DEVELOPMENT DOCUMENT FOR
PROPOSED EFFLUENT LIMITATIONS GUIDELINES
AND NEW  SOURCE PERFORMANCE STANDARDS
                 FOR THE
STEAM ELECTRIC POWER GENERATING
            POINT SOURCE CATEGORY

                 ^ PRO^

       UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
                 MARCH 1974

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                            Publication Notice

This is a development document for proposed effluent limitations
guidelines and new source performance standards.  As such, this report
is subject to changes resulting from comments received during the period
of public comments of the proposed regulations.   This document in its
final form ;will be published at the time the regulations for this
industry are promulgated.

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                  DEVELOPMENT DOCUMENT

                          for

        PROPOSED EFFLUENT LIMITATIONS GUIDELINES

                          and

            NEW SOURCE PERFORMANCE STANDARDS

                        for the
            STEAM ELECTRIC POWER GENERATING
                 POINT SOURCE CATEGORY
                    Russell E. Train
                     Ad mi ni st r ator

                     Roger Strelow
Acting Assistant Administrator for Air 6 Water Programs
                   Allen Cywin, P.E.
         Director, Effluent Guidelines Division

              Dr. Charles R. Nichols, P.E.
                    Project Officer
                      March, 197U

              Effluent Guidelines Division
            Office of Air and Water Programs
            S. Environmental Protection Agency
                Washington, D. C.  20460

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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 304, 306 and 307 of the Federal Water
Pollution Control Act Amendments of 1972.

Effluent limitation 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  "test  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  proposed  effluent  limitations
guidelines and standards of performance are contained herein.
                                   iii

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                                CONTENTS


Part       Section                                                Page

              I    CONCLUSIONS                                      1

              II   RECOMMENDATIONS                                  3

              III  INTRODUCTION                                     7

                   General Background                               7
                   Purpose and Authority                            8
                   Scope of Work and Technical Approach             9
                   Industry Description                            12
                   Process Description                             21
                   Alternate Processes                             23
                   Industry Regulation                             31
                   Construction Schedules                          32

              IV   INDUSTRY CATEGORIZATION                         35

                   Process Considerations                          35
                   Raw Materials                                   43
                   Information on U.S. Generating Facilities       46
                   Site Characteristics                            53
                   Mode of Operation  (Utilization)                 58
                   Categorization                                  68
                   Summary                                         75

A                  Chemical Wastes                                 81

              V    WASTE CHARACTERIZATION                          81

                   Introduction                                    81
                   Once-through Cooling Systems                    87
                   Recirculating Systems                           88
                   Water Treatment                                 93
                   Boiler or PWR Steam Generator Blowdown         105
                   Equipment Cleaning                             107
                   Ash Handling                                   116
                   Coalpile Drainage                              128
                   Floor and Yard Drains                          131
                   Air Pollution Control                          133
                   Miscellaneous Waste Streams                    134
                   Low Level Rad Wastes                           138
                   Summary of Chemical Wastes                     144
                   Classification of Waste Water Sources          144

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                                CONTENTS  (Continued)


Part       Section                                                   Page
              VI   SELECTION OF  POLLUTANT  PARAMETERS
                                                                     147
                   Definition of Pollutants                           147
                   Introduction                                       147
                   Common Pollutants                                  147
                   Pollutants from Specific Waste Streams             150
                   Other Potentially Significant Pollutants           155
                   Selection of Pollutant Parameters                  156

              VII  CONTROL AND TREATMENT TECHNOLOGY                   161

                   Introduction                                       161
                   Continuous Wastes                                  162
                   Periodic Wastes                                    173
                   Miscellaneous Wastes                               174
                   Pollutant-Specific Treatment Technology            192
                   Combined Chemical Treatment                        202
                   Other Processes                                    212
                   Powerplant Wastewater Treatment Systems            213
                   Wastewater Management                              215
                   Summary                                            221

              VIII COST, ENERGY AND NON-WATER QUALITY ASPECT          229

                   Introduction                                       229
                   Wastes Not Treated at Central Treatment Plant     230
                   Complete Treatment of Chemical Wastes  for  Re-use  238
                   Energy Requirements                                244
                   Ultimate Disposal of Brines and Sludges            245

         IX,X,XI   BEST PRACTICABLE CONTROL TECHNOLOGY  CURRENTLY     247
                     AVAILABLE, GUIDELINES AND LIMITATIONS
                   BEST AVAILABLE TECHNOLOGY ECONOMICALLY
                     ACHIEVABLE, GUIDELINES AND LIMITATIONS
                   NEW SOURCE PERFORMANCE STANDARDS AND
                     PRETREATMENT STANDARDS

                   Best Practicable Control Technology                247
                     Currently Available
                   Best Available Technology Economically            250
                     Achievable
                   New Source Standards                               251
                   Cost of Technology                                 251
                   Energy and Non-Water Quality Environmental        253
                     Impacts
                                    vi

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                    CONTENTS  (Continued)


Section                                                Page

         Thermal Discharges                             £55

    V    WASTE CHARACTERIZATION                         255

         General                                        255
         Quantification of Main Condenser               255
           Cooling Characteristics
         Effluent Heat Characteristics from Systems     269
           Other Than Main Condenser Cooling Water

    VI    SELECTION OF POLLUTANT PARAMETERS              275

    VII   CONTROL AND TREATMENT TECHNOLOGY               277

         Introduction                                   277
         Process Change                                 279
         Waste Heat Utilization                         308
         Cooling Water Treatment                        313
              General                                   313
              Once-through (Nonrecirculating Systems)   314
              Once-through Systems with Supplemental    315
                Heat Removal (Helper Systems)
              Closed or Recirculating Systems           322
                Cooling Ponds                           323
                Spray Ponds                             333
                Wet-Type Cooling Towers                 341
                Dry-Type Cooling Towers                 364
              Survey of Existing Cooling Water Systems  372

    VIII  COST, ENERGY AND NON-WATER QUALITY ASPECT      381

         Cost and Energy                                381
              Cost Data                                 385
              Costs Analysis                            388
              Energy (Fuel)  Requirements                404
              Loss of Generating Capacity               407
         Non-Water Quality Environmental Impact         410
           of Control and Treatment Technology
              General                                   410
              Drift                                     418
              Fogging                                   424
              Noise                                     432
              Height                                    433
              Consumptive Water Use                     434
              Pollutants in Blowdown                    439
              Aesthetic Appearance                      440
              Icing Control                             442
         Comparison of Control Technologies             443
         Considerations of Section 316(a)               443
                         vii

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                                CONTENTS  (Continued)
Part       Section


         IX,X,XI   BEST PRACTICABLE CONTROL TECHNOLOGY  CURRENTLY  453
                     AVAILABLE, GUIDELINES AND LIMITATIONS
                   BEST AVAILABLE TECHNOLOGY ECONOMICALLY
                     ACHIEVABLE, GUIDELINES AND LIMITATIONS
                   NEW SOURCE  PERFORMANCE STANDARDS AND
                     PRETREATMENT STANDARDS

                                                                   453
                   Categorization                                  ,,-c
                   Waste Characteristics
                   Control and Treatment Technology
                   Cost of Technology
                   Energy and Other Non-Water Quality
                     Environmental Impacts

              XII  ACKNOWLEDGEMENTS

              XIII REFERENCES                                      469

              XIV  GLOSSARY                                        503

Appendix 1    Industry Inventory                                  Al-1

Appendix 2    Plant Data Sheets                                   A2-1

Appendix 3    40 CFR Part 423 Effluent Limitations                A3-1
              Guidelines for Existing Sources and Standards
              of Performance and Pretreatment Standards
              for New Sources for the Steam Electric Power
              Generating Category  (as published in proposed
              form in the Federal Register on March 4,  1974).
                                     vm

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                                FIGURES

Number                title

III-1     Projected Total U.S. Energy Flow                 19
          Pattern  (1980)

III-2     Condensed Construction Schedule,                 33
          200 MW Oil-Fired Unit

III-3     Typical LWR Nuclear Plant Project                34
          Schedule, Highlights Only

IV-1      Schematic Flow Diagram, Typical Steam            36
          Electric Generating Plant

IV-2      Schematic Cooling Water Circuit                  42

IV-3      Cumulative Frequency Distribution of Entire      48
'         Powerplant Inventory for All EPA Regions

IV-4      Cumulative Frequency Distribution of Fossil-     49
          Steam Powerplants for All EPA Regions

IV-5      Cumulative Frequency Distribution of Nuclear-    50
          Steam Powerplants for All EPA Regions

IV-6      Largest Fossil-Fueled Steam Electric             52
          Turbine-Generators in Service  (1900-1990)

IV-7      Heat Rates of Fossil-Fueled Steam                54
          Electric Plants

IV-8      Heat Rate vs Unit Capacity                       55

IV-9      Heat Rate vs Unit Age                            56

A-V-1     Typical Flow Diagram, Steam Electric             82
          Powerplant  (Fossil-Fueled)

A-V-2     Simplified Water System Flow Diagram             83
          for a Nuclear Unit

A-V-3     Nomogram to Determine Langelier                  91
          Saturation Index

A-V-4     Clarifier                                        94

A-V-5     Filter                                           94
                                   IX

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                           FIGURES  (continued)

Number                 Title                              Pa?e


A-V-6     Ion Exchange Process, Cationic  and               96
          Anionic Type

A-V-7     Ion Exchange Process, Mixed  Resin Type           98

A-V-8     Evaporation  Process                             101

A-V-9     Typical Ash  Pond                               118

A-V-10    Flow Diagram -  Air Pollution Control            135
          Scrubbing  Device at  Plant  4216

A-V-11    Liquid Radioactive Waste Handling               141
          System PWR Nuclear Plants

A-V-12    Liquid Radioactive Waste Handling System       143
          1100 MW BWR  Nuclear  Plant

A-VII-1   Chlorine Feed Control, Once-Through             164
          Condenser  Cooling Water

A-VII-2   Recirculating condenser Cooling                168
          System, pH Control of Slowdown

A-VII-3   Clarification Waste  Treatment Process          169

A-VTI-U   Ion Exchange Waste Treatment Process            171

A-VII-5   Neutralization  Pond                             172

A-VII-6   Ash Sedimentation System  - Plant No.  5305      178

A-VII-7   Ash Handling System  - Plant No. 3626            179

A-VII-8   Ash Handling System, Oil  Fuel Plant             180
          - Plant No.  2512

A-VII-9   Cost of Neutralization Chemicals               183

A-VII-10  Comparison of Lime,  Limestone,  and              184
          Soda Ash Reactivities

A-VII-11  Comparison of Settling Rate                    185

A-VII-12  Coal Pile  -  Plant No.  5305                     186

A-VII-13  Cylindrical  Air Flotation  Unit                  188

A-VII-14  Typical A.F.I.  Oil-Water  Separator             188

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                           FIGURES  (continued)

Number                 Title                               Page


A-VII-15  Oil Separator and Air Flotation Unit             189
          - Plant No.  0610

A-VII-16  Corrugated Plate Type Oil Water                  190
          Separator

A-VII-17  oil Water Separator                              191

A-VII-18  Effect of pH on  Phosphorus Concentration         198
          of Effluent  from Filters Following Lime
          Clarifier

A-VII-19  Solubility cf Copper, Nickel, Chromium,          203
          and Zinc as  a Function of pH

A-VII-20  Theoretical  Solubilities of Metal Ions           204
          as a Function of pH

A-VII-21  Experimental Values - Solubility of              205
          Metal Ions as a  Function of pH

A-VII-22  Experimentally Determined Solubilities           206
          of Metal Ions as a Function of pH

A-VII-23  Change in the Solubilities of Zinc,              207
          Cadmium, Copper, and Nickel
          Precipitates (Produced with Lime
          Additions) as a  Function of Standing
          Time and pH  Value

A-VII-24  Sewage and Kaste Water Disposal for a            216
          Typical Coal-Fired Unit, 600 MW

A-VII-25  Recycle of Sewage and Waste Water for a          217
          Typical Coal-Fired Unit, 600 MW

A-VII-26  Recycle Water System, Plant No. 2750             218

A-VIII-1  Chemical Wastes, Central Treatment Plant         231

A-VIII-2  Cost for Coal Pile Run-off Collection            237

A-VIII-3  100 MW Coal-Fired Steam Electric                 239
          Powerplant,  Recycle and Reuse of
          Chemical Wastes

A-VIII-4  100 MW Oil-Fired Steam Electric                  240
        -  Powerplant,  Recycle and Reuse of
          Chemical Wastes
                                    xi

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Number
    FIGURES  (continued)



Title
                                                          Page
B-V-1
B-V-2
B-V-3
B-V-4
B-V-5
B-V-6
B-V-7
B-V-8
B-V-9
B-V-10
B-VII-1
B-VII-2
B-VII-3
B-VII-4
B-VII-5
B-VII-6
B-VII-7
B-VII-8
B-VII-9
B-VII-10
B-VII-11
B-VII-12
B-VII-13
B-VII-14
Unit Condenser Delta (T)
Unit Heat Rate Distribution
Maximum Summer Outfall Temperature
Delta (T) vs Unit Age
Base Unit Heat Rates
Cycling Unit Heat Rates
Peaking Unit Heat Rates
Base Unit Condenser Delta (T)
Cycling Unit Condenser Delta (T)
Peaking Unit Condenser Delta (T)
Energy Flow for a Power plant
Energy Balance for a Powerplant
Powerplant Violating Second Law
Powerplant Violating First Law
Powerplant Conforming to First
and Second Law
Carnot Cycle Steam Powerplant
Rankine Cycle Powerplant
Rankine Cycle with Superheat
Powerplant
Regenerative Cycle Powerplant
Reheat Cycle Powerplant
Drain Cooler Addition to Powerplant
Drains Pumped Forward in Powerplant
Superposed Plant Addition
Simple Brayton Cycle Gas Turbine
256
257
260
264
266
267
268
270
271
272
281
281
283
283
284
287
290
291
292
294
299
300
301
303
           Powerplant
                                    xii

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                          FIGURES  (continued)

Number                Title
B-VII-15  Brayton Cycle with Regenerator Gas              304
          Turbine Powerplant

B-VII-16  Combined Gas-Steam Powerplant                   306

B-VII-17  Once-Through  (Open) Circulating                 316
          Water System

B-VII-18  Once-Through  (Open) System with                 317
          Helper Cooling System Installed

B-VII-19  Cooling System Capable of Both                  319
          Open and Closed Mode Operation

B-VII-20  Plant Layout at Plant No. 2119                  320

B-VII-21  Seasonal Variation of Helper Cooling            321
          Tower

B-VII-22  Cooling Canal - Plant No. 1209                  325

B-VII-23  Chart for Estimating Cooling Pond               328
          Surface Heat Exchange Coefficient

B-VII-24  Cooling Pond Surface Area vs Heat               330
          Exchange Coefficient

B-VII-25  Determination of Surface Temperature            331
          Increase Resulting From Thermal
          Discharge of Station

B-VII-26  Determination of Average Surface                332
          Temperature Increase Resulting
          From Thermal Discharge of Station

B-VII-27  Estimation of Capital Cost of                   334
          Cooling Pond

B-VII-28  Unitized Spray Module                           335

B-VII-29  Four Spray Module                               336

B-VII-30  Spray Canal - Plant No. 0610                    338

B-VII-31  Spray Modules - Plant No. 0610                  339

B-VII-32  Graphic Representation of Design                340
          of Spray Augmented Cooling Pond

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                          FIGURES  (continued)

Number                Title                               Page

B-VII-33  Thermal Rotcr System                             342

B-VII-34  Double Spray Fixed Thermal Rotor                 343

B-VII-35  Graphic Representation of Preliminary            344
          Cost Data on Rotating Disc Device

B-VII-36  Determination of Required Flow per               345
          Disc for Rotating Disc Device

B-VII-37  Counterflow Mechanical Draft Tower               346

B-VII-38  Crossflow Mechanical Draft Tower                 346

B-VI1-39  Crossflow Natural Draft  Tower                    348

B-VII-40  Counterflow Natural Draft Cooling                348
          Tower

B-VTI-41  Typical chart  for Determining                    352
          Rating Factor

B-VII-42  Cost Vs Rating  Factor,                           353
          Mechanical Draft Tower

B-VII-43  Cooling Tower  Performance Curves                 354

B-VII-44  Comparison of  K-Factor and Rating                355
          Factor for the  Performance of
          Mechanical Draft Cooling Towers

B-VII-45  Graph Showing  Variation  of Cost  of               356
          Mechanical Eraft Cooling Towers
          with Water Flow

B-VII-46  Mechanical Forced  Draft  Cooling                  359

B-VII-47  Parallel Path  Wet-Dry Cooling                    359
          Tower Psychometrics

B-VII-48  Parallel Path  Wet-Dry Cooling                    361
          Tower for  Plume Abatement

B-VII-49  Parallel Path  Wet-Dry Cooling                    362
          Tower  (Enlarged Dry  Section)

B-VII-50  Typical Natural Draft Cooling                    353
          Towers  - Plant No.  4217
                                   xiv

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                          FIGURES  (continued)

Number                Title                              Page

B-VII-51  Hyperbolic Natural Draft Crossflow             365

          Cooling  Towers, Typical  Cost
          Performance Curves  for Budget
          Estimates

B-VII-52  Hyperbolic Natural  Draft Crossflow             366
          Cooling  Towers, Typical  Cost
          Performance Curves  ror auage-c
          Estimates

B-VII-53  Fan-Assisted  Natural  Draft Cooling             367
          Tower

B-VII-54  Direct,  Dry-Type Cooling Tower                 369
          Condensing  System With Mechanical
          Draft  Tower

B-VII-55  Indirect, Dry-Type  cooling Tower               370
          Condensing  System With Natural-
          Draft  Tower

B-VII-56  Temperature Diagram of Indirect Dry            370
          Cooling  Tower Heat-Transfer System

B-VII-57  Representative Cost of Heat Removal            373
          With Dry Tower Systems for Nuclear
          Plants

B-VTI-58  Steam  Type  Direct Contact  Condenser            374

B-VII-59  Effect of Turbine Exhaust  Pressure on          375
          Fuel Consumption and  Power Output

B-VIII-1a Example  of  Optimization  of Net Unit            384
          Power  Output  by Reduction  of Cooling
          Tower  Fans

B-VIII-1  Additional  Generating Costs for                 401
          Mechanical  Draft Towers, Base-Load
          Dnit,  300 MW, 6 Year  Remaining Life

B-VIII-2  Additional  Generating Costs for                 401
          Mechanical  Draft Towers, Base-Load
          Unit,  300 MW, 18 Year Remaining Life

B-VIII-3  Additional  Generating Costs for                 401
          Mechanical  Draft Towers, Base-Load
          Unit,  300 MW, 30 Year Remaining Life
                                    xv

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                          FIGURES  (continued)

Number                Title                               Page

B-VIII-4  Additional Generating Costs for                 401
          Mechanical Craft Towers, Base-Load
          Unit, 300 MW,  18 Year Remaining Life

B-VIII-5  Additional Generating Costs for                 401
          Mechanical Draft Towers, Base-Load
          Unit, 300 MW,  30 Year Remaining Life

B-VIII-6  Additional Generating Costs for                 403
          300 MW Cyclic Unit, Mechanical
          Draft Towers,  6 Year Remaining Life

B-VIII-7  Additional Generating Costs for                 403
          300 MW Cyclic Unit, Mechanical
          Draft Towers,  18 Year Remaining Life

B-VIII-8  Additional Generating Costs for                 403
          300 MW Cyclic Unit, Mechanical
          Draft Towers,  30 Year Remaining Life

B-VIII-9  Additional Generating Costs for                 403
          300 MW Peaking Unit, Mechanical
          Draft Towers, 6 Year Remaining Life

B=VIII-10 Additional Generating Costs for                 403
          300 MW Peaking Unit, Mechanical
          Draft Towers, 18 Year Remaining Life

B-VIII-11 Additional Generating Costs for                 403
          300 MW Peaking Unit, Mechanical
          Draft Towers, 30 Year Remaining Life

B-VIII-12 Variation of Additional Generation              405
          Cost with Capacity Factor

B-VIII-13 Additional Generating Costs for 800 MW          406
          Nuclear  Unit, Mechanical
          Draft Cooling Towers, 18 Year
          Remaining Life

B-VIII-14 Additional Generating Costs for 800 MW          406
          Nuclear  Unit, Mechanical
          Draft Cooling Towers, 30 Year
          Remaining Life

B-VIII-15 Turbine  Exhaust Pressure Correction             408
          Factors  (Example,  Plant No. 3713)
                                   xv i

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                          FIGURES  (continued)

Number                Title                              Page


B-vm-16 Broadside Multiple Tower Orientation           414

B-VIIl-17 Longitudinal Multiple Tower Orientation

B-VIIl-18 Ground-Level Salt Deposition Rate from         423
          a Natural-Draft Tower as a Function of
          the Distance Downwind: A Comparison
          Between Various Prediction Methods

B-VIII-19 Modified Psychrometric Chart                   425

B-VIII-20 Graphical Distribution of Potential            427
          Adverse Effects From Cooling Towers
          Based on Fog, Low-Level Inversion and
          Low Mixing Depth Frequency

B-VIII-21 Location of Natural Draft Cooling              429
          Towers Through 1977

B-VIII-22 Heat Transfer Mechanisms With                  435
          Alternative Cooling Systems

B-VIII-23 Water Consumption Versus                        438
          Meteorology and Cooling Range

B-VIII-2U Estimated U.S. Energy Situation  (1980)          450
          Relevant to Environmentally-Based Control
          of Thermal Discharge from Steam Electric
          Powerpiants
                                   xvn

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                                 TABLES

 Number                     Title                        Page

II-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            14
          Generating Industry (Year 1970)

III-3     Projected Growth of Utility Electric            16
          Generating Capacity

III-4     FPC Projection of Fuel Use                      17
          in Steam Electric Powerplants

III-5     FPC Projected Annual Fuel Requirements          18
          for Steam Electric Powerplants

IV-1      Industry Inventory Summary                      47

IV-2      Urban Steam Electric Powerplants                57

IV-3      Characteristics of Units Based on               65
          Annual Hours of Operation

IV-4      Chemical Waste Categories                       70

IV-5      Applicability of Chemical Waste                 72
          Categories ty Fuel Type

IV-6      General Subcategorization Rationale             76

IV-7      Subcategorization Rationale for Heat            77

IV-8      Subcategorization Rationale for Pollutants      78
          Other Than Heat

A-V-1     Recirculating Water Quality Limitations         90

A-V-2     Typical Water Treatment Waste  Water Flows       1Q2

A-V-3     Arithmetic Mean and Deviation  of                104
          Selected Water Treatment Waste Para-
          meters
                                   XVT11

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                          TABLES  (continued)

Number                Title                              Page

A-V-I+     chemical Waste characterization,                llOff.
          Boiler Tubes' Cleaning

A-V-5     Chemical Waste Characterization,                115
          Air Preheater Cleaning, Boiler
          Fireside Cleaning

A-V-6     Constituents cf Coal Ash                        119

A-V-7     Time  of Flow for Ash Handling Systems           120

A-V-8     Chemical Waste Characterization,                122ff.
          Ash Pond Overflow  - Net Discharge

A-V-9     Coal  Pile  Drainage                             129

A-V-10    Chemical Waste Characterization                132
          Coal  Pile  Drainage

A-V-11    Chemicals  Used in  Steam Electric Powerplants    145

A-V-12    Class of Various Waste  Water Sources            146

A-VI-1    Applicability of Parameters to  Chem-            148
          ical  Waste Streams

A-VI-2    Chemical Wastes -  Number  of Plants              149
          with  Recorded Data

A-VI-3    Selection  of Pollutant  Parameters               157ff.

A-VI-4    Selected Pollutant Parameters                   160

A-VII-1   Ash Pond Performance                            175

A-VII-2   Summary of EPA Data Verifying                   177
          Ash Pond Performance, Plant No. 0107

A-VII-3   Ash Pond Effluent  Total                        201
          Suspended  Solids

A-VII-4   Comparison of Alkaline  Agents                  209
          for Chemical Treatment

A-VII-5   Chemical Wastes -  Control and                  222ff.
          Treatment  Technology

A-VII-6   Flow  Rates - Chemical Wastes                   224
                                    xix

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                          TABLES  (continued)

Number                Title                               Page

A-VII-7   Costs/Effluent Reduction Benefits,               225
          Control and Treatment Technology for
          Pollutants Other Than Heat, High
          Volume Waste Streams

A-VII-8   Costs/Effluent Reduction Benefits,               226
          Control and Treatment Technology for
          Pollutants Other Than Heat,
          Intermediate Volume Waste Streams

A-Vll-9   Costs/Effluent Reduction Benefits,              227
          Control and Treatment Technology for
          Pollutants Other Than Heat,
          Low Volume ftaste Streams

A-VII-10  Costs/Effluent Reduction Benefits,              228
          Control and Treatment Technology for
          Pollutants Other Than Heat,
          Rainfall Runoff Waste Streams

A-VIII-1  Design Flow for Chemical Wastes                 232
          Treatment Plant

A-VIII-2  Estimated Capital Costs, Chemical               233
          Wastes Treatment Plant

A-VIII-3  Estimated Annual Operating Costs,               234
          Chemical Wastes Treatment Plant

A-VIII-4  Estimated Annual and Unit Costs,                235
          Chemical Wastes Treatment Plant

A-VIII-5  Estimated Capital Costs, Treatment              241
          of Chemical Wastes

A-VIII-6  Estimated Annual Operating Costs,               242
          Treatment of Chemical Wastes  for
          Reuse

A-VIII-7  Estimated Annual and Unit Costs,                243
          Treatment of Chemical Wastes  for
          Reuse

B-V-1     Efficiencies,  Heat  Rates, and Heat              259
          Rejected by Cooling Water

B-V-2     Plant Visit Thermal Data                         261

B-V-3     Typical Characteristics of Waste
          Heat Rejection                                  273
                                   xx

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                          TABLES (continued)

Number                Title                              Page

B-V-U     Total Plant Thermal Discharges                  274

B-VII-1   Efficiency Improvements                         297

B-VII-2   Energy Demand by Heat Using                     312
          Applications  (1970)

B-VII-3   Uses of Various Types of                        376
          Cooling Systems

B-VII-4   Extent to Which Steam Electric                  377
          Powerplarits are Already committed
          to the Application of Thermal
          Control Technologies

B-VII-5   Cooling Water Systems Data, Plants              378
          Visited

B-VIII-1  Cooling Water Systems - Cost Data,              386
          Plants Visited

B-VIII-2  Cost of Cooling System Equipment                390

B-VIII-3  Hypothetical  Plant Operating Parameters         392

B-VIII-U  Revised Plant Operation Parameters              392

B-VIII-5  Typical Plant Characteristics                   394

B-VIII-6  Assumed Increase in Heat Rate Compared
          to Base Heat  Rate as a Function of the          397
          Turbine Exhaust Pressure

B-VIII-7  Cost Assumptions                                398

B-VIII-8  Cooling Tower Economic Analysis                 400

B-VIII-9  Energy  (Fuel) Consumption Penalty               409
          Due to Increased Turbine Backpressure
          from Closed-Cycle Cooling System

B-VIII-10 Effluent Heat, Applicability of                 412
          Control and Treatment Technology

B-VIII-11 Solids in Drift From Cooling Towers             420

B-VIII-12 Factors Affecting Dispersion and
          Deposition of Drift from Natural-Draft          422
          and Mechanical-Draft Cooling Towers
                                    xxi

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                          TABLES  (continued)

Number                Title
                                                         Page
B-VIII-13 Energy Production of Some Natural               431
          and Artificial Processes at Various
          Scales

B-VIII-1U Evaporation Rates for Various Cooling Systems   436

B-VIII-15 Comparative Utilization of Natural              437
          Resources With Alternative Cooling
          Systems for Fossil-Fuel Plant with
          680 MW Net Plant Output

B-VTII-16 Control and Treatment Technologies              444
          for Heat: Ccsts, Effluent Reduction
          Benefits, and Non-Water Quality
          Environmental Impacts

B-VIII-17 Incremental Cost of Application of              445
          Mechanical Eraft Evaporative Cooling
          Towers to Nonnew Units  (Basis 1970 Dollars)

B-VIII-18 Incremental Cost of Application of              446
          Mechanical Eraft Evaporative Cooling
          Towers to New Units  (Basis 1970 Dollars)

B-VIII-19 Timing for Cases Leading to Significant         448
          Thermal Controls by July 1, 1977

B-VIII-20 Estimated Number of Units Requiring             449
          Thermal Controls Based on Environmental Need

B-VIII-21 Incremental Oil Consumption If All              451
          Environmentally-Based Thermal Controls
          Are Added by July  1, 1977
                                   xxii

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                               SECTION I

                              CONCLUSIONS


For the purpose of  establishing  effluent  limitations  guidelines  and
standards  of  performance  for  steam electric powerpiants, 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.

