Gu Co.
                                                           UGICorp.
                                                                         er Co.
                                                                          r &  Uiuitvtlk <,M ft  Clrririr L'rfim
                                                           Norlliern Indi.ma TuMir Srrvicr f'a.
                                                           Ohio M'atM Omiji.my
                                                           Ohio Piiwrr r^Ht>|..iny
                                                         • Ohio Valley r.lrftii. (i«p.
                                                           Prnniylvrftiix I'owrr lrfiin|Mny
                                                           PulrwnAC  K«livj«i (V»m|i4iiy
                                                           Putilk Servirr <'*. <•! Imli.nia
                                                           Snutlfm Imliiin.i Cji A Klmrir Co.
                                                                                                             A»«MirW4'llltn.Mi (.*• ft rJrctrk Co.*
     luwa I'owrr ft t Jf^rt  Compwy *

 XZftftw KHtmMtti C^mit if 7V»*i (tJtCOT)
     H-K  r.lnlric (xjtip., Int.
     rUird. t:.ty of
     Kinlrii r.liHific <>np., lac.
     Uuehrinnrl KJrr. C-mp., Inc.
     Ko^rne I'lililiri
     lluwtr. City uf
     Brady W^irr K IJRl.l Workl
     Bra«n I'.ln . I'uwer Omp., Inc.
     Birnl^ni Muni. i|*al UliUtia
     BrownivilKC^iyiif
     Bryan.'Uly.d
     (^>p K«i k Kite. <**»., Inc.
     Omral I'.iMrr & UK In Conipaay
     City ..I Aiitlin
     Ctily I'.iMtc .'y-rvirr Board (San' Antonio)
     rVilrttun, City trf
     (i.m.,ni l.r (>Hmtv f>c. (*x,p. Asv>c.
     < Jiimnumty I'ulilic, St-rvN'r (*jmp*uy
     Cftrtliyl.Ml, (.Jty ol
     Kaufman (>«unty Kleetrir Conp.. lor-
     Kitnlilr Klrriric Coop.,  lor.
     I-aGranirr. Cily ol
     ljunar (.4>uniy.r.kt.trie  Coop, Aon.
     I Jmniunr County Klec. Coop., lac.
     IJvinir«t«in, (Uty of
     l.uck.hart L>tilhirt
     Lower Colundo Kivrr Ambority
     Lulin^ L'lititin
     Ma«k Vilify Kin-trie Coop., loc.
     McC JiUoch Elcciric Coop.. Inc.
     McUrtnan County FJrctrk Cuop.. like.
     Mrtlina Klcrtrk Cuop.,  loc.
     Mid.S.iuih FUxirtr Coop. Asm.
     MidVnt Klectrk C*wp., Inc.
     N*v*rro County Llrctfk Coop.. Inc.
     Nrw BraunCrli  ClUiltn
     New  Era Electric Coop., Inc.
     Nuece* Electric Coop.. Inc.
     Kobrnioii rJn-tric Coup., loc.
     Kobtlown, City of
     Sam  Houston tlectiic Coop^ Inc.
     San Bernard Uectric Coop^ Inc.

Wntnn SjtUmi CMr^inatimf  Owm/ ( tt'SCC)
    Arizona Power Authority
    Arizona Publk Service. Co.
    BonnevUle Power Adminiitration
    Briihh ColumUa Hydro &  Power Authority
 '   Cjlifninia Dept. of W.iter Knourcei
    Central Telephone &  Utilitiei {South Colorado 'Row
      hiviiion)
    Chelan County  P.U.I). No. I
    Gty of Clrndale. Pulilk Servire Drpt.
    f4iy of'l'acuma, l>«-[ii. Public Uiililin
    C.ty of Scsuk IVpl. ••( l.iRhiinK
     Otwliti fijunty P.U.I). No. I
    Colorado— Ute  Klrrtrir.  Anncialiun, Inc.
    l)u.»Klai fVwnty P.l',1).  No. 1
    I'.l I'M Urririr (x»ti|tany
    Kiyrni- Water ft Untric Board
    Gi>f:< (vMimy P (J.I). No. '2
    l I'nwrr f ^ifnp^ny
    Ixn Anyflrt lV|iartiiiriil ij Wjirr ft  Power
           a To
Inwa PuMir Srrvkr O-o,'
Iowa SiMtll^-tn 1,'ltlitlrl Co.*
M«ilrir Co.
Northern Kiatn Power Co.*
llninn Unttir fltimpaiiy
Up|KT Prninitila Ptiwrr Co.
WiviMttin l.lertiK. Powrr f^N
WiM-iinon.MM ltif«n  Power O
Wiwcni.n Power and 1J«M Cumpa«y
WMcoruin PuUk .Service tp.
Cuero MltrtiM; IVpt.
Djill.it Powrr ft  l.iKhi Company
IVrp l.jfl 'let.t« Mrr. (k»ip.. Inc.
Srlnik nbunr. City of
S.-nu.n. . Ji Klrc. Coup.. Inc.
Soutliwrii Trim tire. Coop.. Inc.
Stamford Klt-ctnc Cuup., Inc.
Traffur, Ctt> jny
PariftcCuft Klrrtfirt^.
Pacific Power &  l.iKlit (Jtnipan
Portland Grnrral t.l..ir>. *rp>t.f l.nKM>'inRion XVjfrr l'.,»r, C^m
Writ  KiMitraay Powei &  l.ntlil
                                                          Wnl Peon I'owrr O
                                                                                 hi.ll .. rr(x,,
                                                                                  of MAIN l
                                                                              l«-r o( M'P.
                                                                              i^r 
-------
 Multiply (English Units)

        English Unit
      CONVERSION FACTORS
                   by

Abbreviation   Conversion
                               Abbreviation
Obtain (Metric Units)

     Metric Unit
acres
acre-feet
British Thermal Unit
British Thermal Unit/pound
cubic feet/minute
cubic feet/second
cubic feet
cubic feet
cubic inches
degree Fahrenheit

feet
gallon
gallon/minute
horsepower
inches
inches of mercury
pounds
million gallons/day
mile
pound/square inch (guage)

square feet
square inches
tons (short)
yard
ac
ac ft
Btu
Btu/lb
cfm
cfs
cu ft
cu ft
cu in
°F

ft
gal
gpm
hp
in
0.03342
Ib
mgd
mi
psig

sq ft
sq in
t
y
0.405
1233.5
0.252
0.555
0.028
1.7
0.028
28.32
16.39
0.555(a)
CF-32)
0.3048
3.785
0.0631
0.7457
2.54
atm
0.454
3,785
1.609
(0.06805(a)
psig +1)
0.0929
6.452
0.907
0.9144
ha
cu m
kg cal
kg cal/kkg
cu m/min
cu m/min
cu m
1
cu cm
°C

m
1
I/sec
kw
cm
atmospheres
kg
cu m/day
km
atm

sq m
sq cm
kkg
m
hectares
cubic meters
kilogram-calories
kilogram-calories/kilogram
cubic meters /minute
cubic meters /minute
cubic meters
liters
cubic centimeters
degree Centigrade

meters
liters
liters/second
kilowatts
centimeters

kilograms
cubic meters/day
kilometer
atmospheres (absolute)

square meters
square centimeters
metric tons (1000 kilograms)
meters
(a)  Actual conversion,  not a multiplier

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