Informal categories for establishing  guidelines  for  pollutants  other
than  heat   (chemical-type wastes) have 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.  Categories for 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.

Informal  categories  for  guidelines   for   effluent   heat   (thermal
discharges)   include  a  basic  division  of  the  industry by degree of
utilization into  base-load,  cycling  and  peaking  units.   Additional
subcategorizations are based on 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  ard 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 by no discharge of pollutants, other than from  cooling  water
systems,  storm  water  run-off,  sanitary  waste systems, and low-level
radwaste systems.  No discharge is achievable through the application of
an integrated system of water management which provides for the multiple
re-use of water in uses  having  descendingly  stringent  water  quality
requirements.  Standards of performance for new sources will provide for

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essentially   the   same  effluent  levels  as  best  practical  control
technology currently available to due the immediate technical  risks  of
applying best available technology.

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  practicable  control
technology currently available, best available  technology  economically
achievable, and new source performance standards consist 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/or 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
301, 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  guidelines.   However,  the
designation of specific technology as "best practicable and  standards",
etc.,  does not mean that it alone must be utilized to meet the effluent
limitations.  Any technology capable of meeting the  guidelines  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-l

                              SUMMARY EFFLUENT LIMITATIONS GUIDELINES AND STANDARDS FOR POLLUTANTS OTHER THAN HEAT
SOURCE
Nonre circulating cooling water systems


Recirculating cooling water systems








Nonrecirculating ash sluicing systems


Nonrecirculating wet-scrubber air
pollution control systems

Low-volume waste sources taken
collectively , as if from one source




Rainfall runoff taken collectively.
as if from one source

Sanitary wastes
Radwastes
Clarification water treatment
Softening water treatment
Transformers
Intake screens
Recirculating ash sluicing systems for
flv ash or oil bottom ash
POLLUTANTS
Chemical additives (biocides)
Chlorine-free available
Chlorine-total residual
Chemical additives (corrosion inhibitors)
Chlorine- free available
Chlorine-total residual
Chr omi urn- 1 ot a 1
Oil and grease
pH value
Total phosphorus (as P)
Total suspended (nonf ilterable) solids
Zinc-total
Oil and grease
pH value
Total suspended (nonf ilterable) solids
Oil and grease
pH value
Total suspended (nonf ilterable) solids

Copper-total
Iron-total
Oil and grease
pH value
Total suspended (nonf ilterable) solids
Oil and grease
pH value
Total suspended (nonf ilterable) solids
All pollutants
All pollutants
All pollutants
All pollutants
Polychlorinated biphenyls
Debris
All pollutants

EFFLUENT LIMITATIONS*
BPCTCA (1977)
No limitation
0.2 (0.5 max)*-*
No limitation
No limitation
0.2 (0.5 max)**
No limitation
No limitation
10
600 to 9oO
No limitation
15 (100 max)***
No limitation
10
600 to 9.0
15 (100 max)***
10
600 to 9.0
15 (100 max)***

1
1 it[i[t
10 (20 max)***
600 to 9.0
15 (100 max)
10 (20 max)**
6.0 to 9.0
15 {100 max) **
Municipal stds .
No limitation
No discharge
No discharge
No discharge
No discharge
_

BATEA (1983)
No limitation
002 (005 max)**
No limitation
No limitation
No limitation
No discharge
002
10
6.0 to 9.0
' 5
15 (100 max)
1
No discharge
-
No discharge
No discharge
-
No discharge
No discharge
No discharge
No discharge
No discharge
-
No discharge
10 (20 max) +
6.0 to 9.0
15 (100 max)4"
Municipal stds .
No limitation
No discharge
No discharge
No discharge
No discharge
_

New Sources
j±
Approx. no discharge,.
Approx. no discharge*.
Approx. no discharge
No discharge
0.2 (0.5 max)***
No limitation
No discharge
10
600 to 9oO
No discharge
15 (100 max)***
No discharge
No discharge
-
No discharge
10
6.0 to 900
15 (100 max)

1
1
10 (20 max)***
6.0 to 9.0
15 (100 max)
10 (20 max)**
6.0 to 9,0
15 (100 max) **
Municipal stds.
No limitation
No discharge
No discharge
No discharge
No discharge
No discharge

   *  Note:  Numbers  are concentrations,  mg/1,  except  for pH values. Effluent limitations, except where otherwise indicated, are monthly  averages of daily
           amounts,  mg,  to be  determined  by the  concentration  shown  and the flow of waste water from the source in question.  In  some  cases there are lim-
           itations  shown  on the maximum  amount  for  any day. Where waste waters from one source with effluent limitations for a  particular pollutant are
           combined  with other waste waters,  the effluent limitation, mg (or mg/1), for the particular pollutant, excluding pH,  for the combined stream
           shall be  the  sum of the effluent limitations (for concentration limits apply appropriate dilution factors) for each of the streams which contri-
           bute to the combined stream  except that the actual  amount, mg (or mg/1), of the pollutant in a contributing  stream will be used in place  of the
           effluent  limitation for those  contributing streams where the actual amount, mg (or mg/1), of the pollutant is less than the  effluent limitation,
          mg  (or mg/1), for the contributing stream. The pH value should be in the range given at all times.

  **  Note:  Effluent  limitations are average concentrations during a maximum of one 2-hour period a day and maximum concentrations at  any time. No more than
           one unit  at a plant may be chlorinated at any time. Limitations are subject to case-by-case variances it higher levels or  more-lengntny periods
           are needed  for  condenser tube  cleanliness.

***  Note:  Or  influent amounts, mg, to  that source in the same day, whichever is the greater.

  #  Note: No discharge  of chlorine or  other biocides used for biological control in condenser tubes.

 ##  Note:  Effluent  limitations are average concentrations during the time span of each runoff event and maximum concentrations  at any  time.
###  Note: Average is amount,  mg, and maximum is concentration, mg/1.
   +  Note:  Same  as  ## except  that  limitations apply separately to (1)  the  segregated first  15 minutes  of runoff from any rainfall event, and  (2) the
           remainder of the rainfall  runoff from any rainfall event.

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                                    Table  H-2

           SUMMARY OF EFFLUENT LIMITATIONS GUIDELINES AND STANDARDS FOR HEAT
         TYPE OF UNIT
                            BEST PRACTICABLE CONTROL
                         TECHNOLOGY CURRENTLY AVAILABLE
                           to be met no later than
                                 July 1, 1977
  BEST AVAILABLE TECHNOLOGY
   ECONOMICALLY ACHIEVABLE
   to be met no later than
  LARGE BASE-LOAD

    Construction completed
    after July 1, 1977

    Construction completed
    before July 1, 1977
     • 500 MW and larger
     • 300-499 MW
     • all other

  SMALL BASE-LOAD

  CYCLIC

  PEAKING
                              NO DISCHARGE
NO DISCHARGE  (July 1, 1980)
                              NO LIMITATION
                              NO LIMITATION
                              NO LIMITATION

                              NO LIMITATION

                              NO LIMITATION

                              NO LIMITATION
NO DISCHARGE
NO DISCHARGE
NO DISCHARGE

NO DISCHARGE

NO DISCHARGE

NO DISCHARGE
(July 1,
(July 1,
(July 1,

(July 1,

(July 1,
(July 1,
1978)
1979)
1980)

1983)

1983)

1983)
  Large means units in plants over 25 MW and in systems over 150 MW.
  No limitation for any unit with a remaining service life of six years or less.
  No limitation on once-through house service water for nuclear units.
  No discharge excludes blowdown,which is limited to a temperature not  exceeding the
      temperature of water returned to the condenser.
  Variations can be granted on a case-by-case basis where sufficient  land is not available
      and  (for best practicable control technology currently available,  only)  where
      neighboring land uses would be impacted by saltwater drift,  provided (for both land
      availability and saltwater drift)  alternative technologies are  not practicable.
r
STANDARD OF PERFORMANCE FOR NEW SOURCES IS NO DISCHARGE OF HEAT  (EXCEPT FOR SLOWDOWN)
    FOR ALL UNITS/ WITHOUT EXCEPTION

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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 ccntrol program came about with the enactment
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 cf technical 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 ccntrol activities were the responsibility 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 Executive Order  as
an  independent  agency outside the Department 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 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 most 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.

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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 significant changes was from a reliance on water
quantity  related  effluent limitations to a direct control of effluents
through the establishment of  technology-based  effluent  guidelines  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  pollutants.  Section
304(b)  of the Act requires the Administrator 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   treatment  techniques,  process  and procedure
innovations, operation methods and other alternatives.  The   regulations
proposed  herein  set  forth effluent limitations guidelines  pursuant to
Section 304(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

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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 Administrator1s
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  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 limitation 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
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 ehere such equipment will be used, including
preparation work at such premises.

Scope of Work and.Technical Approach

This document was developed, specifically, for effluent  discharge  from
steam   electric   powerplants   covered   under   Standard   Industrial
Classification 1972 Industry Nos. 4911,  4931,  and  4932,  relating  to
liquid  discharges  to navigable waters of the United States.  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 primary 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

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                                                           Table  III-1
                                                     PRINCIPAL STATUTORY  CONSIDERATIONS
STATUTORY
BASIS General Description Process Changes Cost
Process
Employed, Age
& Size of Equip-
ment & Facilities-
"Non Water Quality
Environmental
Impact & Energy
Best Practicable
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)(l)(B)

[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 reasons
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  Emphasizes process
for which "construe-    changes.
tion" commences after
proposal of regula-
tions.
2. Generally same
considerations as for  1983;
more critical analysis
of present availability.
                      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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relation to the effluent reduction  benefits  to  be  achieved,  age  of
equipment and facilities, processes employed, engineering aspects of the
application  of  various  types  of control techniques, process changes,
non-water quality enviornmental impact   (including  energy  requirments)
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  tc  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  of
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.   The  only recognition of heat in any special terms in 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  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
                                   11

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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  guidelines  and  standards  of   performance
proposed  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 ether provisions  of  the  Act  were  examined.
However,  since these permit applications cover only the characteristics
of the effluent with no quantification of  the  corresponding  treatment
practices,  the  value of the information obtainable from them is fairly
limited.  Also as part of this effort visits were  made  to  27  plants,
with  at least one plant visit to each of the ten EPA regions.  Sampling
programs were conducted at plants where  it  was  felt  that  sufficient
information could be obtained to document exemplary treatment practices.

The  economic  analysis  contained  in this report pertain only to costs
related to control and treatment technology  for  the  reduction  and/or
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 for effluent limitations guidelines and
standards of performance, extensive use has been made of  prior  studies
in  this  area  made for EPA, in-house informatipn developed by EPA, and
information developed by industry sources.  In particular, reference was
made to  unpublished material contained in a  draft  report  prepared  by
Freeman  Laboratories,  Inc.,  for  the Water Quality Office, EPA, under
Contract No. EPA-WQO  68-01-0032,  entitled  Industrial  Waste  Studies:
Steam Generating Plants, dated May 1971.

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 municipal and cooperative categories, rely on firm purchases to meet
                                   12

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all  cr  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 construction  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
I970, 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 stored, and that the
industry must be ready tc produce at any give time all the  product  the
consumer  desires  to utilize.  While some industrial power is sold on a
so-called "interruptitle" basis, the total amount sold on this basis  is
insignificant compared to the overall power consumption.  As a matter of
fact,  the  ability  cf 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 generating 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 mist 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 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
                                   13

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                                    Table HI- 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
            mills/KWH
               7.7
              15.4
   * Note: Includes some hydroelectric and internal combustion.

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"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%  cf 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 hydroelectric generation, both of  the  once-through
and  pumpedstorage  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-4, again  from
FPC  reports,   shows  the  projected  distribution of fuel use for steam
electric power generation for the next two decades.

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 54% 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.
                                   15

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                                                  TABLE III- 3
CTl
                       PROJECTED GROWTH OF UTILITY ELECTRIC GENERATING CAPACITY
                                   (Figures in thousands of megawatts)


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)

                 (2)
                 (3)
These projections are keyed to the electrical energy demand projections made
by Regional Advisory Committee studies carried out in the 1966-1969 period.
The projections are premised on an average gross reserve margin of 20%.
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
            POWERPLANTS
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
                    PPG  PROJECTED ANNUAL FUEL REQUIREMENTS FOR
                          STEAM ELECTRIC POWERPLANTS
Fuel
Coal
Natural Gas
Fuel Oil

U^00
3 8

Measure
10 tons
12
10 cubic feet
10 barrels
3
10 tons to diffusion
plants without re-
cycle of plutonium
1970
332
3.6
331

7.5


1980
500
3.8
640

41


1990
500
3.8
800

127


00

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                                              Figure   III-l
                              PROJECTED TOTAL  U.S.  ENERGY PLOW  PATTERN  (1980)
                                                       234
HYDROELECTRIC
GEOTHERMAL
NUCLEAR
GAS
[IMPORTS)
GAS
(DOMESTIC)
 COAL
OIL
(IMPORTS)
OIL
(DOMESTIC)
                                                      Sgj^CONyERSIONLOSSES
ELECTRICAL
 ENERGY
GENERATION
  13.2
                                                           (UNITS: MILLION BBLS/DAY OIL EQUIVALENTI

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Coal is the most  abundant  of  the  fossil  fuels.   Nationwide  it
estimated  that proven recoverable reserves are sufficient to supply
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  ether 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 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  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 ccal.

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  Icng  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 alsc 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
                                  20

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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.
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
have  caused at least one major system to announce a slowdown in planned
expansion resulting in the delay in construction of two large generating
units.

The setting of effluent standards for  steam  electric  powerplants  has
therefore  involved  a large number of complex factors, many of which do
not apply to a conventional  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 some other 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 second law of thermodynamics which rests an experimental evidence.

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
                                   21

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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  the  conversion  of  heat  into any other form of energy is
limited  to  efficiencies  of  about  40  percent  regardless   of   any
improvements  to  the 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 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  is  not
radioactive, drives the turbine.  In a boiling water reactor,  steam  is
generated directly 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 similar 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,
converting  of  liquid  to  vapor  and  superheating   (heating above the
saturation  equilibrium  temperature)  the   steam.    Superheating   is
                                   22

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necessary  to prevent excess condensation in the turbines and results in
an increase in cycle efficiency.  Reheating, the raising of the  temper-
ature  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 cf 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
Rankine  cycle  by  providing  for  some  type  of  direct conversion of
chemical  energy  intc   electrical   energy.    This   group   includes
magnetohydrodynamics, 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
developments  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.  Beth 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.
                                   23

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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 15S5 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  electric
power  is  expected  to decline to about 1% 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 lead 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.   90-542).   Development  of the maximum potential at other
sites may be limited ty 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  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  ether 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
                                   24

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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 upper limits  as their ideal energy conversion efficiencies based
on the  maximum combustion temperature  and  the  heat  sink  temperature
 (ambrient  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  toiler 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
                                   25

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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 steair 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  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  30%.  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 40%.  One  HTGR
is  operating in the United States at this time, with another  expected to
be  operating in 1974.  The HTGR should be responsible for a   significant
portion  of  the  total  nuclear  capacity  by  about 1985.   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.
                                   26

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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 tc those of current nuclear plants.

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 KW 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 net 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
                                   27

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loaded units  and experience with gas turbines used as base- load  units
is limited.

A  major  advantage  cf  the  combustion gas turbine is the fact that it
requires no cooling water.  Conversion of existing 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  teen  converted  to accept a mixture of 1C to 2Q%
shredded refuse and 80 to 90% powdered coal.  The refuse has  previously
been processed to remcve a portion of the ferrous metals.  The operation
appears to be reasonably successful, although its economic justification
is  more  difficult  to  document.   Refuse can never supply more than a
minor  fraction of  the  energy  requirements  of  a  community  and  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

Magnetohydrodynamics

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
                                   28

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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 (4000-5000°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  ccnstruction 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 ten 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.

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
                                   29

-------
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  cf 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  applications,  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  iranufacture  of  the usable fuels also involves the
utilization of significant quantities of electric and other  energy,  so
that the overall benefits are questionable.

A  strong  effort is teing 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
earth's  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.

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.
                                   30

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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 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 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.
                                    31

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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  comirercial  operation.   For  example,  the  condensed
construction schedule for a 200 MW oil-fired unit shown in Figure  III-2
encompasses  a  span cf 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.
                                     32

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                                   Figure  IH-2
                  CONDENSED CONSTRUCTION SCHEDULE, 200 MW OIL-FIRED UNIT*  (Reference No. 187)
U>
U)
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
JFMAMJJASOND
-

1973
JFMAMJJASONT

Initd
.__ Commerci

	
...



1974
JFMAMJJASOND

Boilout — ^
jal 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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                                      Figure III-3

                    TYPICAL LWR NUCLEAR PLANT PROJECT SCHEDULE  (HIGHLIGHTS ONLY)*
          Task
                                      Year
1  2
8
10
00
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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                               SECTION IV

                        INDUSTRY CATEGORIZATION
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  and  location  and  their  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.

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
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.  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.
                                   35

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U)
           VENT
          A
                                         >! f
                                   SSCONDARY ! |4
                                   SUPERHEATER1' '
                                    SECTION
S5ES
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OILER
LOWDOWN
RUM \

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                         FIGURE   IV-I

              SCHEMATIC   FLOW   DIAGRAM
BOILER FEED
    PUMP
CONDENSATE
   PUMP
            TYPICAL STEAM ELECTRIC GENERATING PLANT

-------
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 in the future 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 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.

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.
                                    37

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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/m2  (900 psi) expanded in the turbine to atmospheric
pressure and using exhaust steam to heat the feedwater, the total  cycle
efficiency would be atout 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/m2  (2-1/2 in 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 4558.  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 would  require
higher steam pressures and temperatures would 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.

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  5000  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 14 MN/m2  (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/m2  (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
                                   38

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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 1950r  with  associated  lower  costs  of  larger
units,  have  made  it  economical  and  reliable to have one boiler per
turbine-generator.

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 plantary discs.  Each set of moving and plantary
discs is called a stage.  The moving discs are  mounted  on  a  rotating
shaft  while  the plantary 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/in2  (2-1/2 in Hg abs)
backpressure cannot operate at 1730 Kg/in2 (5 in 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 tc 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.
                                   39

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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  its  effect  on  plant
efficiency and therefore on the  thermal  discharge.   In  many  plants,
turbine  design  will  fce  a  key  factor  determining the extent of  the
feasibility of converting 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 cf these biocides most powerplants clean condensers
mechanically as part cf regularly scheduled maintenance procedures.

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-thro ugh11 system.   One
                                    40

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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-2 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 exemplary plants in the industry
using once-through coding  systems)  will  require  about  0.5  x  10~*
m3/sec.   (0.8 gpm) 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~* m3/sec.  (0.73
gpm) .  Because of differences in thermal  efficiencies,  nuclear  plants
under  identical conditions require about 50% more cooling capacity than
comparible fossil plants.

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.
                                   41

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                              ,
                              Los*
SCHEMATIC COOLING WATER CIRCUIT
         FIGURE IV- 2
             42

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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 plantary frame  called  a
stator.   The  process converts mechanical energy into electric energy at
almost 100X 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  waste effluents produced.

Coal

Coals  are  ranked   according  to  their geological  age which determines
their fuel  value and ether 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  SOX 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.   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  expert  uses.

The  ash content of  coal  varies from 5 to 20J& 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
                                   43

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plants.   These plants in effect trade off the cost of transporting  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 m3
 (3.9 trillion cu ft) cf natural 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 powerplants  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 835
by 1990.  This trend could be affected by several technological develop-
ments.   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
                                   44

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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 cil is presently the third most significant source of  fossil  fuel
for  generating  electricity, accounting for 15% of the total generation
in 1970.  However, in the New England- Middle Atlantic area it accounted
for 82% of  the  theriral  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 cf 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
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.
                                    45

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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 40%
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.  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 must  be made of   the
removal  of acid gases from the furnace stack gases,  and  the  disposal of
the effluents resulting from these operations.

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.  Refuse is  not  expected to
be a major source of fuel for the steam electric powerplant industry  in
the immediate  future.

Information on U.S.  Generating Facilities

An  inventory  of  operating  steam   electric powerplants in the United
States is presented  in Appendix A 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 1037 operating generating  plants   in   the
United  States  as   of  January 1, 1972, consisting 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-3  through  IV-5 provide  a cumulative frequency distribution
plot of plant  size within the steam electric  powerplant  industry.    It
can be seen from Figure IV-3 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-4  shows that the size  distribution of
                                    46

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                       TABLE IV-1
                INDUSTRY INVENTORY SUMMARY
                	—	     PLANTS UNDER
                          OPERATING PLANTS     CONSTRUCTION
       STATE           TOTAL  FOSSIL  NUCLEAR  FOSSIL  NUCLEAR
EPA Region 1
  Connecticut           16      13      3         00
  New Hampshire          550         00
  Rhode Island           550         00
  Vermont                431         00
  Maine                  660         01
  Massachusetts         29      28      1         01

EPA Region 2
  New Jersey            18      17      1         01
  New York              39      36      3         12
  Puerto Rico            440         00
  Virgin Islands         220         00

EPA Region 3
  Delaware550         00
  Maryland              14      14      0         01
  Pennsylvania          48      45      3         0       2
  Virginia              15      15      0         02
  West Virginia         12      12      0         10
  District of Columbia   220         00

EPA Region 4
  Alabama               10      10      0         03
  Florida               43      43      0         04
  Georgia               13      13      0         31
  Kentucky              19      19      0         20
  Mississippi            990         00
  North Carolina        12      12      0         12
  South Carolina        16      15      1         11
  Tennessee              770         11

EPA Region 5
  Illinois45      43      2         13
  Indiana               29      29      0         10
  Michigan              40      38      2         24
  Minnesota             48      45      3         01
  Ohio                  54      54      0         03
  Wisconsin             33      31      2         01

EPA Region 6
  Arkansas10      10      0         01
  Louisiana             27      27      0         11
  New Mexico            16      16      0         00
  Texas                 91      91      0         10
  Oklahoma              19      19      0         00

EPA Region 7
  Iowa                  37      37      0         01
  Kansas                32      32      0         00
  Missouri              31      31      0         00
  Nebraska              15      15      0         02

EPA Region 8
  Colorado              23      23      0         0       1
  Montana                880         00
  North Dakota           990         00
  South Dakota           981         00
  Utah                   660         00
  Wyoming                880         00

EPA Region 9
  Arizona               12      12      0         10
  California            39      37      2         02
  Hawaii                 770         00
  Nevada                 660         00


EPA Region  10
  Alaska                 14       13       1         00
   Idaho                   110         00
  Oregon                  660         00
  Washington              990         00

  TOTAL                1037     1011      26        17      42
                           47

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                               48

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                                 49

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                             FIGURE IV-5



                                50

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fossil-fueled  plants  roughly  corresponds  to  the  industry  profile.
However,  Figure  IV-5  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 1500 MW.

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  nrust  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-6).  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 450
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.

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 outlined 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 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
cals   (3,413  BTU)  of  heat  energy.   Steam pressures and temperatures
increased from about 1.17 MN/mz  (170 psig) at the turn of the century to
1.72 - 1.90 MN/m2  (250> - 275 psig) and 293°C  (560°F) by World War I, and
                                   51

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            Figure IV- 6
LARGEST FOSSIL-FUELED STEAM-ELECTRIC
    TURBINE-GENERATORS IN SERVICE
               1900 - 199*0
   2500 r
   2000
                       292
 oo
   1500
   1000
    500
                I
      1900
1930
  YEAR
1960
1990
                 52

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to 3.10 - 4.48 MN/m«  (450-640 psig) and 370-400°C  (700-750°F)  by  1924.
278   In  1924 and 1925 there was a surge to 8.27 MN/m2  (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/m2  (3,206
psia)  and  temperatures  of  540-565°C   (1,000-1,050°F) . 278   Above the
critical pressure the liquid and vapor phases are indistinguishable  and
there  is  no  need   for  a  steam  drum  (separator).  The economic jus-
tification 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 gen-erate  a kilowatt hour, as shown  in  Figure  IV-*7,  taken
from Reference No. 292.  In 1900 it required 2.72 Kg  (6 pounds) of coal,
(4i,700 K cals (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  cals/KWH   (8,717  BTU/KWH).  28°   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  tc  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-8.  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-9 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 improvement in efficiency
achieved  as  the industry has progressed to newer and larger generating
facilities.

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. 2»2  Traditionally, plants have been
located in or near population centers to reduce transmission  costs  and
satisfy  the other key site factors mentioned.  Table IV-2 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
                                    53

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  30,000
  25,000
  20,000
        \
h
UJ
LJ
CL


D

CO
   15,000
  10,000
   5,000
\
          Y
            MATIONAL  AVE'RAGE
                BEST
             PLANT
      0
       1920    1930   1940   1950   I960  1970   I960   1990
                 HEAT RATES OF FOSSIL-FUELED
                   STEAM ELECTRIC PLANTS


                        FIGURE IV- 7
                                   292
                             54

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o
o
                              LEGEND
                      m UNITS UNDER 10 YEflRS OLD
                      A 10 TO 20 YEflRS OLD
                      X OVER 20 YEflRS OLD
 ).00
20.00
 40.00  60.00   80.00
UNIT CflPflCITY  (MW)
100.00
120.00
HlO1
140.00
160.00
      HEHT  RRTE  VS  UNIT  CRPfiCITY
                      Figure IV-8
                          55

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o
o

d
0_,
CO
                                        LEGEND
                               CD UNITS  UNDER 100 MW
                               A 100 TO  300 MW
                               X OVER 300 MW
 o
 o

 o
 00^
 CM
 o
 o
 o

 CM"
 o
 o
 o

 CM"
 o
 CM
 CM
 O
 O

 O
 O
 CM
CC
                                   a

                                   a
CD
— CD
cr —
CC
                  a

                  a
                              a
                              a
                                 an
                                             a i
                                           a
                                           a
 o
 o
 o
 CM
 O

 O
 O
         x       a
           x
           xax

                                 an
                                      Q „  m
 "t.OO    5.00    10.00   15.00   20.00   25.00   30.00   35.00   40.00
                 UNIT RGE IN TERRS


       HERT  RRTE   VS.   UNIT   RGE
                          Figure IV-9


                             56

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                                  TABLE IV-2

                       URBAN STEAM.ELECTRIC POWER PLANTS
HO.
 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
Mas s achus ett s
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
Hawaii
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
                                     57

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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.

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
month's   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 transportation 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.

Air Pollution Control

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.
                                    58

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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 a relatively costly procedure.   Many  alternatives  have  been
proposed  to remove the SQ2, and several are being tried 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.

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,  high-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 elder 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
                                   59

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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 continuous 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  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.

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  peaking  units,  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.
                                    60

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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 the same capacity.  There are  some  differences,
however,  that  may  affect  the operation of the nuclear plant, such as
relative operating costs, refueling time, 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 acceptance of the breeder reactor will
introduce another factor in  the  economic  evaluation  of  light  water
reactor  operation  as the water reactors produce the plutonium utilized
so efficiently by the breeder.  Ultimately, however, the water  reactors
may become the marginal operating plants on a utility's 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 the event, fossil units, pumped-stroage
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 termed  base-loaded  units.   Units  which  are  operated  to  meet
                                   61

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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 tnird 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 originally built for  peaking  or   cyclic  service  is
considerably  less than  195 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 useful
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  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  systeir  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
                                    62

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also  have  multiple  units  serving  eadh  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  complicates  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 cf 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:

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  seasonal  peak  loads
only.   During  periods  of  operation the unit is held in standby or is
shut down.

This type of classification system would require a  designation  by  the
utilities  as to which units are in each group.  This could be validated
by EPA's field representatives.  These  definitions  would  probably  be
                                   63

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generally  accepted  fcy  the  industry.   The base-loaded units  could be
identified on the basis of these definitions.  Some  disagreement  would
be  expected  concerning the differentiation between cycling  and peaking
units under these definitions.

Definitions Based on Annual Hours of Operation

It is  clear  that  a  tasic  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  cf 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 cf generation.

Definitions  on the Basis of Unit Indices

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

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 KWHRS.  The one-hour net maximum demand was  7,719,000  KW.
The  average  hourly deirand 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.
                                   64

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                                 Table IV-3
                       CHARACTERISTICS OP UNITS BASED ON ANNUAL
                             HOURS  OF  OPERATION
Annual Hours of
Operation
0 - 2000
2000 - 6000
6000 - 8760
Heat Rate, Btu/kwhr
Min. Mean Max.
8727 15793 27315
8735 12493 27748
8706 10636 26741
Remaining Service? yr
Min. Mean Max.
1 11 26
1 15 26
1 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,
cn

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Thus,  if  the load factor  is 100%  over a  period  of  24 hours, we at once
know that 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 KWHRS  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%


Thus  the operating load factor takes into  account the variation  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 KWHRS   (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%.
                                    66

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Operating Capacity Factor

Although  a  plant  may  have installed equipment of a certain amount of
generating capacity, cnly 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 KWHRS.  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%.

Section 304 (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 capital cost associated with the
application of pollution control technology in relation to the  effluent
reduction  benefits  to  be  achieved.   Similarily, the capacity factor
could determine, in relation to the  effluent  reduction  benefits,  the
incremental  production  cost  and  the incremental reduction in reserve
margin due to lost generating capacity.

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  must  be  able to respond readily to swings in systems
demand, or  cycling.   Units  used  for  base-load  service  produce  60
percent,  or  more,  cf  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
                                   67

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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.

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 "total
cost ... in relation to effluent reduction benefits..." 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  anc
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.
                                    68

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Furthermore,  while  the  technology  for  affecting  this  transfer  is
available, its application is dependent on  many  factors  not  directly
associated  with  the  production  process.   The  effectiveness of heat
transfer devices is tc seme 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  effects  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  powerplant  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, anc 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-4  provides  the  informal  categorization  for  the
purposes of the  development  of  effluent  limitations  guidelines  and
                                   69

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                      TABLE IV-4
               CHEMICAL WASTE CATEGORIES
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
       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
       B.  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.  SO2 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 Rad Wastes
       F.  Construction Activity
                       70

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standards for chemical wastes, and Table IV-5 shows the applicability of
the  categories  to  plants utilizing the four basic fuels for producing
electricity.

Thermal Discharge Characteristics

The most obvious factor influencing  the  rejection  of  waste  heat  to
navigable  waterbodies  is the type of condenser cooling system utilized
within a plant.  Powerplants  which  recycle  cooling  water  through  a
cooling  device only affect the receiving water by way of the telatively
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 systeirs.

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 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.
                                    71

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                         TA3LE IV-5
        APPLICABILITY OF CHEMICAL WASTE CATEGORIES
                      BY TYPE OF FUEL
               at ion
                                         X
                                         X
Proces
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 Tubes
      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  (SO2) Control Devices

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

     X
                           72

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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  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.
                                   73

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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 equipirent 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  elecelectric  production  to
be  36 years 87.  Figure IV-7, 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 to
subcategorize  fossil-fueled   units   by   age,   with   6   (six-year)
subcategories 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,  categorization   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 Section 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  torm  the  basis  for
thermal   waste  subcategorization  of  the   steam  electric  powerplant
industry.   Among  these  technical  and  economic  factors   considered
relative to  the  size  of  a   unit  were  availability  and  degree of
                                    74

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practicability  of  control  and treatment technology, and unit costs of
control and treatment  technology  with  relation  to  other  generating
costs.   The  primary  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
powerplants  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.  Size subcategorization based on this
precedent  was  seriously  considered,  because  the  form  in  question
outlines  the  environmental  details  of  each  powerplant  required to
respond.

However, investigation indicated that the exclusion of smaller units was
based primarily  on  procedural  considerations  rather  than  technical
factors.   There  is  no  significant  technical  factor  which suggests
division of the industry on the same basis as established  by  the  FPC.
In  addition,  other  subcategories  based on size were also considered.
However,  no  technical  or  economic  bases  were  found   to   justify
subcategorization  by  size  of unit or plant.  It was therefore decided
not to establish formal subcategories on the basis of size of facility.

As a result of  evaluation  of  the  factors  outlined  above,  informal
categorization   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  (six  groups
covering the span of 36 years).

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,  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-6 the
subcategorization rationale for heat is summarized in Table IV-7 and the
subcategorization rationale for pollutants other than heat is summarized
in Table IV-8.
                                    75

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                    Table IV-6

             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.

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                               Table IV-7

       SUBCATEGORIZATION RATIONALE FOR POLLUTANTS OTHER THAN HEAT
Characteristic
 of Plant
Need for Sub-
categorization
               Rationale
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 for small plants would be significantly
greater but still relativelly 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 are small
for all plants

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                                         Table IV-8
                             SUBCATEGORIZATION RATIONALE FOR HEAT
       Characteristic of Unit
                             Need for
                          Subcategorization
                                  Rationale
-j
00
      Utilization(Base-load,
        cyclic, or peaking)
Age



Fuel


Size



Process Employed

Land Availability


Water Consumption


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


        •Noise


        •Aesthetics
 Yes



 Yes



 Yes


 Yes



 No

 Yes


 No


 No




Yes



No


N<3


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.
Capital is less readily available and design
engineering manpower requirements higher for
small plants and systems relative to the effluent
reduction benefits of thermal control technologies.
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
                                           Dodies.
                                           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.

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The degree of nonthermal effluent reductions that can be achieved by the
application of specific control and treatment 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,  fuel
utilized, and utilization characteristics of the plant,  with  only  the
age  of  unit  and its utilization characteristics qualifying as further
bases for subcategorization of thermal discharges, and waste source  for
nonthermal discharges.

An  important  footnote  to the subject of industry subcategorization is
that while certain factors were net found to qualify as  candidates  for
general  subcategorization,  some  were  found  to  be  factors which in
particular cases could  affect  the  degree  of  the  practicability  of
applying  certain waste water control and treatment technologies.  Those
factors which must be further considered 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,  significance  of  system  reliability  requirements,  and
characteristics   of   intake   water  (temperature,  concentrations  of
constituents) .
                                   79

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                                 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.  Seme wastes are discharged more or
less continuously as long as the plant is operating.   Some  wastes  are
produced  intermittently, 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, 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.
                                   81

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                                                   cvltwiCMS
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                                                    ^YPICAL FLOW DIAGRAM - S1EAM EI£CTRIC POWER PLANT (POSSIIr-PUEIiED)

                                                                SOURCES OF CHEMICAL HASTES

                                                                     FIGURE A-V-1

-------
CO
         FOLSOM
         SOUTH
         CANAL
         WATER
                   700 GPM
10.000-14.000 GPM
                                        REGENERANT
                                        CHEMICALS
                                                                      DEMORALIZED

MAKE-UP .
SYSTEM

230 GPM
6 GPM
440 GPM


r «
RAW WATER
DEMINERALIZER



SANITARY
SYSTEMS

PLANT RAW
SERVICE
WATER SYSTEM
EMINERALIZED
WATER
REGENERA



PRIMARY
AND
SECONDARY
SYSTEMS


NT WASTE

SEWAGE
TREATMENT

iL.
H
i

STORAGE TANK

cr
OEM

A_




NDENSATE
NERMIZERS


1REGENERAN1
WASTE
EGENERiXT
OLDUP1ANK
I

*-


NEUTRAUZATIGfc
CKE;\AICALS







REGENERANT
CHEMICALS

COfcDENSATE
STORAGE
TAN<


                             5000-11.400 GPM
                             0-3200 GPM
                                                                                    ATMOSPHERE
                                                  Figure  A-V-  2

                         SIMPLIFIED WATER SYSTEM  FLCW DIAGRAM FOR A  NUCLEAR  UNIT
                                                                                    108r

-------
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  steairu    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  2800  kw/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 boiler 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 pretreatirent  (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
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   or   all dissolved solids within the
recirculating evaporative  cooling  systems.   These   streams  may  also
contain chlorine and ether chemical additives.   According  to the FPC234,
the  principal  chemical  additives reported for cooling water treatment
are phosphate, lime, alum and chlorine.
                                   84

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As a result of fossil-fuel combustion in  the  boiler,  flue  gases  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 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
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  precipitate
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.
                                   85

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Besides  these  major waste streams, there are other  miscellaneous 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

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 Eurns and Roe, Inc.

These  data  are included in Appendix 2.  Note that a code system is  used
for individual plant identification.

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

   I.  Condenser Cooling System
       A.  Once-through
       B.   Recirculating
                                    86

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

 III.  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
      B.  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.  SO2 Removal

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.  construction  Activity

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  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
                                   87

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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.

Recirculating 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 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++) , magnesium  (Mg-H-) , sodium  (Na+) ,  and other metallic ions,
and carbonate (CO3—) , bicarbonate  (HCO3-),   sulfate   (SOU—),  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.

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
                                    88

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saline  water,  c  values as low as 1.2 to 1.5 may be required,  this is
usually not a materials or  operating  limit,  but  rather  a  means  of
preventing biological damage from blowdown salinity.1*4

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 Cr 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-DfC-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	                 	(cfs)

          1.2                    107                      128
          1.5                     42.8                    64.2
          2.0                     21.14                    42.8
          5JO                      5.3                    26.7
         10.0                      2.3                    23.7
         20.0                      1.1                    22J5

This table was developed assuming an evaporation rate  (Ev) of  21.4  cfs
and a drift rate  (D) cf 0.05 cfs  (0.0053S of 950 cfs).»**

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.

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

    c.   Reducing the size and cost  of  makeup  and  blowdown  handling
facilities  (i.e., pumps, pipes, screens, etc.).1**
                                   89

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                                      Table  A-V-1
                       RECIRCULATING WATER QUALITY LIMITATIONS
                                 144
    Characteristic
       Limitation
                              Comment
pH and Hardness
pH and Hardness
with addition of
proprietory chemicals
for deposit control.
Langelier Saturation
   Index = 2.5
Langelier Saturation
   Index = 1.0
                     Langelier Saturation
                        Index = pH-pHs

                            where

                     pH = measured pH
                     pHs = pH at saturation
                           with CajK>3
                     See Figure A-V-3   for
                     nomograph solution.
Sulfate and Calcium
                              CSQ  =  concentration  of
                                 4   S04 in mg/1
                              Cc  = concentration of
                                                                Ca in mg/1 as CaC03
Silica
                              CJ..Q  = concentration  of
                                      Si02 in mg/1
Magnesium and Silica
(C
                                       SiO
                = 35'000
                               M
= concentration of
                                                                Mg  in mg/1 as
                                         90

-------
                  Figure A-V-3

NOMOGRAM TO  DETERMINE LANGELIER SATURATION INDEX
                                                     228
        Courtesy Power Engineering
    t  6000
            MILLION
r-4000
I-3OOO
' pALK AND
": pC a SCALE
r2000 4.0
- *.?
E'°°° 1 as
r 800 2.4-4
r 600 T
Rrrpr>r'fjt~p J
t > t f-'.iVOC O 4 -
; paws *?-z"3 ac
^^ (V 1 :
r 30<)^* ^ \ V?c° . 2-°^1
: 	 ^ ^* ~^^ \ "- _j 25-
-~I>ALK * 1.3 ^ -
d"^5.o--
- ;oo IG-*
(so ; I
r 60 M^ /.5-
"C"5C4££ -j -
r 40 4
/.2 4
- 30 A/0.
: 32
- 40
j- 50
r fio
r 70

— so
~r QO

— too
~r i in
-!20
-140

160

180
^ /./•*-_.
                                                TEMf?,f
       IO
 Example: Water at 124 F has a pH
 of 7.7, total bOtius. of 400 ppm. ca!-
 ciurrr hardness as CaCU3 of 240 ppm,
 and alkalinity as CaCO., of 196 ppm.
 Find the Langelier saturation index.
 Solution:  (i) Join 400 ppm nn the
 iefthand scale with 1?4 F on the tern-
 persti-re r-^=?!s.  .At rrtterccotior. with
 C sci-Ie note value of  1.7.  (2) Join
 240  ppm with pCa  reference point
 and extend to pCa scale. Read pCa=
 2.62. (3)  Join 196-ppm with pALK
 reference point, extend to pALK scale
and read pALK=2.40. Add the three
values:
  PHS=C + pCa  + pALK=6.72
 lndex=pH-pHs=7.2-6.72=+ 0.48

                91

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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  SOX  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  O.OOSX   of  the  cooling  water  flow  for
mechanical  draft  towers  and  0.00256 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  % 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
856  of  this  value.  Higher  rates of  heat  rejection in the blowd'own 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  Naf  substitution  for Ca-J-+ and Mg-H-.   Advantage may be taken of the
greater solubility of some ions.  For  instance SO4— may be  substituted
for CO3— or HCO3-, as:                           ~

          Ca CO3 + H2 SO4 = CaSOU + H2O + CO2 (g)

         Mg (HCO3) + H2S04 = MgSOU +2H2 +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 icns  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 water  softening to  reduce  or  eliminate
blowdown at certain powerplants is discussed in Reference 22.

Eventually  the  limit  is  reached and there must  be some bleed through
drift  or  blowdown   although its  quantity  may  be  greatly  reduced,
resulting  in  higher  concentrations.   Data obtained from the study of
fifteen plants  (See Appendix  2) 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
                                   92

-------
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.

Water Treatment

All water supplies contain varying amounts of suspended solid matter and
dissolved  chemical  salts.   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 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 removal 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 filtered 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-U  and  A-V-5  show
simplified  flow  diagrams  for  clarification  and filtration processes
respectively.  Surface water, in addition to dissolved  impurities,  may
                                   93

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TRJEATMEMT
J
                  CLEAB. WATEIZ.
             CLARIFICATION PROCESS
                 FIGURE A-V-4

            FILTRATION  PROCESS

               FIGURE
                   94

-------
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(SO4)3 .  18 H2O), ferrous sulfate  (copperas, FeSC4 .  2
H20) ,  ferric sulfate (ferrifloc, Fe2  (SO4)3) , and sodium aluminate"" (soda
alum,   Na2  A12  O4).   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  carbonate   (soda  ash-Na2CO3) .
Calcium  is  precipitated  as calcium carbonate  (CaCO3) and magnesium'as
magnesium hydroxide  (Mg (OH) 2) .                       ~

Chemical precipitation of calcium and magnesium can be  carried  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 powerpiants 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 op-
posite 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)
                                    95

-------
RAW
                 ION EXCHANGE PRCXTESS
              CATIONIC AND ANIONIC TYPE
                   FIGURE A-V- 6
                         96

-------
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 regeneration.

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  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 100X of
its settled bed depth.  Flow rates of 3.4-U.1 10-3 m3/s/mz (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 8.0 m3 water per  m3  resin.   Anion  rinse
water  is  approximately  10.0  m3 water per m3 resin.  With mixed resin
units, there are two  additional  steps  in  the  regeneration  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, magnesium, 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-U  times  the
stoichiometric  exchange  capacity of the resin.  On a weight basis, the
                                   97

-------
   Acio
                  wAsye-
ION EXCHANGE PROCESS
  MIXED RESIN TYPE
    FIGURE A-V-7
         98

-------
waste sulfuric 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.

Occasionally,  hydrochloric acid is used for hydrogen cycle regeneration.
Hydrochloric acid yields a greater regeneration efficiency than sulfuric
acid.   The cost of hydrochloric 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  45S.  The spent regenerant will contain
the eluted anions.  These are  sulfate,  chloride,  nitrate,  phosphate,
alkalinity,  bicarbonate,  carbonate, 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/or  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  1056  sodium  chloride solution.  The waste
regenerant consists of approximately  1/3  part  calcium  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  condenser.
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 the pool, the raw water salts in the
pool become concentrated.  If allowed to concentrate too much, the salts
will scale the heating surfaces and the heat transfer  rate  diminishes.
To   prevent  scaling,  a  portion  of  the  pool  water  is drawn off as
                                   99

-------
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  re-
acts 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  different  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  cf processes involved or toxic  elements involved in
the process.  Reference 21 reports waste water flows as shown  in  Table
A-V-2.

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.

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


                                 100

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                                 FEED
                          COU06USE&
COJJD.
        J
        EVAPORATION PROCESS
           FIGURE A-V-8
            101

-------
                 Table  A^V-2
      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
                      102

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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  per  liter.   Suspended  solids  amount  to
approximately  75  -  8058  of total solids with the quantity of volatile
solids being 20 - 25X of total solids.  The BOD level usually  is  30  -
100  mg  per  liter.  A large corresponding COD level of 500 - 10,000 mg
per liter 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  clarifiers.
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
per liter suspended solids.

All  ion  exchange  wastes  are  either acidic or alkaline except sodium
chloride solutions which are neutral.  While ion exchange 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  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-3 shows the arithemetic mean  and  standard  deviation  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  variations.   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 clarification wastes, the  reported
data  do  hot  indicate  whether  the  waste  stream  is a sludge from a


                                 103

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               TABLE A-V-3

    ARITHMETIC MEAN AND DEVIATION OF

SELECTED WATER TREATMENT WASTE PARAMETERS
                               ARITHMETIC  STANDARD  0~
                                 MEAN     DEVIATION m
                                   m           0-
CLARIFICATION WASTES
Flow - M3 per day
Turbidity - J.T.U.
Total Suspended Solids -
Total Suspended Solids -



mg TSS per 1
kg TSS per day
Total Hardness - mg CaCO.3 per 1


1
25
2
3
Total Hardness - kg CaC03_ per day
Iron - mg Fe per 1
Iron - kg Fe per day
Aluminum
ION EXCHANGE WASTE
Flow"- MT~per day
Total Dissolved Solids -
Total Dissolved Solids -
Sulfate *• mg SO4per 1
Sulfate - kg SO4 per day
Chloride - rag Cl per 1
Chloride - kg Cl per day
Sodium - mg Na per 1
Sodium - kg Na per day
Ammonia - mg NHJ - N per
Ammonia - kg NH3 - N per
EVAPORATOR ^ SLOWDOWN
Flow""- M* per day
Total Dissolved Solids -
Total Dissolved Solids -
Total Suspended Solids -
Total Suspended Solids -
Sulfate - mg SO4 per 1
Sulfate - kg SOjj per day
Chloride - mg Cl per 1
Chloride - kg Cl per day





316
,088
,213
,673
,215
27
352
212


2
53
5
7



1 Piece


mg TDS per 1
kg TDS per day






1
day


mg TDS per 1
kg TDS per day
mg TSS per 1
kg TSS per day





74
7
1
2,
1
1

3














,515
,408
,311
085
,100
,708
124
,112
558
46
14

38
730
88
175
16
79
4
194
17

374
11
4
3,
3
4

6
1













613
,015
,060
,594
,812
63
572
662
Data

,737
,550
,263
859
,414
,603
389
,448
,572
137
41

62
805
187
443
36
109
8
337
31

1.
1.
2.
2.
2.
2.
1.
3.
—

5.
1.
3.
1.8
3.
2.
3.
2.
2.
3.
2.

1.
1.
2.
2.
2.
1.
2.
1.
1.

9
8
1
1
4
3
6
1


0
6
2

1
7
1
1
8
0
9

6
1
1
5
2
4
0
7
8
                    104

-------
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 boiler 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.  Con-
sequently, when the toiler 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.

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) + H2) + CO2(g)

Deposits  of 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.


                                 105

-------
Chelating or complexing agents are sometimes  applied.   Tetrasodium  salt
of  ethylenediaminetetracetic  acid   (Na4-EDTA)   and  trisodium  salt of
nitrilotriacetic acid  (NaJ-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  decreases 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 infiltration  in  the  condensate system.    In
addition  to  mechanical  deaeration,  sodium  sulfite  is  employed for
chemical deaeration.

                        2 Na2SO3  + O2 =  2Na2SO4

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

                          N2HIH- 02 - 2H20  + 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 bcilers 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 from boiler
plants using phosphate treatment  contain 5-50  mg/1  phosphate  and  10-
100mg/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


                                  106

-------
Efficiency.  Consequently, the data  have  greatly  varying   parameters.
'Reference 21 reports waste water flows  from boiler  blowdown  ranging from
tO-4 gal/1000 Ib steam generated.
ii

Equipment Cleaning

i
^Chemical Cleaning Boiler or  PWR steam Generator  Tubes

Boilers  are subject to two  major chemical problems, corrosion  and  scale
•^formation.  Proper operation and maintenance  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.

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

Chemical  cleaning of boilers can be of two types - 1)   Preoperational--
2necessary 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.

iTypical steps for preoperational cleaning involve:
it*
 (i)   an alkaline bo i lout using a solution containing   caustic   or   soda
ash,  phosphates, wetting or emulsifying agents  and sodium nitrite  as  an
^inhibitor to protect against caustic embrittlement.
i
" (ii)  draining of the solution after achieving satisfactory   removal  of
oil, grease, silica, loose scale, dirt  and construction debris  etc.

 (iii) rinsing of the toiler
u
 (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.


                                107

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

(vi)   second rinsing of the boiler with demineralized  water

(vii)   an alkaline boil out 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.

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 deposits 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 procedures are
more effective for copper removal, others for iron   removal,   and  still
others  for  silica  removal.   The  composition  of  boiler  scale  and
corrosion  products  is  briefly  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 toiler 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


                                 108

-------
leaked into the boiler  water,  and  therefore  will  differ  with  each
successive cleaning of the boiler.

Frequency of Boiler Cleanings

There  are  many  factors  which  affect the cleaning schedule for power
utility steam boilers.  High  pressure  boilers  require  more  critical
control  of  feed  water  purity  and  consequently usually require less
frequent cleanings.  A review of boiler cleaning  data  in  Table  A-V-4
shows  that  cleaning frequency varies from once in seven months to once
in one hundred months.   The  mean  time  between  boiler  cleanings  is
estimated  from these data as thirty months with a standard deviation of
eighteen months.

Types of Boiler Tube Cleaning Processes

Alkaline Cleaning Mixtures with Oxiding Agents for Copper Removal

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


                                 109

-------
          TABIE A-V-4
CHEMICAL HASTE CHARACTERIZATION
INCREASE IN POLLUTANT QUANTITY PER CLEANING CYCLE
BOILER TUBES' CLEANING
A
as*

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
IS
20
13
7
20
50
60
50
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
m3
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
D E F G H
Volume Alkalinity (CaCCh ) BOD
(1000 gal.) (lb> Kg (Ib) kg
46 1380 626 104 47.2
46 1380 626 104 47.2
28 181 82 -9.8 -4.45
57 -158 -72 -8.3 -3.8
80 3770 1711.9 121.4 55
50 158.4 71.94 -1.65 -0.75
150.8 -23.8 -10.84 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 - - -
IJKLMNOPQR
Total Total
COD Total Solids Dissolved Solids Suspended Solids Ammonia
(Ib) kg (Ib) kg (Ib) kg (Ib) kg (Ib) kg
4017 1823 11816 5369 8588 3899 176 80 16.7 7.58
4017 1823 11816 5369 8588 3899 176 80 16.7 7.58
5091 2311 12024 5458 10684 4850 9.8 4.45 1.2 0.54
8302 3769 11972 5435 11225 5096 75 34 9.8 4.45
11101 5040 34817 15807 1983 900.4 505.2 229.4 52.86 24.0
9169 4163 39698 18023 37196 16887 246 111.7 3.2 1.454
-14.07 -6.39 99.34 45.1 99.34 45.1 0000
_ - - _- -_
_ - - ____---
_ - - - - --
- - - -------
_ - - _- -
_ - - -------
_-- _ - _ -
_ - - -------
- - - - - - -
--- -- _-
- - - -- - -
- - - _______
--- -- -_
--- -- - -
--- -- - -
--- -- - -
--- -- --
--- -- --
--- -- - -
--- -------
--- -------
--- -- - -
-_- -- - -
--- -- - -
--- -------
--- -------
--- -------
--- -------
--- -- --
--- -- - -
--- -- --
--- -------
--- -- - -
-_- -------
--- -- - -
--- -------
--- -- - -
--- -- - -
- - - - - - -
--- - - --
-_- --_____
--- -- - -
--- - - --
- _ _

-------
                    TABLE A-V-4



          CHErflCAL WASTE CHARACTERIZATION



INCREASE IN POLLUTANT QUANTITY PER CLEANING CYCLE





              RniLgp TtmKs' CLEANING  (continued)
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
36J.O
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
'(lb)
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
-
-
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
-
-
F G H I
Sodium Nitrate
1076
1076
2018
-
4885
12378
-55.9
-
_
2569
2569
3504
1902
2742
3363
3363
5007
2200
1515
2031
182
243
128
-
-
-
2603
1301
2603
-
3500
5374
1144
573
1144
573
3027
3027
-
-
-
-
201
-
55.7
-
1440
2161
2105
810
2105
kg (lb) 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
J K L M
Hardness Bromide
(lb) kg (lb)
I'll 550
1211 550
-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
-
-
-
228
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 0
Manganese
(lb)
-
-
-
0.0059
30.8
_
-
-
27.9
-
-
48.9
-
-
-
-
-
15.4
-
11
-
-
13.2
-
-
11
-
11
-
-
-
-
-
-
-
-
-
11
-
-
-
-
-
6.6
-
6.6
-
-
kg
•
-
-
0.0027
14
_
-
-
12.7
-
-
22.2
-
-
-
-
-
7
-
5
-
-
6
-
-
5
-
5
-
-
-
-
-
-
-
-
-
5
-
-
-
-
-
3
-
3
-
-
p
Acidity, Oil and Grease,
Mercury, Sulfite, lead..
Turbidity Selenium. Phenols. Surfactants
JTU
370
370
276
23
387
100
0
-
_
NO DATA
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

-------
        TABLE A-V-4
CHEMICAL WASTE CHARACTERIZATION
A B C D E F G
Code Phosphorus Sulfate Chloride
(Ib) kg (Ib)
34C9 4.07 1.84 11.26
3406 4.07 1.84 11.26
3410 0.4 0.18 -40
3412 -0.08 -0.036
3414 7.26 3.3 73.37
3416 -0.001674 -0.00076 0.33
3404 -0.0125 -0.0057 2.24
3603 74 33.6
3603 -
3604 -
3604 -
3604 78.9 35.82
3604 -
3604 -
3605 58.72 26.66
3605 -
3605 -
3605 -
3605 -
3605 -
3606 40.97 18.6
3606 -
3609 24.45 11.1
3609 -
3609 -
3607 33.76 15.33
3610 -
3610 -
3610 30.1 13.7
3610 -
3611 28.7 13.05
3611 - - -
3612 -
3612 -
3612 -
3612 -
3612 -
3612 -
3612 - - -
3612 -
3612 30.9 14.03
3612 -
3614 -
3614 -
3614 -
3614 -
3614 17.24 7.83
3614 -
3613 17.24 7.83
3613 -
3613 -
kg (IX)
5.11 7772
5.11 7772
-18.6 19100
6142
33.31 25898
0.15 32191
1.02 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
kg
3528
3528
8671
2788
11758
14615
2.74
18324
6834
9537
9537
20532
6623
6623
19107
17834
19107
8372
8372
11047
13358
13358
5978
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 QUANTITY PER CLEANING CYCLE
BOILER TUBES' CLEANING (continued)
HI J K L M
Fluoride Aluminum Chromium
(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 (Ib)
_ _
-
-
-
-
-
-
395 18.94
-
217
217
1139 17
233
233
1742 13.87
1742
1742
477
477
628
11.0
-
724 28.6
-
181
8.8
233.6
452.6
233.6 8.8
233.6
392.4 6.6
392.4
87.53
87.53
87.53
87.53
128
128
513
513
228.8 8.8
228.8
114.86
495
247.88
247.88
250.6 4.4
376.3
249.2 4.4
164.5
124.8
kg (Ib) kg
6.91 3.13
6 . 91 3 . 13
1.4 0.63
1.21 0.55
23. 17 10.52
0.0832 0.0378
0.035 0.0160
8.6
- - -
- - -
- - -
7.7 16.9 7.7
- - -
- - -
5.3 13.87 6.3
.
-
- - -
- - -
- - -
5 11.01 5
- - -
13 6.6 3
- - -
- - -
4 8.8 4
- - -
-
4 " -
_
3 6.6 3
-
_
-
-
-
-
-
- - -
-
4 8.8 4
- - -
_
-
_
_
2 13.2 6
- - -
2 4.4 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
(li)
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
271.9
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
45.4
681
454
1362
681
726
635
545
454
454
227
454
454
454
R S
Maqnes ium
(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
-
-

-------
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, nitrates 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.

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.

The  data  in  Table  A-V-4  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  followed for once-through type boilers.

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

In nuclear powerplants of the PWR type, strict control on the quality of
steam  generator  water  is maintained.  Cleaning frequently varies with
plant characteristics, as in fossil-fuel power plants, but the  cleaning
methods are the same.
                                 113

-------
Boiler Fireside

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-5.   The pollutants in the waste stream
may  reveal  extreme values  of pH, hardness and suspended solids as well
as some metals.

Air Preheater

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 may contain  soda  ash
and  phosphates or detergents which  have been added to neutralize excess
acidity or alkaline  depending 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.
                                   114

-------
                   TABLE A-V-5
                                       TON
INCREASE IN POLLUTANT QUANTITY  PER CLEANING CYCLE
                AIR PREHEATER  CLEANING
A
— Line Codl?

1) 3409
2) 3410
3) 3411
4) 3412
5) 3413
6) 3414
7) 3415
B
Cleaning
cycles/yr
12
12
8
12
5
6
4
C
Batch
m3
409
852
1363
2272
265
162.8
378.6
0
Volume
(1000 gal.)
108
225
360
600
70
43
100
E
F
Alkalinity
(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
H

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
Dissolved
(Ib)
7907
16605
27022
44264
4467
3189
8249
L
Solids
kg
3590
7539
12268
20096
2028
1448
3745
M
Tot
Suspend*
(Ib)
1975
4008
6603
10788
477.9
785.24
1834
N
d Solids
kg
897
1820
2998
4898
217
356.5
833
O
P
Sulfate
(Ib)
1066
2231
3601
6114
692
423.8
979
kg
484
1013
1635
2776
314.2
192.4
444.5
Q
R
Chloride
(Ib)
1.801
0
0
9989
0
-8.96
-14.16
kg
0.8178
0
0
4534
0
-4.07
-6.43
BOILER FIRESIDE CLEANING
8) 3410
9) 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 PREHEAIER CI£ANING (continued)
Line

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

8)
9)
A
s»*

3409
3410
3411
3412
3413
3414
3415

3410
3411
B C
Ammonia
(Ib)
2.378
4.49
8.1
12
0.722
0.925
2.)76

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 M 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
B 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)
A
«#*

3409
3410
3411
3412
3413-
3414
3415
3410
3411
B C
Sodium
(Ib)
1.799
0
0
8630
552
-0.35
1.66
0
9
kg
0.818
0
0
^ 3918
' 251
-0.16
0.757
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
F
(Ib)
3.6
0
0
15.01
2.335
1.793
1.668
0
0
G
BCD
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 FIRESIDE CLEANING  (continued)

-------
Cleaning frequency is usually about once  a month,  but frequencies  of  4
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.

Miscellaneous small equipment

At infrequent intervals,  other  plant  components  such  as  condensate
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

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  (TSS), high or low pH values, metallic species,  oil, etc.

Cooling tower basin

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.  Some 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  powerplants  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.

Ash-handling is the conveyance of the accumulated waste  products  to a
disposal  system.  The method of conveyance  may  be either wet  (sluicing)
                                116

-------
or dry (pneumatic).  This report 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 lists commercial fuels
for power production. 27a

        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 powerplants.
In 1972, 335 million tons of coal were consumed in the  U.S.  for  power
generation.   The average ash content of coal is  11 % for the nation, 238
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.  powerplants.
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 pcnds are used.  A typical ash pond  is  illustrated
in  Figure  A-V-9, which is located in plant no.  U217.  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  related  to  the
physico-chemical  properties  of  that ash and to the volume and initial
quality of the water used.  Table A-V-6 lists some of  the  constituents
of  coal  ash.23* Table A-V-7 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


                               117

-------
TYPICAL ASH POND
 PLANT NO. 4217
 Figure A-V-9
      118

-------
              Table A-V-6
      CONSTITUENTS OP COAL ASH
                               238
Constituent
  Si°2
  A12°3
  Pe2°3
  Ti02
  CaO
  MgO
  Na2°
  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
0.1-0.3
0.1-0.6
0.0-0.1
 trace
 trace
 trace
 trace
 trace
 trace
 trace
 trace
                   119

-------
                         Table A-V-7


           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
FW
Pyrites Tank
Purge
Grlder Seal
Mill Rejects
Pressure Transfer
Hydrovac*
Bubblers
Cool Weirs
Pyrites Tank Make-wp
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
                               120

-------
         bottom ash 2,400-40,000 gal/ton ash conveyed

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 (56 of total ash)

Pulverized coal burners
Dry bottom, regardless of type
  of burner                                   85
Wet bottom                                    65
   (without fly ash reinjection)
Cvclone furnaces                              2 0
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 characteristics.  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-8.

In  that  table,  plant capacities range from 31MW to 2533MW and the ash
pond overflow varies between 1817 M3/day (480,000gpd) and 122,946 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 1X of the amount commonly
found in coal). 278  It is generally 0.10 to 0.15X 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.  Depending 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 removed by water
washing.  Generally the washing  is  done  while  the  unit  is  out  of


                                 121

-------
                                                                                        TABLE  A-V-8




                                                                               CHEMICAL WASTE  CHARACTERIZATION




                                                                              ASH POND OVERFLOW -' NET  DISCHARGE





                                                                       CHANGE IN PARAMETER LEVEL  FROM  INTAKE TO DISCHARGE
Plant
Code


3412
3416
3404
3402
3401
3405
1703
1720
1710
1722
1709
1711
1711
*1711
3936
M 3936
to .
to *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
Plant Capacity Fuel
HW

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
161S5
3164
15563
0706


21872


18908
21705
14276
12050
2978
138S6


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/o


C




C
C
C
C
C
C


C
C
C


C
Flow
m3/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
405.32
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)

11.62'
-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
1.3535
.3513
1-7048
0.1904
-
.1553
.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
rag/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
297100
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 10s
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- 8




                                                                             CHEMICAL MASTE  CHARACTERIZATION
acu D^MTI rnrRBS-T^id i
Plant
Code
3412
3416
3404
3402
3401
340S
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 ""^^nsaa fCfliCO* )
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
(Ib/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

MRT nTcrHAiwns! (continued)
CHANGE IN PARAMETER IEVEL FROM INTAKE TO DISCHARGE
__gulfate Alupiimim Chromium
(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
(lb,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
x 106
225100 0.075
2798
56468
4393
-2530000
-11879
162500 -
-54800 0.011
37000
398000 0.15
13400 0.1
425000 6
-3151 -0.145
421849
31600
241414
273014
14600 0.153
137000 1.67
160000
321525
374856 1.350
873000 0.021
297642 0.021
1070642
269000
109865
76654
604
456123
-
74500 6
20002
142217
96125
-
-
-
66433 5.30
428300 -
39200 -0.22
-2509 0.1
36691 -0.12
(Ib/day) kg/day
3.233 1.468
-
-
-
-
-
-
1.19 0.541
32.51 14.76
0.722 0.378
0 0
-0.8326 -0.384
-0.8326 -0.384
-
-
-
1.784 0.81
58.48 26.55
-
-
157.62 71.56
0.7 0.318
0.175 0.0795
0.875 0.3975
-
-
-
-
-
-
50 22.72
-
-
-
-
-
-
32.12 14.58
-0.916 -0.4160
0.125 0.0568
-0.791 -0.3592
(Ib/HWHr)
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/HWHr
x iff
111
-
-
-
-
-
-
33
940
43
0
-18
-18
-
-
-
37
1860
-
-
5165
83
21
104
-
-
-
-
-
-
2230
-
-
-
-
-
-
2541
-37
5
-28
mg/1
-0.113
0
-
0.01
-
0.139
O.OOOO1
-O.O14
-
-
0
-0.03

0.0005
O.O07

O.O11
-
-
-
O.OO1
-
-

0.080
0.004
0.007
0.005

-
_
-
-
-
-
-
-
0
-
-

(li/day)
-4.86
0
-
0.059
-
0.0055
0.0005
-1.515
-
-
0
-O.174
-0.17
O.OO44
0.35
0.354
0.1277
-
-
-
0.116
-
-
_
6.54
0.105
0.092
0.001251
6.738
-
-
-
-
-
-
_
_
0
-
_
-
kg/day
-2.21
0
-
0.027
-
0.0025
0.00023
-0.688
_
-
0
-0.079
-O.079
O.O019
0.159
0.16O9
0.058
-
-
-
0.053
-
-
-
2.97
0.048
0.042
0.000568
3.O6
-
_
-
_
-
_
_
_
0
_
_
-
(Ib/MWHr)
xlO6
-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 106
-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- 8




                                                                             CHEMICAL WASTE CHARACTERIZATION
ASH POND OVERFLOW - NET DISCHARGE
Plant
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
0101
3514
1716
1716
*1716

mg/1
0
-4
-
-
52
-1609
982
-
26
-
-3
173

30
32

73
14
-
-
3
92
88

27
23
18
37

-
-
23
-
-
-
-

-
-
-45
-136



-------
                                                                                      TABLE ArV-8
                                                                             CHEMICAL WASIE CHARACTERIZATION
ASH POND OVFRFLOK'— NET P1SCHARGR
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
Chloride
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
3T691
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
CHANGE IN PARAMETER IEVEL FROM INTAKE 1C
Copper
kg/MWHr mg/1 (Ib/day) kg/day (Ib/MWHr) kg/MWHr
x 10s x 106 x 106
3577000 -0.001 -0.043 -0.0196 -3 -1
-1460 0000 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 -Q.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
-
-
-

(continuted)
1 DISCHARGE
(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
-
-
-
-
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
-
-
-
0.409
-
-
i-
-
(Lb/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
-
-
-
-
Manganese
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 O.OOO75 0.189
0 -
-31
-31 -
6.8 -
48
54.8 -
24 0.076 8.85 4.02 40.74
1971 - - -
_
-362 -
-1501 -
-
_
-
29
44
8 - - -
0.447 -
81.447 - -
-
-
_
673 -0.02 -1.224 -0.555 -68
4523 0.102 3.467 1.574 350
_
-
-
71
-
-
-
-

kg/MWHr
x 106
-
-
-
-
-
-
-
-
-
126
0.0861
-
-
-
-
-
-
18.5
-
-
-
-
-
-
-
-
-
-
-
-
_
-
-
-31
159
-
-
-
-
_
_
-
-
•total of more than one waste stream for plant

-------
                                                                                        TABIE A-V- 8
                                                                              CHEMICA
                           Maqnes ium
                                                                             ASH  POND  OVERFLOW - NET DISCHARGE (continued)





                                                                      CHANGE  IN PARAMETER I£VEL FROM INTAKE TO DISCHARGE








                                                                              Mercury


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
*L825
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 mg/1 (Ib/day) kg/day (Ib/MWHr) kg/MWHr mg/1
x 106 x 106 x 106
231600 - - - - - -0.054
- ' -
- _ -
-4942 - - -
_ _
_ _
- _
54800 - - -
- _
158000 0.0002 0.044 0.0197 2.77 1.26 0.01
- _
-4470 - - - - - -
1212 - - - - - -
-3258 - - -
3000 - - - - -
16815 - - - - - -
19815 - - -
5100 - - - - - 0.011
1770 - - - - - -
- - - - - - -
-0.002 -0.00793 -0.0036 -0.44 -0.2
-7650 - - - - - -
- - - - 0.015
- - - - - 0.008
-
0 - - - - - -
5860 - - - -
2685 - - - - - -
55 -
8600 - - -
- - - - -
- -
- - -
-5811 - - - - - -
-2970 - - -
- _
- - -
-
- 0 0 00 0 -
9600 - - - - -
1020 - - - - - -
922 - - - - - -
1942 - - -
(Ib/day) kg/day (lb/ MWHr) kg/MWHr mq/1
x 106 x 106
-2.32 -1.057 -175 -80 -0.014
- - - - 0.162
- - - - 0.00013
_
- - - - 0.17
- - - - 0.117
0
- - - - -0.073
- - - -
2.167 0.984 139.2 63.2 0.03
- - - - 0.011
-
_
-
- - - - 0.009
- - - - 0.009
_
0.1277 0.058 5.88 2.67 0.003
_
- - - - -0.01
- - _ _ •
- - - - 0.03
0.5 0.227 130.83 59.4 0.003
0.066 0.0302 17.62 8 0.013
0.566 0.257 148.45 67.4
- - - - 0.07
- - - - -0.007
- -0.006
- - - - o.ooi
-
- - - -
- - - -
- - - -
- - - -
- - - -
- - - -
- - - -
- - - -
- - - - 0.05
- - - -
- - - - 0.12
- - - - -0.02
- - - -
(lb/
-------
                                                                                       TABLE A-V- 8
                                                                             CHEM
Plant
Code
3412
3416
3404
3402
3401
340S
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

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


(lb/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
Ehosohori]
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
is /WIBr)
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/MHHr
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
                                                                            ASH POND OVERFLOW - NET DISCHARGE  (continued)

                                                                     CHANGE IN PARAMETER LEVEL FROM INTAKE TO DISCHARGE

                                                                            Sulfite, lead. Oil and Grease,
                                                                    .tv      Phenols. Surfactants, AloicldeB
                                                                -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

-------
service.   In-service  water washing  at reduced  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-8 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.

Coalpile Drainage

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  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.   Active  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   gallons)   per  year  with
average  figures around 75,000 to  100,000 cubic  meters  (20 to 26 million
gallons) per year.  Table A-V-9 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.


                                128

-------
    TABLE A-V-9




COAL PILE DRAINAGE
PLANT
ID

4701
4706
4702
4705
4703
2120
4704
2119
0112
5305
COAL CONSUMED/DAY
Ibs Kgs
xlO6 xlO5
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 xUQ^
20 75.7
-
25 94.62
-
25 94.62
-
17 64.34
22 83.27
26.5 100.3
-

-------
Water pollution associated with coal  pile  runoff is  due to the  chemical
pollutants  and  suspended  solids  usually   transported  in  coal  piie
drainage.  Drainage quality and quantity is  variable,  depending  on  the
meteorological  condition, area of  pile  and  type of  coal used.  Areas of
high average rainfall 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 precipitation of ferric
compounds.  High humidity areas have  higher   precipitation  and  produce
larger runoffs.

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 acidity, and contain  iron, usually in the  ferrous   state.   Alkaline
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 contains large
amount of iron, mostly in ferrous state, and aluminum.  l37

Coal pile runoff is commonly characterized as having   a  low  pH  (high
acidity)  and  a  high concentration  of  total dissolved solids including
iron, magnesium and sulfate.  Undesirable  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 oxidized by ferric ion
to produce ferrous sulfate.  When rain 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.

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 FeS2+7 O2 +2 H2O  = 2 FeSO4+2 H2SO4

Subsequent oxidation of  ferrous sulfate  produces ferric sul-
fate:

     H F6SO4+2 H2SO4+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:
                                130

-------
     Fe2 (SOU) 3+6H20 = 2Fe (OH) 3+3H2SO4
and/or
     Fe2(S04) 3+2H20 = 2Fe (OH) (SO4) +H2SO4

Pyrites  can  also be oxidized to ferric ions as shown below:

FeS2*1t  Fe+3=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) .

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 reactions are dependent  upon  type
of coal and physico-chemical conditions of the pile.

The pollution of streams by coal-pile runoff may be attributed 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 synergism among 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-10.   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

The floor drains within a powerplant 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.

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


                                 131

-------
TABLE A-V-10
A B C
Plant
Line Code Alkalinity BOD
mg/1 mg/1
1) 3402 6 0
2) 3401 0 0
3) 3936 0 10
4) 1825
5) 1726 82 3
6) 1729
7) 3626
8) 0107 0
9) 5305 21.36
10) 5305 14.32
11) 5305 36.41

A B C
Plant
Line Code Copper Iron
mg/1 mg/1
1) 3402 1.6 0.168
2) 3401 1.6 0.168
3) 3936
4) 1825 - 0.06
5) 1726
6) 1729 - 0.368
7) 3626 1.8 4700
8) 0107 3.4 93000
9) 5305 - 1.0
10) 5305 - 1.05
11) 5305 - 0.9
D E F

COD TS IDS
mg/1 mg/1 mg/1
1080 1330 720
1080 1330 720
806 9999 7743
85 6000 5800
1099 3549 247
-
28970
45000 44050
_
-

Discharqe Concentrations
D E

Maqnesiuni Zinc
mg/1 mg/1
1.6
1.6
89 2.43
174 0.006
0.08
-
12.5
23
-
-
-
G

TSS
mg/1
610
610
22
200
3302
-
100
950
-
-


F

Sodium
mg/1
1260
1260
160
-
-
-
-
-
-
-
-

H

Ammonia
mg/1
0
0
1.77
1.35
0.35
-
-
-
-
-


G

pH
pH
2.8
2.8
3
4.4
7.8
2.7
2.1
2.8
6.7
6.6
6.6

Discharqe Concentrations

Nitrate Phosphorus Turbidi
mg/1 mg/1 mg/1
0.3 - 505
0.3 - 505
1.9 1.2
1.8
2.25 0.23
-
_
_
8.37
2.77
6.13
















                                     mg/1
                                                                            mg/1
                                              130
                                              130
                                             1109
                                             1850
                                    21700
                                    27310
                                     8.68
                                    10.25
                                     8.84
  525
  525
 5231
  861
  133
 6837
19000
21920
3.6
3.6
481
         1200
          825
                                                                                      mg/1
  0
  0
 0.37
 0.05
15.7
 0.3

-------
stream will be acidic if any wash water from air preheater  or  fireside
of the boiler winds up in floor drains.

Air Pollution Control
A  number  of  processes have been proposed for removing particulate and
S02 emissions from stack gases 4S.  Some of these  processes  have  been
suggested  for potential application in fossil-fuel powerplants 1*1,220.
In general the SO2 removal processes can be categorized as follows: *23

     (1)   Alkali scrubbing using calcium carbonate or lime
          with no recovery of SO^.
     (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 particulate 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 devices are described in  an  earlier
portion of this section of the report.

At  present  the "wet" processes - alkali scrubbing with and without SO2
recovery, oxidation of SO2 for sulfuric acid production - are mainly  in
pilot  plant or prototype stage of development.  Of the three processes,
sufficient data is available  only  for  the  alkali  scrubbing  process
without  SO2  recovery,  and consequently only this process is described
briefly in the following paragraph.

Flue gas from electrostatic precipitators  (optional equipment) is cooled
and saturated by water spray.   It  then  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 atmosphere 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


                              133

-------
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  for disposal (as a landfill).

The process described above suffers  from potential  scaling  problems.
The calcium salts tend to form a deposit, causing equipment shutdown and
requiring frequent maintenance.

The  process  is  a  closed loop type  and consequently there is a no net
liquid discharge from the process.   The   disposal  of  sludge  has  been
covered  in  the  literature  16».   However,  depending upon the solids
separation efficiency in a pond or mechanical equipment-,  there  may  be
excess   free  water associated with  the  sludge.   To  dewater this sludge,
mechanical filtration equipment may  be necessary.

To  date  eleven  utilities  have  committed   themselves  to   fullscale
installation  of  the alkali scrubbing process without SO.2 recovery 2".
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  process
for the  other plant  (no. 4216) is described in this  section.

Plant  no.  4216  of  79 MW capacity burns 0.7X  sulfur coal.  The boiler
gases are split into two streams - approximately 7558 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 124°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, some S02
pick-up  is achieved.  This is evident  from Figure A-V-8  where  the  net
output   from the process  (thickener  underflow) is richer in sulfate than
the process input  (river water) .  The  flow diagram   and  the  different
stream compositions are shown in Figure  No. A-V-10.

Miscellaneous Waste Steams

The  operations  and  the  waste  streams described  earlier are centered
around meeting the steam generating  boiler requirements.  Besides  these
chemical  waste  streams,  there  are  also   miscellaneous waste streams
originating  in  a  steam  electric  plant.    These   waste  streams  are
described in the remainder of this section.


                                 134

-------
                                                                "ST/ICK 64SES
                                                                                        ~65GPM_
            STEAM TO TURBINES
»
                  i
                                     ^270,000 JCFH
               BOILER
              179 MW PLANT)
                          L J"LJiE^A^f s«- J
                            ~"
                                     JNLCT
                              SCRUBBER LIQUOR
 TJQ1 £; IN TUI5 PLANT
                        OFTHF'
FLUE GASES  GO THROOSff
THE-ELECTROSTATICL PRBCIHTATOR
AND NOT THROUGH THE
SCRUBBER
                                     -3500 GPM
                                          OVERFLOW
                                                   RIVER WATER
                                                       -160 GPM
                                                                                          MAX
                                                                                       LI ME SLURRY
                                                                                       3-5 GPM
                                                                                                                FLYASH FRCM
                                                                                                        4505PM PRECIR1TATOR
                                                                                                            _   AND SERVICE
                                                                                                       -pH"   WATER DISCHAffSES
                                                                                                                           SETTUNS
                                                                                                                             POKP
                                                                                                              -50OGPM
                                                                                                                       t
                                                                                                                                   TO "RTWR
                                                                                                                                 LOSS  TO SOU.
STREA
W1METIR
PH
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ALMUN/Tr/ho
HARDNETSS
5ULFATE
SULFITE
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TS5
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UNIT
INPPfl
-'
GCO,
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PPM
PPM
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.JNLET
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WATER
2.0
3900
O
1950
4095

-------
Sanitary Wastes

The amount of sanitary waste depends upon the number of employees.   This
in turn is dependent upon the type of plant—coal, oil, or  gas,  its  size
and  its  age.   A powerplant 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 estimates for the waste  stream:

                  FLOW            BOD-5      TSS

Office/Admin.     0.095m3/day     30 g       70  g
                   (25 gpd)         (0.07 Ib)   (0.15 Ib)

Plant             0.133 m3/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:

                  FLOW             BOD-5         TSS

Office/Admin.      1.890 m3/day     635 g         1360 g
                   (500 gpd)         (1.40 Ib)     (3.00 Ib)

Plant              1.125 mVday     3480 g        7330 g
                   (2975 gpd)        (7.65 Ib)     (16.15 Ib)

Total             3.015 m3/day     4115 g        8690 g
                   (3475 gpd)        (9.05 Ib)     (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.  Moreover, the per
capita hydraulic loading  for powerplant personnel  is  relatively  small
 (25  to  35   gallons)  in comparision  to  domestic  usage   (100 to 150


                                  136

-------
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 6 Sampling Streams

Laboratory  facilities are maintained in many steam electric powerplants
to carry out chemical analysis for checking different 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.

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  require-
ments  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.

Basically,  there  are 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   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


                                 137

-------
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.21

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.21 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


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.

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  erosion  of  soil  disturbed  by the construction
activity.


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  description  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.
                              138

-------
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  thrcugh  a  series of preheaters.  Thus, in a PWR, the
primary coolant is isolated from the steam-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  bcron  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 coolant  and  let-
down.   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
                                139

-------
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 contaminated 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  M3/s   (40gpm)  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
10X 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  separa-
tion  such  as settling, filtration and centrifugi^ig  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.
                                140

-------
LIQUID RADIOACTIVE WASTE HANDLING•SYSTEM
          PWR NUCLEAR PLANT
           FIGURE A-V-H

-------
BWRs  usually use ground resin filter demineralizers  in  the  RWCS and 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 1,100MW 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 BMSs contains concentrations
much  lower  than 1 mg/1 of all chemicals other than  boric acid which is
present  at  a  maximum  concentration  of  60  mg/1.   The   anticipated
quantities of BMS discharge for a sampling of PWRs  ranges from 0 to over
5,000,000  gallons per 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  expected   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.


                                  142

-------
REACTOR)^
i—r
CLEAN-UP SYSTEM
FILTERS-
OEUIKERALIZERS «l



POWOEX PHASE
SEPARATORS (4)
1 I
                                                                                           TURBINE
                                                                                          CONDENSER
                                       CONDENSATE
                                    DEMINERALIZERS  (6)
CONDENSATE
 STORAGE
TANKS  (2)
400.000 gal.
LOW CONDUCTIVITY WASTE
EQUIPMENT DRAINS FROM
DRY WELL. RE ACTOR BUILDING
AND TURBINE BUIlttlNG ETC.
HIGH CONDUCTIVITY WASTE
FLOOR DRAINS FROM
DRY WELL ANO REACTOR.
TURBINE. AND RADWASTC
BUILDINGS. ETC.
CHEMICAL WASTE
LABORATORY DRAINS
SAMPLE DRAINS. ETC
DECONTAMINATION
DETERGENT WASTE
CASK CLEANING
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                               1100 MW  BWR NUCLEAR PLANT
                                    FIGURE  A-V-12

-------
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 radioisotopes from
waste streams, it is expected  that  most  discharges  from  radioactive
waste  systems  in  BWRs  will  contain  extremely  low  concentrations of
chemical pollutants.


Summary of Chemical Usage

Table  A-V-11  lists  chemicals  used  in  steam electric   powerplants
corresponding to various classes of uses.

Classification of Waste Waters Sources

Waste  water  sources  can  be  classified as high-volume,  intermediate-
volume,  low-volume,  or  rainfall  run-off.   Table  A-V-12  lists the
individual waste water sources according to the  above classification.
                                   144

-------
                                            Table A-V-11

                                  CHEMICALS USED IN STEAM ELECTRIC POWERPLANTS
                                          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
Thi ocyanates
Organic sulfurs
Sulfuric acid
Hydrochloric 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-12

      CIASS OF VARIOUS WASTE WATER SOURCES
     Class
                Source
High Volume
Nonrecirculating main condenser
  cooling water	
Intermediate Volume
Nonrecirculating house service water
Slowdown 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
                           146

-------
                                 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,   incineratior  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 powerpiant
which give rise to chemical wastes.  Reported  data  were  included  for
each waste stream wherever available.  The waste streams are specific to
each powerpiant 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.

Common  Pollutants

Since   powerpiant  waste  effluents  are  primarily  due  to  inorganic
chemicals, the common pollutants reflect the general level of  inorganic
chemical concentration.


                               147

-------
                                                  TABLE A-VI-1
                             APPLICABILITY OF PARAMETERS TO CHEMICAL WASTE STREAMS
PARAMETER
ALKALINITY
BOD
COD
TS
TDS
TSS
AMMONIA
NITRATE
PHOSPHOROUS
TURBID IT Y
FECAL COLIFORM
ACIDITY
HARDNESS, TOTAL
SULFATE
SULFITE
BROMIDE
CHLORIDE
FLUORIDE
ALUMINUM
BORON
CHROMIUM
COPPER
IRON
LEAD
MAGNESIUM
MERCURY
NICKEL
SELENIUM
VANADIUM
ZINC
OIL S GREASE
PHENOLS
SURFACTANTS
ALGICIDES
CHLORINE
MANGANESE
Conde
Cooli
Syste
Once
Through
X


x
X
















X











x
x


riser
ng
m
Recircu-
latinq
X
X
X
x



y
x
y


Y
X


X
X
x

X
X
X

X

X


X

X

X
X
X

Water
Treatment
Clarifi-
cation Wastes
x
X
x
x
x


X
x
V


X
X


X
X
x

X
X
X

X

X


x

X





Ion Ex-
change Wastes
X
X
X
x
X


x
X



X
X



X


X
x
Evaporator
X
X
X
x



x
X
V


X
X


X

X

X
x
X X


x i x
X
X
X
X


X
X




X

X

X
x


X

Boiler
Blowdown
X
x
X
x



x
X
X


x
X


X

x

X
X
X

X

X


x





X

Chemical
Cleaning
Boiler
Tubes
X
x
X

X


x
x.
x

X
x
X

X
x
X
y

X
X
X

X
x
X
X

X
X

X


X

Air Pre-
heater
X
X
X

x

X


x

X

X


X



X
X
X

X

X










Boiler
F ires ide
x

X

x

x


x

X

X
X

X

X

X
X
X

X

X

x






X

Ash Pond
Overflow
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

Coal Pile
[ Drainage




X

x
x
x
x

X

X

Floor
Drains


X
x
X
X



x'

X
X
X
X

1
X

x

X
X
X
X
X
x
x
X

X

X



x






X
X





X _,

x




Air Pollution
S02 Removal
X
X

x
Y
X


X
X

X
X
X
X



X



X

X



x

x




X

1 Sanitary
Wastes

x
X
X
X
X
x
x
X
x
x





X















X
X



id w
K <1)
3 01



















X






































































































































































                   NOTE:  Miscellaneous streams such as laboratory sampling,  stack chemical cleanings, etc.
                          are not included since the species are accounted for in other streams.
                                                      148

-------
                                   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
Once
Through
_
-
-
_
-
-
•
-
-
_
-
f
-
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
Treatnj
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
ent
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 1
Slowdown 1
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
-


13
-
-
-
-
-
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
2
2
2
2
2
2


-
2
2
-
'-
2
-
-
-
2
1
2
-
2
-
1
-


2
-
-
-
-
-
-
Ash Pond 1
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
SO2 Removal
1
-
-
-
1
1
-
1
1
_


_
1
2
2
_.
_
_
1
_
1
1
_
1
1


1
—


-
-
-
-
-
-


Sanitary
Wastes
-
-
-
-
-
-
-
_
_
_


•
_
_
_
_
_
_
_
_
_
—
_
—
-


_
_


-
-
_
-
-
-


TJ
(0 W
£ 0)
4-1
IS (0
SI
-
—
-
-
-
-
-
_
_
_


_
_
_
_
_
_
_
_
_
_
_
_
—
-


-
—
-
-
-
_
-
-
-







































                                            149

-------
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.

Pollutants from Specific Waste streams

Biochemical Oxygen Demand  (BOD -  5 day)

BOD  is  a  significant  pollutuant  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
                                  150

-------
pollutant in  powerplant effluents, but may be used  as  gross  indicator
for certain combined wastes.

Oil and Grease

Oil  and grease  enter  into  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 preoperational 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;
                      - floor and yard drains;

    Drainage  and misc.
     waste  streams    - 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 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.


                                151

-------
Chlorine - Free Available

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.  Chloramines  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  arid 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 as soluble components of
the residues  of  combustion  where  such residues  have  been  handled
hy dr aul ical ly -

Blowdown  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.


                                   152

-------
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 blcwdcwn or leakage from these systems.

These 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;
                          - bciler fireside
        condenser cooling
         water systems    - once through; and recirculating

    3.  Mercury

        ash handling      - coal fired plants; and coal
                             pile drainage.

    4.  Vanadium  (oil-fired plants only)

        ash handling;
        qhemical 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.
                                   153

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Phenols

Polychlorinated biphenyls  (PCS's) are  sometimes  used   as   coolants  in
large  transformers.   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,  toiler  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  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 SO.2 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
chemical cleaning of toiler 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.
                                154

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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.

Chloride and Magnesiuir

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.
                                  155

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    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.

Selection of Pollutant Parameters

The U. S. Environmental Protection Agency published   (Federal  Register,
Volume  38,  No.  199,  pp.  28758-28670,   October   16,  1973)  40 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 those excluded  for one or more  of the following
reasons:

    1.   Not harmful when selected parameters are controlled

    2.   Not present in significant amounts

    3.   Not cont rol 1 ab le

    4.   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


                               156

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                                                                       Table A-VI-3

                                                           SELECTION OP POLLUTANT PARAMETERS*
POLLUTANT PARAMETER
Acidity (as CaCO )
Alkalinity (as CaCO )
Ammonia (as N)
Biochemical oxygen demand (5-day)
Chemical oxvaen 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 Orcranics
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)4
Sulfite (as SO_)
Surfactants
Chemical additives (biocide/corr.inhib. )
CLASS OF WASTE WATER STREAMS
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**
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
1
1
2
2
9
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
 *Key: • =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        8
** Selected where technology is available to achieve no discharge
=Rejected because indirectly measured by another parameter
=Rejected because radiological pollutants are not within the
   scope of E.P.A. guidelines and standards

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                                                                     Table A-VI-3 (continued)
                                                            SELECTION OF POLLUTANT PARAMETERS *
POLLUTANT PARAMETER

Trace Metals
Aluminum— total
Ant imony— tota 1
Arsenic— total
Barium- total
Beryllium-total
Boron- total
Cadmium— total
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
CLA
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
8
8
8
8
SS OF WASTE WATER STREAMS
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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   Intermediate Volume
        blowdown from recirculating condenser cooling water systems
        nonrecirculating ash sluicing systems;
        nonreciruclating service water systems
        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
    Sanitary System
    The  selected parameters  for  the  various  classes  of  waste  water
streams  are shown in  Table A-VT-4.
                                 159

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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.
                         160

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                                 PART A

                            CHEMICAL WASTES

                              SECTION VII

                    CONTROL AND TREATMENT TECHNOLOGY


introduction

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

    IH.  Minimize the solubility of 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.

The control  and treatment  technology  for  the  discharge  of  chemical
wastes    from   a   steam  electric  powerplant  involves  one  or  more
combinations of the fcllowing techniques:

(1)   Elimination of pollutants by:
     a)   process modifications
                                161

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     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

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 blowdown (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 or  unit  shutdown.
Those  include  spent cleaning solutions  from the cleaning of the boiler
or PWR steam generator tubes, boiler  fireside,  air  preheater  and  con-
denser  cooling  system,  and  other   miscellaneous  equipment  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 Wastes

Once-through Condenser Cooling System

In the once-through systems, chlorine is  the  major  chemical  pollutant
where  it  is  added  for  biological  ccntrol.   Excess  total residual
chlorine discharge can be minimized by monitoring and  controlling  free
available  chlorine  concentrations in the  discharge stream.  Commercial
monitoring and controlling instruments are  available which  can  measure
and maintain concentrations down to 0.2 mg/1.
                                 162

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AS  shown   in   Figure  A-VTI-1,  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 0.2 mg/1 the
analyzer opens  ACS-1 which shuts down the feeder until it  is  restarted
manually or by  timer KS-1.  This type of 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  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.

Mechanical means for cleaning stainless steel condenser tubes is used in
a  few  plants   in  place of some portion of the total required chlorine
addition,  however, the  degree  of  practicability  is  related  to  the
configuration  of  the  process  piping  and  structures involved at any
station.

The substitution of stainless steel  and  titanium  condenser  tubes  in
place  of   copper  alloy  tubes  is  possible  but  is not known to have
employed solely to reduce  the  quantities  of  copper  alloy  materials
discharged.

Closed Condenser Cooling System Slowdown

In  a  closed condenser cooling system a blowdown is required to prevent
scaling of the condenser.  The significant pollutant parameters of  this
waste are  TSS,  chlorine and chromates.

The  monitoring  of chlorine in the blowdown stream can be achieved in a
manner similar to that described for the once-through system.

Further potential methods of reducing or eliminating  residual  chlorine
levels in the blowdown are as follows:
                                  163

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WATER.
SDppL-f
       ct-kLofciUA-yD(2
                         LEGEND;

                         AC-1:
                         ACS1:
                         KS-1:
 Chlorine Analyzer
 Chlorine Feeder Contacts
 Controller (Timer Optional)
 Flow Path
  Optional Flow Path
• Instrument Signal
          CHLORINE FEED CONTROL
   ONCE-THRU CONDENSER COOLING SYSTEM
           FIGURE  A-VII-1
                 164

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   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 blowdcwn 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.

An end-of-pipe treatment for  reducing chlorine levels is the addition of
reducing  agents  such  as sodium  bisulfite (NaHSO3).  Chlorine being an
oxidizing agent will  oxidize  these chemicals.  One mole of bisulfite  is
required  per  mole   of chlorine  or 1.47 mg/1 per mg/1 of chlorine.   By
maintaining a  10X 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.
A  system   of  this type is currently being installed in a nuclear plant
currently under construction.

The amounts of pollutants  discharged  in  blowdown  can  be  reduced  by
reducing  the  blowdown 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.  33*  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.

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
                                 165

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deterioration  can  be   checked   by   maintaining  the  pH   below   8.0,
Biological  attack  on   wood   is   caused  by  cellulolytic  fungi.   Bie
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 bioddes 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.

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.   Poly phosphate,
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
polyphosphates, silicates, ferrocyanides, 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 hydrolytically  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,
                                  166

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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 HJ2S or CO2.

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  tc seven.  This range depends on the balance between
corrosion    inhibition   and   deposit   control.    Phosphonates    and
polyelectrolites   are  used  as  deposit-control  agents.   A  possible
arrangement for pH control is shown in Figure A-VTI-2.

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 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.OX of suspended solids.
Accepted treatment techniques in  the  water  and  wastewater  treatment
industry  consist  of hydraulically thickening these sludges to about 10
to  15X solids content.  Following thickening, the sludges can be further
dewatered by land disposal, centrification, filtration, or incineration.
Figure  A-Vll-3  shows  two  typical  clarifier  waste  systems.   These
processes   are  discussed  in  further  detail  in  Section  A-IX.   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
                                  167

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       RIVER
       WATER
oo
 LEGEM*
AC-I
E/F-I
FC-I
    PH SEMSOR f TRANSMITTER
    ELECTROPMEUMATID
    FLOW COWTROL VALVE
    FLOW PATH
    COV1TROL S»QWAL (ELECTRICAL)
    CONTROL Sl&W/M. (rNEU»AAT»C)
                                                  SOLUTIOW
                                          RECIRCULATING CONDENSER  COOLING SYSTEM
                                                   pH  CONTROL OF SLOWDOWN
                                                        FIGURE A-VII-2
                                                                                                          BLOWfrOWN
                                           AUI> OR
                                           ALKALI  TAMK

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                CLEAR WATER  OVERFLOW  TO  RECYCLE
    PAW

  WATER,,
        aj r
            CLARIFIER
WATCB.
                                  WA5H
'«.   +
                                 WATER TO
                                 PROCESS
                    ,  SLUDGE,  ,
                   / / / / / / 7 7 7 /  7  /
   THICK-
    ENER
        SLUDGE:,
                MECHANICAL
                DE WATER ING
                                        R.&cYcL&
                                  Ul  WAjEe.1
                                  I  pg.oceg
                     SLUD6&
                        I
                                                             MOIST 50LID5
                                                               DISPOSAL
                                TO
                           TO
                                                   SOliD-b
              CLARIFICATION WASTE TREATMENT PR(XESSES

                        FIGURE A-VI1-3
                             169

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sodium hydroxide, alttough  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-4 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-5 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  for  such  uses  as ash sluicing or gas
scrubbing, which do net 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 cf 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 CaC03 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.384

Evaporator Slowdown

In those plants still utilizing evaporators to produce boiler  feedwater
makeup,  the  blowdown  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
                                  170

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 ACID ADJUSTMENT
CAUSTIC ADJUSTMENT
ION  EXCHANGE  WASTE
ai
                         RECIRCULATE
DISCHARGE
                NEUTRALIZATION
                     TANK
¥
     ION EXCHANGE WASTE TREATMENT PROCESS
                FIGURE A-VI1-4
                    171

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NEUTRALIZATION POND
       Figure A-VII-5
           172

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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  cf  the boiler feedwater must be maintained at very
high levels of purity, the blowdown 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 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. "*

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.
                                   173

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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 d0
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 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  bciler   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.

Miscellaneous Wastes

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-1.  The data of one of these, plant no. 0107,  were
                                   174

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                                      Table A-VII-1
                                 ASH POND PERFORMANCE


                       Source: Federal discharge permit applications
Plant No.

0104
0105
0106
0107
Concentration Total Suspended Solids, mg/1
Plant Intake
31
35
10
13
Effluent
22
6
3
10
-J
tn

-------
verified  by  analyses   of   samples   taken at. the site by EPA personnel.
These data are summarized in Table A-VTI-2.

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.

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 bottom 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.  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  system is
shown in Figures A-VII-6 and A-VII-7.

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 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 m3
 (35,000  gal.)  per   week.    The  blowdcwn   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-8.

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.
                                   176

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                                   Table  A-VII- 2




          SUMMARY OF E.P.A. DATA VERIFYING ASH POND PERFORMANCE, PLANT NO. 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

5.1
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
* Note: Total

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ASH SEDIMENTATION SYSTEM
       PLANT NO. 5305
        Figure A-VII-6
          178

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         LEGEND

 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   n use.  This  is now a hand
      operation to let water into lower  compartment of surge tank.
14.   Hpuse 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.
                               ASH  HANDLING SYSTEM
                                 (Plant No. 3626)
                                FIGURE A-VII-7

                                        179

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                                  WA5TE TO
                                       FLUME
                                          CHEMICAL CLEANING  WASTF5
                                                    \. BOILER TUBES
                                                   2. BOILER FIRESIDE
                                                    3 ASH POND
oc
o
OWfKFLOW
                                   100 GPM (MAX.)
                                               WASTE/
                                            NEUTRALIZING
                                               TANK
                                            50,000 GAL.
                         RECIRCULATION
                 WASTE
                 SUMP
                 2,500 GAL.
                                       ACID   CAUSTIC
                                     NEUTRALIZATION
WASTE  POND
 350,000 GAL.
      (CONCRETE)
                                                                      FLOATING 5UCTION
             WASTE POND  PUMP
             TAKES CLEAR LIQUOR
             FROM POND TO NEUTRALIZATION
             TANK  PRIOR TO DISCHARGE
PL/MP5
                                          ASH HANDLING SYSTEM
                                            OIL FUEL PLANT
                                            (Plant No.2512)
                                            FIGURE A-VII-0

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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 0.1%, a sulphur content of 3%,
and a vanadium content of 300-400 ppm.  A magnesium oxide fuel  additive
is used and  it is estimated that bottom ash is 30%, and fly ash is 70%,
of   the  total  ash  and  additives  residue.   The  following  factors
influenced the utility1s 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 at a few plants.

Coal Pile Runoff

In  areas  where  water  evaporation rates are higher than precipitation
rates, it is possible tc 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 m3  (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 initial,
potentially significantly polluting, portions of storm rainfall (say the
first 15 minutes of the  design  storm)  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.

Coal  pile  drainage with pH from 6 to 9.0, and low dissolved solids can
be pumped to an ash pcnd along with other waste streams, depending  upon
available area of the pond.
                                 181

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Runoff  from  coal  pile  with  high  acid  and   sulfate  content can be
neutralized by lime, limestone or soda ash.  Any  of  these 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-g
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   sensitive  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-10  and Figure  A-VII-11   present  a
comparison  of  lime,  limestone  and soda ash reactivities and settling
rates respectively.  For a coal  pile  runoff  containing  ferrous  iron
(FeSO4) and free acid  (H2SO4) , the overall neutralization reaction using
limestone  (CaCO3) can be represented in  the following simplified manner:

3CaCO3 + 2F6SO4 + H2SO4 + 0.5 02 + 2H20  = 3CaSO4  +  2Fe (OH) 3 + 3C02

A  method  of  collecting  and  neutralizing   coal   pile  drainage is to
excavate a channel arcund 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-12  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 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  2400  gpm.   The  filter medium is a 4  ft  deep layer of 0.4 mm
sand.  The loading is 3.5 gpm/ftz 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
                                  182

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oo
04
0)

§
       8
          1.2




          1.1




          1.0





          0.9





          0.8
       §  0.7
       o
          0.6
       c  0.5
       •H
to
-P
03
o
o
       o
       0)

       g
0.4
          0.3
          0.1



            0
          S
             CO
                                              6    7    8     9    10

                                              ACIDITY  IN  1000 MG./L
                                                                11   12
                                                                        13    14  15   16    17
                                           COST OF NEUTRALIZATION CHEMICALS

                                                  (/From  Reference 313)

                                                    FIGURE A-VII-.9

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oc
           pH 10 -
           pH  8 ~
           pH  6
           PH  4 -
                                                                    O SODA  ASH
                                                                    A LIME
                                                                       LIMESTONE
           pH  2
                 0 GRAMS 0.2     0.4     0.6     0.8
                 0       2.0     4.0     6.0     8.0
1.0  (LIME, SODA ASH)
10.0 (LIMESTONE)
                          GRAMS ADDED TO ONE LITER OF RUNOFF  -(From-Reference 313)
                             (INITIAL HOT ACIDITY = 619 MG/1)

                  COMPARISON OF LIME, LIMESTONE, AND SODA ASH REACTIVITIES
                                            A-VII-10

-------
oc>
VI
0)
tn
C
                                    U

                                    
-------
  COAL PILE
PLANT NO. 5305
 Figure A-VII-12
        186

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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 combustion.  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 floatation  unit  or  an  oil-water  separator
(Figures  A-VII-13,  14).   If  the  drains  contain high levels of TSS,
sedimentation  techniques  described  earlier  can  be  used.   An   air
floatation unit used for flooraand yard drains is shown in Figure A-VII-
15.  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-16, 17).

Air Pollution Control Scrubbing 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 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.
                                  187

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                     CYLINDRICAL AIR FLOTATION UNIT
                             FIGURE A-VII-13
61L coUecpua -r
               PjLIMAVZrf
                             SUMP*
                TYPICAL A.P.I.  OIL-WATER SEPARATOR
                          FIGURE A-VII-14
                              188

-------
OIL SEPARATOR AND AIR FLOATATION UNIT
             PLANT NO. 0610
              FigureA-VII-15
                189

-------
CORRUGATED PLATE 'TYPE OIL WATER SEPARATOR
              FIGURE A-VII-16
                    190

-------
                                          OIL
OIL WATER SEPARATOR
   FIGURE A-
        191

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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 qf
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.

Pollutant-Specific Treatment Technology

Applicable  control  and  treatment  technology  relevant  to   specific
pollutants is disciussed 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 6-7-371

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.'7s

Antimony

Solubility  data  indicates  a  potential removal of about 90 percent by
lime coagulation treatment.1*
                                   192

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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.

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.

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 metabisulf ite or hydrosulfite) , or ferrous
sulfate as reducing  agent.   Trivalent  chromium  is  then  removed  by
precipitation with line 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 reducing agent
                                   193

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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 blowdcwn,
      using metabisulfite ------ below 0.5 mg/1
    cooling tower blowdcwn,
      using metabisulfite ---------- 0*025-0.05 mg/1
    metal plating wastes,
      using metabisulfite ---------0.1 mg/1 or less
    chrome plating wastes,
      using metabisulfite --------- 0.05-0.1 mg/1

Ion  exchange  treatment  of metal finishing wastes has successfully net
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

Ion exchange removal can effect complete removal of trivalent chromium.

The U.S. Atomic Energy Commission reports total  chromate   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.
                                   194

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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.

Iron

In  general,  acidic  and/or  anaerobic  conditions  are  necessary  for
appreciable  concentrations  of  soluble iron to exist.  "Complete" 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.
                                 195

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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.

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 (Na^S)  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.   Other  methods   include filtration with adsorptive
compounds  such  as   activated  carbon  and  graphite  powder,  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.

Oil and Grease

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.  Means for oil separation from waste
water have been discussed in a  previous discussion of treatment of floor
and yard drain waste  water.
                                   196

-------
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.

Total Phosphorus (as  Pi

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
or without filtration can achieve phosphorus concentrations of 2 mg/1 or
less.   Figure   A-VII-18   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/l."*

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

No information was found concerning treatment methods for the removal of
selenium.

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.
                                   197

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2.0
  8.5
9.0
9.5      10.0      10.5



    CLARIFIER pH
                                              11.0
                                                       11.5
                        Figure  A-VII-18


          Effect of pH on Phosphorus Concentration


          of  Effluent from Filters Following

                          374
          Lime Clarifier
                           198

-------
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.

Thaliium

No information was found concerning treatment methods for the removal of
thallium  from industrial waste waters.  However, the trivalent hydroxide
is insoluble and may te 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  (IDS) 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.    Sedimentation  lagoons are commonly used at steam electric
powerplants.  Some plants employed configured tanks.  Tanks can be  used
where  space limitations are important.  Filtration is used for rainfall
runoff waste water at plant No.  3630.   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  1800 gpm  (3300 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
                                   199

-------
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  powerplants 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. Total
suspended solids can be determined  from  74  of these  samples.  See Table
A-VII-3.   The  minimum number of samples for any one plant is 6 and the
maximum number is 16.  Total suspended solids levels were 0 mg/1  in 25
samples,  10 mg/1 in 24 samples, and from 20 to  270 mg/1  in the remaining
25  samples.   Ninety-five percent  of  the samples were 70 mg/1 or lower.
The median value of the sample is 10 mg/1 and the average   (mean)  value
of  the   low  95  percent  of samples  is 15 mg/1  total suspended solids.
Flow rates range from 3,000 to 15,000  gpm and ash pond sizes from 35 to
275 acres.

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.

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
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 ----.*-  i mg/l
    metal fabrication wastes -------  0.5-1*2  mg/1
                                  200

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                                      Table A-VII-3



                    ASH POND EFFLUENT TOTAL SUSPENDED SOLIDS,  mg/1
386
Plant No.
Flow Rate, gpm
Pond Size, acres
Total suspended
solids, mg/1














0111
6,OOO
45
0
0
10
20
40
100










0112
15,000
_
0
0
0
10
10
10
20
20
30







2120
14,000
185
0
0
0
10
10
40
60
60








4701
7,000
35
0
0
10
10
10
10
10
10
10
10
30
40
40
60
70
370
4702
7,000
110
0
0
0
10
10
20
40
70
200







4703
8,000
340
0
0
10
10
10
20
30









4704
3,000
40
0
0
0
0
10
10
10
10
40







4705
5,000
90
0
0
0
10
20
160










4706
15,000
275
0
0
0
10
10
10
20
20








ro
o

-------
    metal fabrication wastes, using
      sand filtration - -----  -  ----  0.1-0.5 mg/1

Combined Chemical^Tr eatment

Precipitation

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.   The theoretical  solubilities of
copper*  nickel,  chromium,   zinc,   silver,  lead,  cadmium, tellurium and
ferric and ferrous ircn as a function of pH  are shown in Figures  A-VII-
19, 20.  At a pH  of 9.5 the  solubility of copper,  zinc,  chromium, nickel
and  iron  is  of the  order of  0.1 mg/}., or less.  Experimental values
plotted in Figures A-VII-21, 22   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.
379

A further aspect  related  to  solubility is the time for reaction.  Figure
A-VII-23 shows the change in solubilities of zinc, cadmium,  copper  and
nickel with time  for various levels  of pR.

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. 379

When  solubilizing  ccmplexing  agents are present, the equilibrium con-
stant 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
                                    202

-------
    io pr
    i.o
    0.1
>>

2
   0.01
   0.001
                     8       9      10
                         Solution, pH
II
         \2
                   Figure  A-VII-19
         SOLUBILITY OF COPPER, NICKEL, CHROMIUM,
         AND ZINC AS A FUNCTION OF  pH
j/y
                           203

-------
       u
       f
       O
       CO
          0.01
         0.001
        0.0001
Figure A-VII-20    THEORETICAL SOLUBILITIES OF METAL IONS
                       AS A FUNCTION OF pH
                                  204

-------
o>
O
in
   0.2 —
   O.I
                                                  Zinc
                          Legend

                        O  Nickel
                        D  Chromium
                        X  Zinc
                        A  Copper
                Note: Values plotted as O.I mg/1
                     were reported as zero.The
                     O.I mg/Z value is assumed
                     to be the detectable limit.
                                                                         13
8       9      10      II       12
 Solution , pH
                            Figure A-VII-21

        EXPERIMENTAL VALUES -  SOLUBILITY OF METAL IONS AS
        A FUNCTION OF pH  379
14
                                       205

-------
    0.01
                      7      8       9       10
                        pH(After 2-hr Standing)
II
12
Figure A-VII-22 EXPERIMENTALLY DETERMINED SOLUBILITIES
                OF METAL IONS AS A FUNCTION OF pH

                     Reference No. 236

                           206

-------
ov
70
/

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B 0.4
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— PH -
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8.0
8.5
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          1234  567  8
        Standing  time,  hours
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                                   0
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10
PH -
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1.0
0.4
0.2
= 10.
                                          1	l._.l.   !._]_.. I	l_.
                                                             . , »
      i  u  i  k  't J
    Standing  time,  hours
          CADMIUM
       0  1234  567  8
        Standing time, hours
             COPPER
   )  1  2  3 4  5  6  7 8

    Standing time, hours
          NICKEL
Figure A-VII-23 CHANGE  IN THE SOLUBILITIES OF ZINC, CADMIUM, COPPER, AND
               AND NICKEL PRECIPITATES (PRODUCED WITH LIME
               ADDITIONS)  AS A FUNCTION OF STANDING TIME AND
               pH VALUE.  Reference No. 236.
                                 207

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(ethylene-diamine-tetraacetic   acid) ,   could  have  serious consequences
upon the removal of metal  ions  by precipitation. 379

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  mq/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+2(pH 4.2), Fe+3(pH 4.3),  A1+3 (pH 5.2), Pb+2(pH  6.3),  Cu+2(pH  7.2),
Zn+2(pH  8.4), Ni+2(pH  9.3), Fe+2(9.5), cd+2 (pH 9.7), Mn+2 (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  availability, cost,  desired effluent  quality,
ease  of handling, reactivity,  or characteristics of sludge produced.  A
comparison of these materials is given in Table A-VII-4.  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 net 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/m3  processed/day for a 40,000 m3/day process
to about $100/m3/day  for a 2,000 m3/day process to  about  $1,000/m3/day
for a 400 m3/day process for treatment of acid mine drainage.  Operating
costs  vary  from 3 to  12  cents per 1,000 m3 (11 to 45 cents per million
gallons) per mg/1 of  acidity but are generally in the range 4 to  7  (15
to  27)  cents.380 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
                                   208

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                                      Table A-VII-4
             COMPARISON OF ALKALINE AGENTS FOR CHEMICAL TREATMENT
                                                        380
               Agent
                                               Cost, $/ unit of CaCO  equiv,
vo
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

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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 accompli she'd by
either diffused or mechanical aeration equipment.  Capital  costs  range
from  about   $2,000  for a 100 m3 flow/day process to about $50,000 fora
10,000 m3 flow/day   process.    Operating  costs  will  vary  from  10-20
percent of the total plant operating costs.380

Solids Separation

The  first step in separating the precipitated metals is settling, which
is very  slow for   gel like   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.  Flocculation 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.

Sludge Disposal

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
                                    210

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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 4 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 alsc 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 2.04 to 2.44 liters/min/sq m  (0.05 to 0.06 gpm/sq ft)
of clarifier sludge.

Solids contents from 25 to 35 percent in filter cakes  can  be  achieved
with  semi-continuous tank filters rated at 10.19 to 13.44 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 40 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 2.04 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 4.88
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 to 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
                                   211

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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  icns  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.

Evaporation 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 is suitable for recycle to almost all
water uses in steam electric  powerplants.

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  (with  treatment,  boiler blowdown) to  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 low-volume waste  water of powerplants.

Other Processes

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
                                   212

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satisfactorily overcome.  Insufficient information is available to judge
the  performance,   reliability,  costs  of membrane electrodialysis, ion
exchange,  freezing, electrochemical oxidation (of ferrous  iron),  ozone
oxidization  or  any  other  process for the treatment of steam electric
powerplant waste waters.

powerplant Wastewater Treatment Systems

Previous  sections  of  this  report  have  discussed  the   significant
parameters  of  chemical  pollution present in various 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.  Cily waste waters are segregated from nonoily waste
streams at some stations and the  oil  and  grease  removed  by  gravity
separators  and/or  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  of costs versus effluent reduction benefits, for powerplants
to   treat   separately   the   low-volume   waste   streams,    certain
intermediate-volume  waste  streams,  the high-volume waste streams, and
the waste stream caused by rainfall runoff.

The 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  discharges,  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  critica.1  aspect  of  the  design  of  a
centralized treatment facility.  For purposes of this report it has been
assumed  that  sufficient storage would be provided to store the largest
batch discharge, which in most  plants  would  be  the  boiler  cleaning
waste,  and  deliver it 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,  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
                                  213

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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  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 compatible 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 concentration  of the suspended
solids 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 no 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.
                                  214

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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 boiler 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-VTI-24, 25  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
"exemplary" 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
pollutant  is feasible for many steam electric powerplants.  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-26.

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
                                  215

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                                                                               EVAPORATION & DRIFT LOSS
                                                                                                                                       DISCHARGE
                                    BOILER SLOWDOWN
                                                         20 GPM
Figure A-VII-24  Sewage and  Waste Water Disposal for a Typical Coal-Fired Unit,  600 MW
                                                                                            378

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                                                                                     EVAPORATION & DRIFT LOSS
                                                                    CORROSION INHIBITORS -,
                                                                    CHLORINE          I  I
                                              EVAPORATOR + BOILER SLOWDOWN  220 GPM
Figure A-VII-25     Recycle of Sewage and Waste Water  for a Typical Coal-Fired Uhit,  600 MW
                                                                                                  378

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CO
                                                                                      HOPPER JETTING NOZZLES
                    EVAPORATION 4 DRIFT

                       .^ RIVER
                                                Figure  A-VII-26
                                  RECYCLE WATER SYSTEM,  PLANT NO.  2750
254

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 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.  Overflow 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.

 Several generating  stations  are  utilizing  closed-loop  recirculating
 systems  for  ash sluicing operations.  Systems of this type  are capable
 of achieving no discharge of as 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.
                                   219

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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  "once-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 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 blowdown  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 will not have  a water  surplus, but  will
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 nuirber of cycles  of concentration could  be feasible
                                   220

-------
if windage  and drift losses are minimized to eliminate  heavy  carryover
of solids to the surrounding areas.

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
limitation  guidelines.

Summary

Table  A-VIII-5  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-VIII-6  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-7 for large volume waste streams.
Table A-VII-8 for intermediate volume waste streams. Table  A-VII-9  for
low volume  waste streams, and Table A-VII-10 for rainfall waste streams.
                                  221

-------
                               TABLE a-VII-5
                               CHEMICAL WASTES
                        CONTROL S 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.
(Blowd own, chemical
Cleaning, Floor &
Yard Drains, Plant
Laboratory & Sampling)
2.
Iron 1 .
(Water Treatment,
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
& Coal Pile Drainage)
2.
3.
Vanadium 1.
(Chemical cleaning)
2.
Vanadium 1.
(Oil Ash Handling)
2.
Concentration and
e vaporat ion
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 S Precip-
itation
Ion Exchange
Adsorption
H S Treatment & /""
Precipitation 3
Ion Exchange /
Convert to Dry
Collection
Total Recycle with
Slowdown fi Pre-
Effluent
Reduction
Achievable
Neutral pH
Complete Removal
50-95%
60-90%
90-95%
95-99%
95%
Industry
Usage
Common
Not generally
in use De-
salinization
technology
Not in use
Desalinization
technology.
Not in use
Desalinization
technology .
Extensive
Moderate
Not generally
pract iced-water
treatment
technology.
Not generally
practiced-water
treatment
technology.
Ultimate Disposal Not practiced
Costs
Capital Operating
$10-20,000 (tanks, $3-30,000 (Chemicals,
feeder, etc.) labor, etc.)
$250 , 000-$ 1 , 660 , 000 $150 , 000-$450 , 000
from Table A-VIII-5; from Table A-VIII-6;
costs are signifir costs are significantly
cantly less in areas less in areas where
where evaporation evaporation ponds are
ponds are feasible, feasible.
50-SO 
-------
                                                       Table A-VII-5
                                                        CHEMICftL WASTES
                                                 CONTROL S TREATMENT TECHNOLOGY
                                                                                 (continued)
Pollutant Parameter
Chlorine
(Once-through Con-
denser Cooling)
Chlorine
(Recirculating)
Aluminum/Zinc
(Water Treatment,
Chemical Cleaning,
Coal Ash Handling,
Coal Pile Drainage)
Oil
(Chemical Cleaning,
Ash Handling, Floor
s Yard Drains)
Phenols
(Ash Handling, Coal
Pile Drainage, Floor
s Yard Drains)
Sulfate/Sulfite
(Water Treatment,
Chemical Cleaning,
Ash Handling, Coal
Pile Drainage, SO
Removal)
Control and/or
Treatment
Technology
1. Control of Residual
C12 with automatic
instrumentation
2. utilize mechanical
cleaning
1. Control of Residual
Cl with automatic
instrumentation
2. Reduction of Cl
with sodium
bisulfite
1. Chemical Precip-
itat ion
2. ion Exchange
3. Deep Well Disposal -
1. Oil-water Separator
(Sedimentation
with skimming)
2. Air Flotation
1. Biological
Treatment
2 . Ozone Treatment
3. Activated Carbon
Ion Exchange (Sulfate)
Oxidation £ Ion
Exchange (Sulfite)
Ammonia 1. Stripping
(Water Treatment,
Slowdown, Chemical
Cleaning, Closed
Cooling Water Systems)
2. Biological
Nitrification
3 . Ion Exchange
Oxidizing Agents
(Chemical Cleaning)
BOD/COD
(Sanitary Wastes)
COD (Water Treatment
Chemical Cleaning)
Fluoride
(Chemical cleaning)
Neutralization with
reducing agent and
precipitation where
necessary.
Biological Treatment
, 1. Chemical Oxidation
2 . Aeration
3. Biological Treat.
Effluent
Reduction
Achievable
Control to
0.2 mg/1
Eliminates
Cl discharge
Industry
Usage
Costs
Capital
Operating
Limited usage in $5,000 Negligible'
the industry-
Technology from
sewage treatment
practiced in some No Cost Data Available
plants -a 11 systems
are not capable of
being converted to
mechanical cleaning .

Below detect-
able limits
Removal to
1.0 mg/1
Similar to
Copper
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
75-95%
50-90%
Removal to
2 mg/1
80-95%
Neutral pH &
^95% removal
85-95%
85-95%
85-95%
85-95%
Chemical Precipitation Removal to
1 mg/1
Being installed in No Cost
a new nuclear
f ac ility ; however
excess NaHSO is
discharged.
Limited usage

Common usage
Limited usage
Not practiced
in the industry.
Not practiced
in the industry.
Not practiced
in the industry.
Not practiced
in the industry.
$500-$3000/1000 gpd

$1,500-$ 15, 000
based on 500 gal/MW
25-400 MW range
$5,000-$50,000
$150-$2800/1000 gpd
No data
$50-$ 350/1000 gpd
Data Available
10-1804/1000 gal.

No data
No data
224/1000 gal.
No data
44-154/1000 gal.
Total cost of $2.00/1000 gal.
Not practiced? Total cost - 34/1000 gal.
several installa-
tions in sewage
treatment
Not practiced for No Data Available
these waste' streams
Not practiced Total cost - IOC/1000 gal.
Limited usage
Common practice
Limited usage
Not practiced
Not practiced
Limited usage
No Data
$25,000-$35,000
NO Data
No Data
No Data
Available
Negligible
Available
Available
Available
Total cost - 10-504/1000 gal.
 Boron
(Low Level  Radwastes)
                     Ion Exchange
Removal to
  1 mg/1
                                                  223
Not generally
pract iced-rad io-
active material would
concentrate on ion
exchange resin requir-
ing inclusion in solid
radwaste disposal
system.
                                                                                   No
                                                                                             Data
                                                                                                        Available

-------
                                                      TABLE A-VII- 6

                                                PLOW RATES-CHEMICAL WASTES
Waste Stream
Condenser Cooling Water
Once-Through

Recirculating

Water Treatment
Clarification
Softening
Ion Exchange


Evaporator


Boiler Slowdown

Chemical Cleaning
Boiler Tubes


Boiler Fireside
Air Preheater
Misc. Small Equip.
Stack
Cooling Tower Basin
Ash Handling

Drainage
Coal pile



Reported Data
Waste Flow or Volume



20-7200 x 103 GPD


No Discharge
No Discharge,
1-533,00 x 10 GPD

-3
0.1-1060 x 10 GPD


0.05-1120 x 103 GPD


3-5 Boiler Volumes


24-720 X 10 GAL.
43-600 x 103 GAL.
No reported data
No reported data
No reported data
5-32,000 x 103 GPD

c
17-27 X 10° GAL/YR.



Typical
Frequency Flow or Volume Basis

500-1500 GPM/MW

Varies from 0,3% to 4% of
curculating water flow.


52-365
cycles/yr .

300-365
cycles/yr.

25-365
cycles/yr.

once/7 mos.- 1 boiler vol. per Frequency-once
once/100 mos. 1-2 hrs. -Boiler per 24-30 mos.
draindown time.
2-8/yr. 300,000 GAL. 5/yr.
4-12/yr. 200,000 GAL. 6-12/yr.
-





Dependent Reported data
on rainfall based on 43-60
inches of rain
year.
Remarks

Flow reported in FPC
Form 67.,
Blowdown depends on wate:
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.







Cleaned infrequently
Cleaned infrequently
Overflow from ash punus
reported in FPC Form 67.

Flow dependent upon
frequency, duration and
intensity of rainfall

  Floor & Yard Drains   No reported data
Air Pollution Control   No Discharge
  Devices
                                                                                                  Flow dependent upon fre-
                                                                                                  quency  & duration of
                                                                                                  cleaning and stormwater
                                                                                                  runoff.
Misc. Waste Streams
  Sanitary Wastes
                        No reported data
                                                              25-35 gal/capita/ Personnel:
                                                                day             operators-1 per 20-40 MW
                                                                                maintenance-1 per 10-15 MW
                                                                                administrative-1 per 15-25 MW
Plant Laboratory and    No reported data
  Sampling

Intake Screen Backwash  No reported data
Closed Cooling Systems  No reported data

Low Level Rad Wastes    No reported data




Construction Activity   No reported data
5 gal./day
                                                    224
                                    Nominal, variable flow
                                                                                                  Guideline requires col-
                                                                                                  lection  & 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-7
                               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,
                           [mill/tea]  / [mg/l]effluent concentration
ro
ro
en
        Chlorine-free available

          Uncontrolled addition(S)
          Controlled addition(S)   less than
          Shutdown mechanical cleaning(S)
          On-line mechanical cleaning
          Chemical addition treatment*(N)
          Alternative biocide use*(N)
       Copper
          Present system(C)
          Alternative condenser
          tube 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
          Symbols   CT
                    PT
commonly employed            N
currently transferrable      S
potentially transferrable    *
= net known to be practiced
= some usage
= may substitute one pollutant
    for  another

-------
                                              Table A-VII-8
                                      COSTS/EFFLUENT REDUCTION BENEFITS
                    CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS OTHER THAN HEAT
                                  -INTERMEDIATE VOLUME WASTE  STREAMS-

           Waste Streams: 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
          Cost / Effluent Reduction Benefit,
     [mill/KWH] / [mg/l]         concentration
 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 subst itut ion*(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)
    Coneutralizat ion(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)
.Chromiuai-total
  'present system  (S)
    Chemical treatment (CT)
    Chemical substitution (PT)
Zinc-total
    Present system  (S)
    Chemical treatment (CT)
    Chemical substitution (PT)
           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
     (SI/1000  gal)/0.2
         Unknown

           Base
          0.05/1
         Unknown
 Meaning of     C = commonly employed
   Symbols     CT = currently transferrable
               PT = potentially transferrable
N = not known to be practiced
S ='some usage
* = may substitute one pollutant
      for another
                                           226

-------
                          Table A-VII-9
                  COSTS/EFFLUENT REDUCTION BENEFITS
CONTROL AND TREATMENT TECHNOLOGY FOR POLLUTANTS CITHER THAN HEAT
                    -LOW VOLUME WASTE STREAMS-
    Waste Streams:
Slowdown from recalculating 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,
Water treatment
                                                                     etc.
      Technology / Pollutant
                              Cost / Effluent Reduction Benefit,
                        [mill/KWH] , [mg/1] ...           .   . .
                                   '       effluent concentration
  Present System(C)

  One-Stage Chemical Treatment(S}

       Copper-total
       Iron-total
       Heavy metals in general
       Oil and grease
       pH value
       Total Suspended Solido
       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
                                         10 mg/...
                                      6.0 to 9.0
                                         15 mg/1
                                   significant reductions
                          0.1  mill/KWH

                                        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
                          0.5  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
                                      227

-------
                                    Table A-VII-10
                            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
ro
ro
oo
Present System(C)
Conventional Solids Separation(S)

     Oil and grease
     pH value
     Total suspended solids

One-Stage Chemical Treatment of
  First 15 Minutes 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)
                                           Cost / Effluent Reduction Benefit,
                                     [mill/KWH] , tmg/l]         concentration
         Base

0.01 mill/KWH

            no reduction
            no change
               15 mg/1


0.01 mill/KWH
               10 mg/1
            6.0 to 9.0
               15 mg/1
          significant reductions

unknown


unknown
Meaning of
  Symbols
                         C = commonly employed
                        CT = currently trans ferrable
                        PT = potentially transf errable
       N = not known to be practiced
       S = some usage

-------
                                 PART A

                            CHEMICAL WASTES

                              SECTION VIII

              COST,  ENERGY AND NON-WATER QUALITY ASPECTS


Introduction

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.

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 chemical
wastes.   Two   equalization basins provide separate storage for oily and
oil-free wastes.  The main treatment unit is a clarifier; lime is  added
to raise  the  pH to  a  level  at which most of the metallic ions are
precipitated.  A flocculant is added to assist in the precipitation.

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
                                   229

-------
often  significant.   A  substantial  amount  of  data   is available on
chemical feeders.

Two cost analyses are presented.  The first cost analysis   is   based  on
the concept of a central treatment plant as shown in Figure A-VIII-l for
all  low-volume  waste  waters containing chemical  pollutants.   Table A-
VIIl-1 shows the design flows assumed for this plant.   The second cost
analysis  is  based  on  the  concept  of complete  treatment of chemical
wastes with no discharge of pollutants.

Tables A-VIII-2, A-VIII-3, and A-VIII-4  contain  estimates of  capital
costs,  operating costs and annual and unit costs for a central chemical
waste treatment.  Estimates are presented for three sizes  of powerplants
with generating capacities of 100 MW, 500 MW and 1000   MW   respectively.
The  unit  cost  of  treatment is computed under three  assumptions as to
plant capacity factors.  The first assumption is a  capacity  factor  of
1.0, representing continuous operation at full capacity.   Unit  costs are
also presented for capacity factors of 0.67, representative of  base load
plants,  and  0.35,  representative  of  cycling  plants.   Under  these
assumptions and conditions, the cost  of  treating  chemical  wastes  is
found to vary from 0.05 mills per KWH to 0.38 mills per KWH.

Wastes not Treated at Central Treatment Plant

The  following  wastes  are  not  considered suitable for  treatment 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,  and
once-through  (nonrecirculating) house service water.

Cost  factors  applicable to the treatment of these wastes are  discussed
in the following paragraphs.  None of the  costs  are   of   a  sufficient
magnitude  to  result  in  a  detectable  increase  in   the unit cost of
generation.

Cooling Water-Once Through Systems

The  treatment  technology  for  once-through  condenser  cooling  water
systems  consist  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.
                                   230

-------
Ufc. i SAMPU1& 5TWW»



* r






pll- 6* _





eouALiTATioil
TAUK.
teoo«*l/M*)

O.'OTSM'/C
( 19 GPD/K
                                             UAt *01L PIB6D PLAM1%)
                                                                                                                                              PTtoWAL PATtJ FOB COAL flB6D
                                                                                                                                                      poe. COST
                                                                            CHEMICAL rfASTES-IENTRAI, TREATMENT PLANT


                                                                                        FIGDBE A-VIII-1

-------
                                             TABLE A-VIII-1
                            DESIGN FLOW  FOR CHEMICAL WASTES TREATMENT PLANT

Waste Stream


Ion exchange
Evaporator blowdown
Boiler blowdown
Boiler tube cleaning
Boiler fireside cleaning
Air preheater cleaning
Misc. small equipment
& stack cleaning
Cooling tower basin
Lab. & sampling streams
Average Volume per day-MW

Frequency


Daily
Daily
Daily
I/year
2 /year
6 /year

2/year
2 /year
. Daily

Total Volume/MW
m3


0.333
0.208
0.137
0.34
6.06
15.9

-
-
-

Assumed Design
Gal


88
55
52
90
1600
4200

-
-
-


Average Volume
Per Day-MW
m^

0.333
0.208
0.197
-
0.017
0.044

0.004
0.004
0.044
0.847
0.88
Gal

88
55
52
0.25
4.44
11.7

1.11
2.11
10
223.61
230
ro
CO
ro

-------
                                          TABLE A-VIII-2

                                      ESTIMATED CAPITAL COSTS
                                  CHEMICAL WASTES TREATMENT  PLANT
CO
Descriotion

Equalization tank
Treatment tank
Holding tank
Clarifier
Filter
Pump
Piping
Ma jot equipment cost
Installation cost @50%
Instrumentation cost @20%
Total construction cost
Engineering (§>15%
Contingency @>15%
Total capital cost
Powerplant Generating Capacity
100 MW
$ 42,500
4,700
3,400
7,000
32,000
3,200
3,200
$ 94,000
47,000
18,800
$159,800
24,000
24,000
$207,800
500 MW
$124,000
6,800
7,900
16,000
40,200
2,000
3,200
$201,100
100,500
40,200
$341,800
51,300
51,300
$444,400
1000 MW
$248,000
7,800
9,400
22,000
61,000
2,500
7,900
$359,400
179,700
71,900
$611,000
91,700
91,700
$794,400

-------
                                         TABLE A-VIII-3

                                ESTIMATED ANNUAL OPERATING COSTS
                                 CHEMICAL WASTES TREATMENT PLANT
Description
Chemicals and Power
Requirements :
Lime
Flocculants
Electricity
Annual Costs:
Operat ing labor
Lime
Floccularit
. Electricity
Annual Operating Cost:
Exclusive of labor
Including labor
Units
tons/year
Ibs/year
HP
$15,000
$27/ton
$0.05/lb
12 mils/KWH

Powerplant Generating Capacity
100 MW
54
4200
10
$75,000
1,500
2,100
900
$ 4,500
$79,500
500 MW
275
21.000
30
$105,000
7,400
10,500
2,600
$ 20,500
$125,500
1000 MW
550
42,000
75
$135,000
15,000
21,000
6,500
$ 42,500
$177,500
ro

-------
                                       TABLE A-VIII-4


                               ESTIMATED ANNUAL AND UNIT COSTS
                               CHEMICAL WASTES TREATMENT PLANT
ro
CO
in
Description

Total capital costs
Fixed charges @15%
Maintenance @3% of construction cost
Annual operating cost excluding labor
Operating labor
Total annual costs :
t
Unit costs, mils/KWH of
Generating capacity
Production (base load)
Production (cycling plant)
Powerplan
100 MW
$207,800
31,200
4.800
4,500
75,000
$115,500
0.132
0.200
0.377
t Generating
500 MW
$444,400
66,700
10,300
20,500
105,000
$202,500
0.046
0.07
0.14
Capacity
1000 MW
$794,400
119,200
18,300
42,500
135,000
$315,000
0.036
0.054
0.11

-------
Cooling Water Slowdown - 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.

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.   The  installed cost of
these  plants  is  estimated  to  be   $25,000   -  $35,000  depending on
geographic location.

Coal Pile Runoff

The   cost   of  coal  pile  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-2.  Costs for  liming  contents of pond  will  vary
with pH and frequency of treatment.

Intake Screen Backwash

The  incremental  cost  of  land  disposal of  debris removed from intake
screens would be very insignificant in most  Ceases.

Radwaste

No  treatment  is  assumed  due  to   possible    hazardous   effects  of
concentrating radioactive wastes.

Nonrecirculating Ash Sluice Water

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.
                                  236

-------
  140
  120
T
100
o
Q

O
o
o
 80
4J
to  60
o
u
•P
•H
ft

3 40
  20
©
0
©
             Storage Capacity of Pond in

             Terms  of Runoff from Pile Area
                 1.25 cm (0.5")
               3.75 cm  (1.5")
                 7.5 cm (3")
               10
               I
                        20
                        30
               400       800      1200

                      Area of Coal Pile
40
                                           1606
50   acres
                                           2000  hm2
               COST FOR COAL PILE RUNOFF COLLECTION

                      FIGURE A-VIII-2
                         237

-------
The backfitted configured recirculating  ash sluicing system at plant No.
3630  cost approximately 3 million dollars  to handle the bottom ash from
coal burned 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  dendneralizer  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.

Complete Treatment ^.of Chemical Wastes for Reuse

Costs  associated  with  the  complete   treatment of chemical wastes for
reuse within the plant will vary  from  plant  to plant.   In  order to
arrive  at  an  estimate  of  typical  costs likely to be incurred by an
existing plant in implementing a  complete water  reuse  plan,  conceptual
flow diagrams have been developed for such  plans for coal-fired and oil-
fired  powerplants.   These  flow diagrams  are shown jji Figures A-VIII-3
and A-VTII-4.  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.

Tables  A-VIII-5,  A-VIII-6  and  A-VIII-7   contain estimates of capital
costs, operating costs,  and  annual  and  unit   costs  for  a  complete
treatment  system  for  chemical  wastes.   This system will produce no
discharge of pollutants while returning  the water  to  the  process  for
reuse.   The costs shown in these tables 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  will  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  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 and the  assumption of a unity
capacity factor, for  a  100 MW plant and  0.11 mills  per KWH for  a  1,000
MW  plant.  For a typical base load plant operating at a capacity factor
of 0.67, these costs  increase to  0.45 mills for  a 100 MW plant and  0.17
mills  per KWH for a  1,000 MW plant.  Costs for  a typical plant operated
                                   238

-------
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RRCY£I£ AND REUSE OF CHEMICAL HASTES


           FIGURE A-VIH-3

-------

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                                                    FIGURE  A-VIII-4

-------
       TABLE A-VIII-5

   ESTIMATED CAPITAL COSTS
TREATMENT OF CHEMICAL WASTES
Description
Cooling tower blowdown treatment
Ash -hand ling system modifications
Brine concentrator
Evaporator
Major equipment cost
Installation cost @60%
Instrumentation d>20%
Construction cost
Engineering d>15%
Contingency @15%
Capital costs:
Reuse facilities
Waste treatment plant
Total capital cost
Powerplant Generating Capacity
100 MW
$ 36,300
10,400
77,000
40,000
$163,700
98,200
32,700
$294,600
44,200
44,200
$383,000
207,800
$590,800
1000 MW
$121,300
37,000
460,000
.250,000
$868,300
521,000
73,400
$1,562,700.
234,300
234,300
$2,031,300
794,400
$2,825,700

-------
                                            TABLE A-VIII-6
ro
                                  ESTIMATED ANNUAL OPERATING COSTS
                               TREATMENT OF CHEMICAL WASTES FOR  REUSE
Description
Chemicals and Power
Requirements :
Lime
Flocculants
Electric Power
Steam
Annual Costs:
Operating Labor
Lime
Electricty
Steam
Flocculants
Total Operating Cost:
Excluding labor
Including labor
Units
tons/yr
Ib/yr
HP
10 J Ib/yr
Unit Cost
$15,000
$27/ton
12 mils/kwh
1 mil/lb
$0.50/lb
Powerplant Generating Capacity
100MW
80
4,200
140
8,760
$135,000
2,200
12,300
8, gOO
2,100
$ 25,400
$160,400
1000MW
800
42,000
1,100
87,600
$270,000
21,600
96,400
87,600
21,000
$225,600
$495,600

-------
           TABLE A-VIII-7
    ESTIMATED ANNUAL AND UNIT COSTS
TREATMENT OF CHEMICAL WASTES FOR REUSE
Description
Total capital costs
Fixed charges @15%
Maintenance @3% of construction cost
Annual operating cost excluding labor
Operating labor
Total annual costs
Unit costs, mils/KWH of
Generating capacity
Production (base load)
Production (cycling plant)
Powerplant Generating Capacity
100 MW
$590,800
88,600
13,600
25,400
135,000
$262,600
0.30
0.45
0.86
1000 MW
$2,825,700
423,900
76,200
225,600
270,000
$995,700
0.11
0.17
0.32

-------
in the cycling mode at a capacity  factor  of  0.35 are  about  0.86  mills
and  0.32  mills  respectively.    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 Requirements

Energy requirements fcr 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 pollutant,  the 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 0.2X of the
plant output.  For plants capable  of achieving no discharge by utilizing
evaporation ponds, energy requirements are  about  0.04%  of  the  plant
output.

Ultimate Disposal of Brines and Sludges

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 proportion 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  seme  of  the dewatering  and  ultimate  disposal
techniques applicable to steam electric powerplants.

Conveyance to Off-Site Disposal

Conveying brines and sludges to off-site  disposal facilities is a method
of ultimate disposal provided that the wastes have been concentrated  to
                                   244

-------
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
mosi economical means  for  quantities in excess of 100  m3  (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 m'-'km ($0.05 - $0.50  per 1000 gal - mile) exclusive  of
disposal   charges   by  the  receiving  agency,   '*»   These  costs  are
sufficiently high to make  conveyance economically unattractive except at
sites having no alternate  means of disposal.

Evaporation Ponds  (Jiagoons)

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  }ined to  prevent seepage into the ground.   Multiple
ponds  are  usually  provided  to  allow evaporation from one pond while
other ponds are receiving wastes.  Facilities must also be  provided  to
remove solids accumulated in  the pond.

Landfill

Landfills  are  the   nrost  common  method of disposal of solid residues.
However, leachate  from chemical wastes deposited 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*.

Intermediate Dewatering  Devices

A number of devices  are  available for  the  intermediate  dewatering  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/m2   (12
to 25   in. 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.
                                  245

-------
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 pricr 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.  182

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 cominon 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 cf 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.
                                   246

-------
                                 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.

Chlorine  concentrations  in  both  recirculating  and  nonrecirculating
cooling water systems are to be limited to average concentrations of 0.2
mg/1  during  a   maximum  of  one  2-hour  period  a  day  and  maximum
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.  Furthermore,  Chlorination  of
individual  units  should be applied at times of lowest flow through the
condensers  to minimize  the  total  amounts  (mass)   of  total  residual
chlorine  discharged.   Generally  Chlorination is not required 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   cf  reducing  the  total  residual  chlorine  in
nonrecirculating   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  dn  nonrecirculating  condenser
cooling   water systeirs  by  chemical  treatment is available but is not
generally practicable because of the additional costs involved to  treat
the large volumes of water involved.

    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.
                                  247

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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 where cooling towers are planned,  design for corrosion  protection
can  eliminate the need for chemical additives for corrosion protection.
Treatment of cooling  tower blowdown for  oil  and  grease  removal,  by
chemical  addition  fcr  effluent  pH   ccntrol, and by sedimentation for
reduction of effluent total suspended  solids  is  achievable.   Effluent
levels  of 10 mg/1 oil and grease and  15 mg/1 total suspended solids are
achievable based on the treatment of similar waste waters.  Due to wide
range  of  flow of waste water from recirculating cooling water systems,
the effluent limitations in mass  units,  in any particular plant would be
the products of the flow   times   the   respective  concentration  levels.
Costs  in  general would be approximately  0.1 mill/kwh in the relatively
small number of cases where it would be needed.

Limitation for 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 can be practicably treated collectively by
segregation from higher volume  wastes,  equalization,  oil  separation,
chemical addition, solids  separation,  and  pH adjustment.

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  10 mg/1. Addition of sufficient chemicals to
attain a pH level in  the range 9  to 10 and total suspended solids of  15
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 15  mg/1, the greater the effluent
                                   248

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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  15  mg/1.
Effluent  daily average concentrations of levels of 1 mg/1 total copper
and 1 mg/1   total   ircn  are  achievable  by  the  application  of  this
technology.    The   effluent  limitations in mass units, in any particular
plant,  would be the products of the collective flow   of  all  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  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.

Limitations for Once-Through Ash and Air Pollution Control Systems.

Daily average  effluent total suspended solids  levels  of  15  mg/1  are
practicably  attainable  as   are  oil and grease levels of 10 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 15 mg/1 total suspended  solids
times  the   waste   water flow would, in many of those cases, require the
removal of  large  quantities  of suspended solids not added by the  plant.
In the  light of this, an effluent total suspended solids level for these
streams  should be  limited to a daily average of 15  mg/1 times the waste
water flow  or  a number of pounds per day not  in  excess  of  the  total
intake  to   the  station  for  these  systems,  whichever represents the
greater number of  pounds per day.

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.
                                   249

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Limitations for Rainfall Run-off  Waste  Water Sources.

Rainfall run-off waste water  sources  include  coal-pile  drainage,  yard
and  roof  drainage, and run-off  from construction activities.  Effluent
limitations reflect the  technology   of  diking,   oil-water  separation,
solids separation, and neutralization.

Best Available Technology Economically  Achievable.

The  best available technology economically achievable for all plants is
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.

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 ash
sluicing and wet scrubbing are relatively low, some  degree  of  re-use
should  be  practicable  for  most plants  where  these  operations are
employed.  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, 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.

Maximum effluent reductions are attainable by segregating the initial 15
minutes of run-off from a rainfall event  from  the  remainder  of the
run-off, and by treating both streams separately, each stream to achieve
effluent  levels  of  15  mg/1  total  suspended  solids, 10 mg/1 oil and
grease and a pH value in the  range of 6.0 to 9.0.  Chlorination programs
to achieve no discharge of total  residual  chlorine  from  recirculating
cooling  water  systeirs,  while   not  currently  demonstrated,  could be
applied by 1983.
                                  250

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New  Source Standards.


In view  of the current technical risks associated with  the  application
of distillation technology to waste water recycle, chlorination programs
to  achieve   no  discharge of total residual chlorine from recirculating
cooling  water systems, and segregation of rainfall run-off streams,  new
source performance standards have been determined to be identical to the
limitations  prescribed for best practicable control technology currently
available with  the  following  exceptions.  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 total residual chlorine or  other
additives for  biological control in main condenser tubes, based on the
availability of mechanical systems to achieve biological control in main
condenser tubes.   No discharge of pollutants from  nonrecirculating  ash
sluicing system,  based  on  the  availability  of  dry  systems and of
recirculating wet systems.

Cost of  Technology.
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 (from 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, toiler fireside chemical cleaning volumes vary from  2ft,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.

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,  equalization,  chemical
precipitation, solids separation, and further based  on  generalizations
with  respect  to  the  cost of land, construction, site preparation and
                                  251

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with respect to the waste water volume,  indicate  an approximate cost of
0.1  mill  per  kilowatt  hour  depending   upon   the  plant's 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,  cooling  tower blowdown, 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
increlemental 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 $1/1000 gal treated.  Incremental costs of dry
ash  handling  systems  where  mechanically  feasible are less than 0.01
mill/kwh for existing stations  converting from   wet  systems  and  are
considerably less for new sources.

Recirculating ash sluicing systems  require sedimentation discussed above
plus  pumps,  piping  and  a  blowdown   system.   Incremental costs above
sedimentation are less  than  0.01  mill/kwh   for  existing  plants  and
considerably less for new plants.

The  cost  of  evaporation  in configured  equipment is approximately 1.4
dollars/1000 ga!J..  The corresponding  incremental  cost  in  mills/kwh is
related  to  the quantities of waste  water requiring evaporation.  Costs
would be significantly less in climates  where solar evaporation in ponds
could be employed.

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, even in the case where  new or old copper alloy
condenser tubes were retrofitted, due to  the high  offsetting  salvage
value of copper.  Replacement of existing  cooling tower components would
be more expensive however.

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
                                  252

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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  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  blcwdown  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 of
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  pol-
lution control systems.  Non-solar evaporation is further assumed.

The   incremental  costs  for  achieving  no  discharge  of  pollutants,
exclusive of cooling  water and rainfall run-off, for the  model  station
as previously  stated  are approximately 0.3 mills per kilowatt-hour for a
100 megawatt capacity base-load plant, 0.5 mills per kilowatt-hour for a
cyclic plant and 1.5  mills per kilowatt-hour for a peaking plant.  These
costs   are about  5,  6, and 12 percent of production costs, respectively.
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 require-
ment   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.

Energy 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,
which   may   be required  to attain the effluent reductions required for
best  available technology economically  achievable  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.  Jn most cases
                                  253

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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.
                                   254

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                                 PART B

                           THERMAL DISCHARGES

                               SECTION V

                         WASTE CHARACTERIZATION
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 generating unit is expressed as its  heat
rate,  in  units   of   Joules  per KWH (BTO per KWH) .  A new fossil-fired
generating unit may  be designed for a heat rate of  9.5  million  Joules
per  KWH   (9000 BTU/KWH) .   Since  one KWH is equivalent to 3.6 million
J/KWH (3413 BTU),  such a plant would have an efficiency of 38X.

The transfer of heat  from the condensing  steam  to  the  cooling  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 eco-
nomic constraints.  It  is  also  clear,  however,  that  a  temperature
difference reduction  does not limit the amount of heat rejection.

Quantification of  Main Condenser Cooling Characteristics

The data presented below were obtained .from the Federal Power Commission
and  represent a  summary of the data collected on "FPC Form 67" for the
year  1969.28°  These  data have been screened  to  eliminate  obvious  in-
consistancies.  The   statistical  analyses  have  been  performed using
standard subroutines  available from IBM in their  scientific  subroutine
package   (1000)  operating  units.  All units in this sample are fossil-
fueled.  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  (2700  BTU/KWH).   These  statistics  are  not
weighted by generation.  Weighted figures show the national average heat
rate  to  be   about  seven (7)  percent lower.2a* Given the heat rate, one
                                 255

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                CONDENSER  DELTR T  (DEC.  F)


       UNIT  CONDENSER  DELTR  T
                       FIGURE B-V-1


                         256

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                          FIGURE B-V-2


                            257

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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,$00,000
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 cf  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 FJ 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.280 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-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  visited 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
                                  258

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                                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 KWH x 10"6 (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)
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                MflX. 0UTFRLL  TEMP.  (DEC. F)




       MRX,   SUMMER   OUTFRLL   TEMP0
                        FIGURE B-V-3



                         260

-------
                                                   TABLE B-V-2


                                             PLANT VISIT THERMAL  DATA
ro
cr,
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
(MW)
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
Joule s/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
I
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
Joules/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


     N/A  - Not Applicable

-------
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. *«l 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  eld, 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.

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 cycre has efficiency limitations
beyond certain  temperatures.    Thus,  utilities  economically  optimize
temperature  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   outfall
temperature  may   be significant but move in opposing directions.  That
is, when the ambient temperature, the maximum  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 efficiency  loss  is  of  particular
concern  since  peak demand usually coincides with the worst  (for power
generation) ambient  conditions, which can cause power  shortages.   Con-
                                     262

-------
versely, the wintertime heat rate (usually better than summer) 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 temperature rise may be higher in the winter,  it  can
be  controlled  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  effluent  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
indicates*8** however, that there has been no heat rate improvement on a
national basis  for  over a decade.  Therefore,  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 larger new units are base loaded.  Temperature rise is
not significantly   affected by age  (Figure B-rV-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 sirall 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 50% more heat to the cooling water per KWH
than fossil plants.  Fossil-fueled plants reject from 10% to 20X 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 18X to 43X 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 34X  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)281-   Thus,
                                   263

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                                            LEGEND

                                   CO RLL  UNITS  IN INVENTORY
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                  UNIT RGE IN  TERRS
        DELTfl  T   VS   UNIT  RGE
                             FIGURE B-V-4


                             264

-------
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 5036 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  nraximum 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 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   (12,494  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  4.72 million Joules per KWH (4,480 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) .
                                   265

-------
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              HERT  RRTE (BTU/KW-HR)         *102


       BRSE  UNIT  HERT  RRTES


                          FIGURE B-V-5


                           266

-------
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                            FIGURE B-V-6


                              267

-------
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                        FIGURE B-V-7


                          268

-------
Condenser temperature rise does not vary  with  industry  categorization
(for  fossil  units) .   The  mean  for  all three groups  (based on hours
operated per year)  is about eight to nine degrees C   (15-16  degrees  F)
with  a  standard deviation of a little under three degrees C  (5 degrees
F).   (See Figures B-V-8, B-V-9, and B-V-10) .

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  characteristic
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 155 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-U.  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.
                                   269

-------
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        CONDENSER DELTfl T  (DEC.  F)
                                           28.00
                                                  32.00
       BRSE  UNIT  CONDENSER  DELTfl  T
                         FIGURE B-V-8

                           270

-------
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      CYCLING   UNIT  CONDENSER  DEL   T





                        FIGURE B-V-9



                        271

-------
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        PERKING   UNIT   CONDENSER   DEL   T
                              FIGURE B-V-10


                                 272

-------
                                         Table  B-V-3
                 TYPICAL CHARACTERISTICS OP WASTE HEAT REJECTION
Grouping
Nuclear
Fossil (Nat-
ional Average)
Reference 281
High Utilization
Intermediate
Utilization
Low Utilization
^.Heat Rate,
Joules/KHW
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 - 10.7
0.53 - 1.43
Temperature Rise,
°C
10 - 16

8.6

4.5-13

4.5-13
4.5-11
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      * Note: Calculated by method discussed in this section for fossil-fueled  plants

                and from Table B-V-2 for nuclear plants.

-------
                                        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 Slowdown
(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"
6,290
66*
55
13
1
3 max
ro
        * Note:  175 x  10   Btu/hr during plant cooldown once a year.

-------
                                 PART B

                           THERMAL DISCHARGES

                               SECTION VI

                    SELECTION OF POLLUTANT PARAMETER


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  waterbody,  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 or  heat  content of the condenser cooling water is determined as
follows:

        U = m  x  c x  T
                 KW

    Where    U  =  increase in internal energy of
 condenser cooling water
                                  275

-------
         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) of cooling water, c = 4.186J/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 = 4.186 x  10 J/Kg/°C (1 BTU/lb°F)

    The resultant internal energy increase is:

         U = 2.72 x 10 (4.186 x 10 )  (11.1)   = 5626 x 10 J/KWH
              225 x 10

    or in English units:
       U = 6JL10_x_iO _m_L20l =533  BTU/KWH
                225 x 10

This parameter provides a measure of  the heat rejected to the  receiving
waterbody  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 straight-
forward manner to compute  the  increase  in  internal energy  or  heat
content.
                                   276

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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  theriral  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 SOX 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 ccal 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.

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
                                  277

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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 discharged as measured  in  Joules/KWH.  It is necessary in
evaluating this type cf  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  retraining  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 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
                                   278

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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 been  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  technologies
will be  described in this section.

Process  Change

In order to properly understand both the problems and possible solutions
regarding thermal discharges from powerplants, it is necessary to review
a  few   essential  thermodynamic 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
of 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  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
                                   279

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necessary to include a  few definitions  of words or phrases used  in  the
statements of these laws, or in  explaining them.

Heat  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  thermodynamics.  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.

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 B-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
                                 280

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               J
      (HEAT)

POWER
PLA.MT


— *•
             ENERGY OUT
              (WORK)
             ENERGY OUT
              (HEAT)
            ENERGY FLOW FOR A POWER PLANT
                  FIGURE B-VII-1
IOO ENERGY UNITS
   CHEAT)
POWER
PLA.NT
4-0 ENERQY UWITS OUT
    (WORK)
&O EKIER^Y UWITS OUT
    (HEAT)
           ENERGY BALANCE FOR A POWER PIANT
                    (FIRST LAW)
                  FIGURE B-VII-2
                       281

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hypothetical powerplant.  For this  plant,  for  every 100  units of  energy
input,  40  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  (40%) ?"  "Is  there  any limit on
    efficiency, other than economic considerations?   This  is,  can we
    reduce the heat rejected to the environment, without limit?"

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-4.  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 to
the receiver, which is the environment.

Based  on  our  senses  and  experience,  we are usually psychologically
comfort a"ble 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 99X efficient, if we considered it financially  feasible,  thus
rejecting a negligible quantity of  heat to the environment?
                                   282

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                   POWER
                   PLANT
                        100  ENERGY UNITS
                         OUT
           POWER PLANT VIOLATING SECOND LAW
                 FIGURE B-VII-3
        100 ENERGY
 HEAT  VUWITS


SOURCE/  (HEAT)*
POWER
PUNT
4O ENERGY OWITS
 OUT (WORK')
              POWER PLANT VIOLATING FIRST LAW
                     FIGURE B-VII-4
                       283

-------
too
UNITS' IN
 (MEAT')
POWER
PLAMT
GO
UNITS OUT
                              40 ENERGY  UNITS
                                OUT (WORK)
    POWER PLANT CONFORMING TO FIRST AND SECOND LAW
                 FIGURE B-VII-5

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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.

The efficiency of   this  type  of  plant  can  be  determined  from  the
following equation:

        Ere  = 100 (1-T2)    (1J
                      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 Thermodynamics, 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 (1000°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 + 160 = 1460°R

        T2   = 90 + 460 = 550°R
                                  285

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         Ere  = 100  (1-5_50)  =  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 4055.   These modern  powerplants
achieve  a  quite high  efficiency, relative to the maximum.  If one does
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   pcwerplant has   an  efficiency  relative   to  the
theoretical possible of:

         Relative Efficiency = 4£ 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 T1.

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 stean
powerplant cycle:    bciler,  turbine,  condenser  and  compressor.  ThJ
                                   286

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                                                                 POWER OUT
ro
oo
BOILER
 HEAT


RECEIVER
                                                                 POWER iN
                                   CARNOT CYCLE STEAM POWER PLANT

                                          FIGURE B-VII-6

-------
components  are connected by  piping as  shown,  with the direction of flow
of the fluid between them as  indicated.

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  compressed   in  a compressor.  This compression
process raises the temperature and  pressure  of   the  fluid,   and  a]so
causes  the condensation of the remaining vapor.   The result is that the
fluid leaves the compressor at the predetermined conditions 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 tie
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 the 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 th«
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 great extent at  a
time before thermodynamics was a fully  understood or applied science.
                                   288

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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,  condenser  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
dondensed to liquid  water  by  removing  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 Garnet 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-VII-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

With 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 cocl 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 maximum.

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.
                                   289

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ro
vo
o
                                                    POWER

                                                     OUT
BOILER
                                                  POWER

                                                    IN
                                  RANKINE CYCLE POWER PLANT

                                      FIGURE B-VII-7

-------
1C
                                                           POWER
                                                             OUT
                                          TURBINE
                        SUPERHEATER
                        BOILER
                                                      POWER
                                                      :  IN
                           RANKINE CYCLE WITH SUPERHEAT  POWER PLANT

                                        FIGURE B-VII-8

-------
                                                                   POWER OUT
          MEAT  IN
ro
<£>
ro
           HEAT OUT  /M r AT
CONDENSES/           /HEAT
                        POWER IN
                                  REGENERATIVE CYCLE POWER PLANT


                                        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
boiley 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  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
                                   293

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ro
ID
-pa
                                     ^-REHEATER
                                    REHEAT CYCLE  POWER PIANT

                                        FIGURE B-VII-10

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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  tc  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 1900 kN/ir,2  (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  3792
kN/m2  (550   psi)   and 3U3°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/M2   (900  psi)  and
i»82°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 17200 kN/m2  (2500 psi) and
temperature  of 538°C  (1000°F) might be typical today.  This increase  in
pressure  with  correspondingly  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 2400 kN/m2  (3500 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 feed water heaters  used,  but  of  course  the  plant
initial cost increases correspondingly.  For large plants, present costs
justify 7 or 8 stages of heating.
                                   295

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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 Heaters

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.

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 5UO°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, 10000 kN/m2  (1450 psi and less) , the efficiency
gain  from  reheat   is  less than for higher  pressure units, 12UOO kN/m2
 (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.
                                   296

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                                                     TABLE B-VII-1
                                                 EFFICIENCY IMPROVEMENTS
  Modification
Improvement
in Heat Rate
  Work Required
 Outage
  Time
  Cost
Remarks
  Add Feedwater
  Heaters
270 Btu/Htr.
Replace turbine, add
heater and piping
 8  mos.     $25/KW       For  same steam flow the unit output
                        would be reduced by 5%.  Charge
	required for replacement energy.	
  Lower Back     l%/0.5"Hg      Change condenser tubes for
  Pressure                      higher velocity. Add new
  (Pump more                    circulating water pumps
  C.W.)                         with new intake bays and
  	    piping as required.	
                                             2 mos.    $6-8/KW      Limit of improvement is in the order
                                                                    0.25"Hg and any gain would probably
                                                                    be lost to increase pump power.
  Increase
  Steam
  Temperature
PO
10
0.8%/50
Possibility of boiler
modification to obtain
-25  F. Some modification
of turbine will be required.
Main steam piping will have
to be replaced.
                                                              3 mos.
           $6-8/KW
             Practical limit for steam temperature
             is 1000 F.  Limitation primarily due
             to boiler, however turbine also poses
             problems
                                For  50-100 F  increase
                                make extensive modifi-
                                cation  to boiler(or replace)
                                and  replace turbine plus
                                steam piping. Turbine
                                pedestal modifications will
                                also be required.	
                                             8-16 mos.  $35-50/KW
   Increase        1450-1800psig   Replace boiler,  turbine.
   Steam           =1.7%;1800-     steam and  feedwater piping.
   Temperature     2400psig=2.0%;  some changes  to  feedwater
                  2400-3500 psig  heaters. Modify  turbine
                  =1.7%           pedestal and  install new
   ^	feedwater  pumps.	
                                             16 mos.    $60-80/KW
                                                     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.
   Add
   Reheat
 3-4% for  units
 operating at
 1800 psi  and
 above.
 2-3% for  units
 operating at
 1200-1450 psi
 Replace boiler,turbine
 and hot reheat piping,
 rebuild turbine  pedestal,
 modify boiler controls,
 modify condenser and make
 changes to  feedwater
 heating system.
 24  mos.
$100/KW      Typical new reheat unit would be 75MW
             or less in size and would operate at
             1450 psi and 950°F.

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Increased Cooling Gas Pressure

By 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   arrangement.    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 hew  boiler,   turbine,  feedwater
heaters  and  pumps  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  justifiable 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 8,450 kJ/KWH (8,000
BTU/KWH).  The following changes would  be required:

1.  Raise pressure to 16,500 KN/m2  (2,400 psi)

2.  Increase  superheat temperature to 537°C  (1,000°F)

3.  Add reheat to 537°  (1,000°F)

4.  Modify the regenerative feedwater heating cycle

To make these changes, the following work is required:

1.  New boiler, turbine and boiler feed pumps
                                   298

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ro
vo
10
                                           DRAIN
                                           WNA
                                         COOLER
                           DRAIN COOLER ADDITION TO POWER PLANT

                                    FIGURE B-VII-11

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to
o
o
                                                                            [CONDENSER
                                DRAINS PUMPED FORWARD IN POWER PLANT

                                          FIGURE B-VII-12

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               NEW  PLANT• ADDITION
                 ORIGINAL  PLANT
SUPERPOSED PLANT ADDITION
  FIGURE B-VII-13
       301

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2.  New steam and feedwater piping

3.  New boiler controls

4.  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.

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/m2  (2,500  psi).  A significant increase to supercritical pressures,
around 24,100 KN/m2  (3,500 psi) is being  used for some  of  the  larger
units.   A cycle efficiency improvement of about 1.5 to 2.OX 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-14 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.
                                   302

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           POWER IN
o
OJ
                                      '.FUEL IN
COMBUSTOR
                  IN
                                                       .POWER OUT
                                                     COMBUSTION
                                                      GAS  OUT
                          SIMPLE BRAYTON CYCLE GAS TURBINE  POWER PLANT

                                         FIGURE B-VII-14

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                                     FUEL
                                      1
                                  COMBUSTOR
POWER. \M
           AIR.
f
                             REGENERATOR
                                                               POWER OUT
                  COMBUSTION
                  BRAYTON CYCLE WITH REGENERATOR GAS TURBINE POWER PLANT
                                 FIGURE B-VII-15

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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  interceding  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.

Gas  Cycle Plants  - Base Power

Plants   using  gas  cycles are used for tase 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 pcwerplant 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 produces 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 situation is one where the
existing boilers  need replacement or  veary  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
                                  305

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  TO

STACK
"I
 1
     r
             EXHAUST

              HEAT

             BOILER
              COMfcUSTOR
STEAM
TURBINE
                                                                            PLOW


                                                                        STEAM FLOW
                            COMPRESSOR
                                     AIR IN
                           COMBINED GAS-STEAM POWER PLANT

                                FIGURE B-VII-16

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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 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 1035 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

i With steam vapor cycles, much of the heat is added to the plant at lower
temperatures  than  the  iraximum 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 temperature 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.   Some  operating
problems   were   not  satisfactorily  resolved  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.
                                  307

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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.

MHD

Magnetohydrodynamics   (MHD)  is  a   principle  of  producing power quite
different from the steam cycle.  An electrically conducting 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 of extraction steam

- total energy 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-grade heat in
this manner is desirable because no modification to plant performance is
required.  The 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
                                  308

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or in  various  stages   of   development,   most  are  agriculturally  or
aquacultnrally oriented.   The findings of  some  of  these  programs  are
discussed below.

Agricultural uses

A  considerable amount of related work has been planned by the Tennessee
Valley Authority.  TVA has set aside 7,280 hm2 (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 combinations  to
obtain  an  estimate cf the  potential sale value per acre of greenhouse.
The data indicate gross sale potential of  from $40,000  to  $60,000  per
40.5  hm2   (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 40.5 hm2  (acre)  per year.   Calculations
show that the development of 1,300 hm2 (32 acres)  of  greenhouse  tomato
production and 2,350 hm2  (58 acres) of lettuce would utilize about 6% of
the available  condenser water at the plant, and provide about 1.4% of
the total requirements 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   cf   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.

A  similar  study  of greenhouse use of waste heat has been performed by
the ABC 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 heat-
ing 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.
                                 309

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Aquaeulture

The use of low-grade heat to improve  the   yields   and  productivity  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 80% 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 commercial 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 tc 2.5 years by selective breeding,  spawning, larvae
growth and seeding oysters in the hatchery.    This  avoids  reliance on
variable  natural  conditions  and  permits   accelerated  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 2250 Kg/hm2-
year  (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 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.
                                  310

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Utilization of Extraction steam

Extraction  steam  utilization increases both the number and the size of
the potential heat users.   Table  B-VII-2  following  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 efficiency of  the
generation  cycle  from  34X to 54%.  This is equivalent to reducing the
waste heat rejected  to the environment by 25%.

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  Carribean.
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 IX of the waste heat from a  new
ilOOO 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  Icw-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.
                                  311

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U)
M
NJ
                                    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

-------
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, espe-
cially 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 population of 389,000 people  and  a
climate  similar  to that of Philadelphia, Pennsylvania, the cost of heat
for  space  heating   and  domestic  hot  water  was  estimated   to   be
approximately  $1.98/MBTU. '«s    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 tfce 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
                                  313

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mode.  The amount of  heat  that can be removed from the circulating water
discharge 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 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 m,ore 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 net  recirculate directly to the intake point.  Once-
through systems have  teen  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  80fl
of all existing systems  are once-through.
                                 314

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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  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   m3/sec (500,000 gpm), and some of the large stations require
over 60  m3/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 of some
rivers.

The  discharge from the condenser can be returned to  the  source  via  a
canal  or   pipe,  depending  on  the  local  conditions.   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 velocities 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 2H°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 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  tb
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
                                  315

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  Steam
  Flow
                          	I
                          Condenser
                                           Generator
Discharge
Canal or
Piping
                                      Cooling
                                      Water
                                      Pumps
00
       Intake
       Piping
00
           Intake
           Structure
                   General Water Flow

                         Lake
                         River
                         Estuary
                         Ocean
          ONCE THROUGH  (OPEN)  CIRCULATING WATER SYSTEM
                        FIGURE B-VII-17
                       316

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         Steam
     Intake
     Piping
Pumping
Station
Intake
Structure
                              	|

                              Condenser
                                              Generator
    Discharge Piping
              or Canal
  eat
Removal
System
                 Discharge
                 1Structure
                           General Water Flow

                                 Lake
                                 River
                                 Estuary
                                 Ocean
                 ONCE THROUGH  (OPEN)  SYSTEM
            WITH HELPER COOLING  SYSTEM INSTALLED
                      FIGURE B-VII-18
                           317

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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, sclar  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 shewn in Figure B-VTI-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.359  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
severely   limited  by  environmental  protection  considerations.    The
systems illustrated indicate the  degree  of  flexibility  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 10056 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 1.5°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 22.556 of the heat, even though the approach has increased to  6.4°C
                                  318

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                                                                                      TEAM
VO
                                   COOLING SYSTEM CAPABLE OF BOTH OPEN
                                        AND CLOSED MODE OPERATION
                                               '(Ref.  108z)
                                            FIGURE B-VII-19

-------
                            UNDERWATER DAt,
WEIR
OUTLET
                                   RIVER

                            SKIMMER WALL
  PLANT LAYOUT AT  PLANT  No.
       (From  Reference 359)
         FIGURE B-VII-20
2119
                  320

-------
                                                      -TO TOWER
                                                             • FROM
                                                             TOWER
                                                         \  \

                                                           \

                                                            \
                   -."STREAM  TEMP.
40
as
   p
   in
u.

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in
is:
ro
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in
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                   5
                   a.
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                        in
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                                cc
                                LU
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                                             LU
                                             to
                                           8
                                                   LJ
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                                                          iu
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In
     SEASONAL VARIATION  OF "HELPER" COOLING TOWER

                (From Reference 74)

                  FIGURE  B-VII-21
                             321

-------
This  decrease  is  due  to the variation in relationship between 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 temperature  drops below the vet  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 tc  remove  100X  of  effluent  heat
under the worst winter condition  (March)  would be over-sized by a factor
of U 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  recirculated  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 degrease 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 liirit the temperature effect of 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 105 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
                                   322

-------
commonly employed  is  the use of  cooling  lakes,  which  are  similar  in
principal  to  open,  cnce-through systems, but which are closed inasmuch
as no 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

10.  Dry tower, direct

11.  Dry tower, indirect

12.  Combined  wet-dry mechanical draft tower


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  cooling 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  generally 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
                                  323

-------
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  performance.  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 pcnd 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  watershed  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.

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  m2  (1
to  2  acres)  per MW, are found in  the literature.  At 81 hm2 (2 acres)
per MW, the pond for  a 1,000  MW plant would be 81,000 hm* (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  no^.  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 prcvide a  U-shaped pond.   Another station, plant  No.
1209, utilizes a series of canals as a  "cooling  pond" as shown in Figure
B-VII-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 seme 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.
                                  324

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COOLING CANAL
 PLANT NO. 1209
 Figure B-VII-22
      325

-------
1.   Ponds have been arbitrarily categorized in a number of
    ways, such as shallow or deepr 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 discharg-
    ing the hot water from the plant, particularly in the case
    of shallow ponds, greatly affects pond performance.  The
    discharge structure should be designed to spread the hot
    water in a thin layer over the lake surface thus prevent-
    ing mixing with the cooler subsurface water, and sustain-
    ing a high pond surface temperature to promote rapid heat
    transfer to the atmosphere.  The suitability of the dis-
    charge 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 veloci-
    ty of discharge to a characteristic length of the struc-
    ture, 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/secz (32.2 ft/
              sec2)

    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.

U.  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.
                                 326

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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 pond.  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 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 power-
plant.  The steady net heat loss from the lake surface
is normally expressed as:

                  Heat loss = KA (Ts -TE)

where K  = Heat Exchange Coefficient, J/m2-day-°C
            (BTU/ftz-day-°F)

      A  = Area of Lake, m«  (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/mz-day  (BTU/ft2-day)

      K  = Heat Exchange Coefficient, J/m2-day-°C
            (BTU/ft2-day-°F)

The heat exchange coefficient  (K) is closely related to
windspeed as shown in Figure B-VII-23, which permits
determination of 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
                              327

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en
EH

+


B

oo
  -P
  m
  ^
  0)
  I
        35
        30
        25
        20
      15
        10

                         12            345            6



                                            Windspeed  (m/s)



                   CHART FOR ESTIMATING COOLING POND SURFACE HEAT EXCHANGE COEFFICIENT

                                           (From Reference  32)

                                             FIGURE B-VII-23

-------
   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.

The first step in the procedure  for estimating the average pond  surface
temperature  is  to   determine  the discharge temperature to the cooling
pond.  This is done by  first determining the quantity:

                        KA
where K   =  Heat  exchange coefficient estimated from Figure
           B-VII-23,  J/m2-day-°C (BTU/ft2-day~°F)

      A   =  Assumed pond area,  m2 (ft2)

      p   =  Density water, kg/m3 (lb/ft3)

      cp =  Heat  capacity, J/kg-°C (BTU/lb-°F)

      Qg =  Condenser  flow, m3/day (ft3/day)


Figure B-VII-24  can be used to determine the approximate area  A.    With
the  condenser  rise,  from  Figure  B-VII-25,  0  (excess  of discharge
temperature,  Tj>, over the equilibrium temperature,   TE)   is  determined.
Note  that  curves for slug flow and complete mixing are given.  Then the
discharge temperature, Tg, and the inlet temperature, Tc, can be  deter*
mined.

      Tp =  TE +  6r

      Tc =  T|> -  Condenser rise


From  Figure   B-VII-26,  using  9  and KA/pcQ£, 6 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-VIl-24, which   determines  the  area  required  for  each  million  kJ
(million BTU)   of  heat  to  be rejected.  If the cost per acre of pond
                                 329

-------
3.0
2.5
2.0
1.5
1.0
0.5
                                  T   =  Surface Temperature ( C)
                                  s
                                  T   =  Equilibrium Temperature (  c)
  0
       "180    200   220   240   260  280  300  320  340  360  .380  400
                                                   2 o
                  Heat  Exchange  Coefficient,  k, J/m - C-day
      COOLING  POND  SURFACE AREA VERSUS HEAT EXCHANGE COEFFICIENT
                            FIGURE B-VII-24
                                3-3 ft-

-------
   35
   30
o

-------
U

-------
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:

  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.  Make'up 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

Spray  systems  can  te  utilized  to  reduce the large area required by
cooling  ponds by up tc 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   tc  the  pond  below.  Water from the pond is pumped
directly to the condenser.  To obtain adequate  cooling  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 performance.  The spray is produced by  modules
moored  at intervals in the canal and floating on the water surface.  Two
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
mVsec to 0-789 m3/sec  (10,000 to 12,500 gpm).  Two characteristics
                                  333

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    3.0 L
                            Cost  per  Hectometer of Pond Surface
X
re

-------
u>
u>
en
                                           UNITIZED SPRAY MODULE

                                             (From Reference 365)

                                               FIGURE B-VII-28

-------
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!/
i/
if
f


               —•wsw"'
                                      FOUR SPRAY  MODULE
                                     (From Reference 366)
                                       FIGURE B-VII-29

-------
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 cf the plant.

The  use of  these  modules  in the utility industry is relatively new,
although tests have been underway for some years. . Plant  No.  3304  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^ inlet
temperature  is the condenser discharge temperature.   The  cooled  spray
from  the  first  module  remixes  with  the water in the canal, and the
resulting temperature 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  overall  performance
with  additional modules is not cost effective.  Using some general data
on one manufacturer's units. Figure B-VTI-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 tem-
perature) .   The wet bulb temperature is then used to determine  the  ex-
pected  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.
                                  337

-------
 SPRAY CANAL
PLANT NO. 0610
 Figure B-VII-30
     338

-------
SPRAY MODULES
 PLANT NO. 0610
  Figure B-VII-31
       339

-------
         100 90  80  70 60  50 40  30  20 10  8 -
Initial Temperature
            GRAPHIC  REPRESENTATION OF DESIGN OF SPRAY AUGMENTED COOLING  POND





                                      Figure  B—VII—32
                                                                                               Wet Bulb Temp.
                                                                                                       17.8°C
                                                              Initial Temperature (  C)

-------
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  (24,600
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 1.26X.

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 nun 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-VII-35 and B-VII-36 were developed.

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  relationship  between
the  air  flow  and  the  water  flow.   In counterflow, 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 flew  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
                                 341

-------
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                                     THERMAL ROTOR SYSTEM
                                         FIGURE  B-Vn-33
                                     (From Reference -389)

-------


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COOLED WATER CHANNEL

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          70'	
                                            (-
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                           SECTION THRU CHANNELS
-POLYVINYL CHLORIDE LINER
                                                                             "'
                                                                HOT WATER
                 DOUBLE SPRAY FIXED THERMAL ROTOR
                       (From Reference  360)
                         FIGURE B-VII-34

-------
                      Range
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0) !-3

8*
 *s
H O
(0 H
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-------
        1.6
       1.4
       1.2

-------
                 t  AIR f
                 I OUTLET j
        WATER
COUNTERFLOW MECHANrCAL DRAFl' TOWER

             FIGURE B-VII-37
         CROSSFLOW MECHANICAL DRAFT TCWER

              FIGURE B-VII-38
                  346

-------
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 consists of an
upper  section  of   dry  tower  emitting  warm  air  heated  solely   by
conduction,   and  a   lower wet section emitting 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-VII-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.

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  expensive than  shell and tube condensers.  The air system for
the tower may be  either  induced, forced, or natural draft.
                                  347

-------
                    t  *'"  t
                    I  OUTLET |
           WATER OUTLET
    CROSSFLOW NATURAL DRAFT TOWER
           FIGURE  B-VII-39
      DRIFT   /  HOT-WATER
    ELIMINATOR / DISTRIBUTION
      FILL
                                      AIR
                                      INLET
                         COLD-WATER BASIN
COUNTERFLOW  NATURAL-DRAFT COOLING  TOWER
            FIGURE  B-VI1-40
                        348

-------
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 75X  of the total heat transferred is by  evaporation,  the
remainder by sensible heat transfer to the air. (6)

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 srrall droplets of water and  thus  increasing  the
total   surface  area  per  unit  of throughput.  For a given water flow,
increasing the  air  flew  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.

The   mechanical    draft  tower  consists  of  the  following  essential
functional components:

1.  Inlet  (hot) water distribution

2.  Packing  (film)

3.  Air moving  fans

4.  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 susceptibility
to fire. On multi-celled towers, the cost of fire prevention system can
run into several hundred thousand dollars or more.  Constant exposure to
                                 349

-------
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 pressure  and wood
stave pipe, plastic and metallic pipe have  been used.  The blades on the
fans must be reasonably lightweight, and  corrosion resistant.  Both cast
aluminum  and  GRP  (glass reinforced plastic) ,  are generally used today.
For large towers mounted on .the ground,   concrete cooled-water  storage
basins  are  used almcst exclusively.' For  other applications,  both wood
and sheet metal basins have been used.


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 are6:

1.  Lower pumping head as a result of lower packing.

2.  Lower pressure drop .through the  packing.

3.  Higher water leadings for a given height.

4.  Lesser overall tower height.

Compared  to  the counterflow tower, crossflow towers have the following
di sadvantages 6:

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.
                                  350

-------
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
    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  ^nd  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
manufacturers are shown in Figure B-VTI-41.  The"rating factor  obtained
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-U2; where
cost/106 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.   (Figure  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   ccst.   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-VII-44.  The relationship between the two factors is
essentially linear.

The curves in Figure E-VII-43 take into account a size factor, 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  in
                                  351

-------
       70° WET BULB
         40
         30
         20
              /«
           • 5 0-6 0-7  0-8 0*9  1-0 1-1 1-2  i-3 1-4  1-5  1-6
                         RATING FACTOR
TYPICAL CHART FOR DETERMINING RATING FACTOR

               (From Reference  74)

                Figure B-VII-41
                       352

-------
  3000
  250TJ
 4

OC

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\


H2000
04
***"
  1500
u.
<

-------
         APPROACH.?  678
L
12

K
16
C05T-C X $100,000
BASIN AREA » Cx 100 FT,2
FAN HORSE POWER * C x 100
PUMP HORSFPOWf fl - GPWY
       O.OIE           ,


             ^
                                        0.5  1.0  1.5  2.0  2.5  30  35"  4.0
                                                K xGPM x I06
                        COOLING TOWER PERFORMANCE CURVES
                                FIGURE B-VII-43
                                                         (57)
                                  354

-------
  150


  140


  130


  120


  110


  100


   90


   80
H
0
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8  70

-------
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1400




1300




1200




1100




1000




 900




 800




 700




 600




 500




 400
ft    300
nj
O

     200




     100
                                               K=70
                                                            16.7°C
                                             K=50
                                                   Range  l6.7°f
                                            Range 5.s°c

                                      K=5°  Range 5.50C

                                     ^  JIJ  Kane   '^u
                                         K=3°  Range 5.5°n

                0.1
                     0.2
                                0.3
0.4
0.5
                                                         0.6
                                                             0.7
                                                                        0.8
                          Water Flow Through Tower  (m  /s)
      GRAPH SHOWING VARIATION OF COST  OF  MECHANICAL DRAFT COOLING TOWERS


                       WITH WATER  FLOW (from Reference 57)

                                FIGURE  B-VII-45


                                    356

-------
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   drcps 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)).

4.  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.

2.  A more sophisticated air  distribution system is required
    to maintain uniform air  flow through the packing.
                                  357

-------
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 currently 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 6:

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 Tower

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-VTI-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-47.   The  air  passing  through the dry section is heated
along line 1-3.  The air passing  through 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
                                   358

-------
          MECHANICAL-FORCED DRAFT COOLING
                  FIGURE B-VII-46
                      twv section
                                                           SUPER HEAT
                                                          (Non-Fog) ARIA
                                       SUPER SATURATION
                                          (fog) AREA
                                          DRY BULB TEMPERATURE (°F)
PARALLEL PATH WET DRY COOLING  TOWER PSYCHOMETRICS
                  FIGURE B-VII-47
                 (From  Reference  128)
                             359

-------
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-49, the principal cooling o'ccurs in
the dry system, with  the wet section used only as required.   The  tower
performance  in such  a  situation is  iridicated on the psychrometric 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 172,000 gpm
of brackish water.

Natural Draft Cooling Towers

The  natural  draft tower, or hyperbolic tower, as it is commonly 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 tc  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


Approximately  a tenth  of the tower  height is utilized for the air-water
contact section, the  remaining  90%  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
                                  360

-------
                             SUB-SATURATED AIR MIXTURE
AIR COOLED
  HEAT
EXCHANGERS
 HINGED SUMMER
 DAMPER DOOR
             SUMMER
  HOT WATER    FLOW ONLY
   INLET PIPE
 INTERMEDIATE
   WATER
               EVAPORATIVE
                  FILL
                 SECTION ,
 COLD WATER
   BASIN
           PARALLEL-PATH WET DRY  COOLING TOWER FOR PLUME ABATEMENT
                                      FIGURE B-VII-48
                                  (From Reference  128)
                                    361

-------
co
en
to
                                                                  <
                                                                  Q
tt
o


S
D
X

v
iu
o.
V)
                                               SUPER SATURATION

                                                  (Fog) AREA
                                                                           "T&Y STiHAM
                                                                                              DIMENSIONS INDICATE

                                                                                              RELATIVE FLOW RATE
                                                                       SUPER HEAT

                                                                      (Non-Fog) AREA
                                                                                        -WET STREAM MASS FLOW
                                                                          DRY BULB TEMPERATURE (°F)
                              COt.0 WATER
PARALLEL-PATH WET DRY COOLING TOWER  (ENLARGED DRY SECTION)



                            FIGURE B-VII-49                 (FrOrn
                                                                                                            128)

-------
TYPICAL NATURAL DRAFT
    COOLING TOWERS
    PLANT NO. 4217
     Figure B-VII-50
         363

-------
Southwest, with high temperatures and  low  humidities,  the potentials for
favorable   density   differences   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 S
-------
15° RANGE
10096 RH     APPROACHES
  01234
      TOWER COST - DOLLARS PER THOUSAND BTU/HR.
25° RANGE
10096 RH
                                                         APPROACHES
  0123
      TOWER COST - DOLLARS PER THOUSAND BTU/HR.
   15° RANGE
   5096 RH   APPROACHES
  01234
      TOWER COST - DOLLARS PER THOUSAND BTU/HR.
25° RANGE
5096  RH
                                               ui
                                                 80
                                                 75
                                                 70
                                                 65
                                                 60
                                                          APPROACHES
  0123
      TOWER COST - DOLLARS PER THOUSANb BTU/HR.
   15° RANGE
   2596RH   APPROACHES
  0123
      TOWER COST - DOLLARS PER THOUSAND BTU/HR.
25°RANGE
2596  RH  APPROACHES
80
                                                 75
                                                 70
                                               I-
                                               UJ
                                                 65
                                                 60
  01234
      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
                                        365

-------
35° RANGE
10096 RH
         APPROACHES
    0123
        TOWER COST - DOLLARS PER THOUSAND BTU/HR.
45°RANGE
100% RH
   80
                I         2         3
         TOWER COST - DOLLARS PER THOUSAND BTU/HR.
35° RANGE
5036 RH
         APPROACHES
              I          2         3
        TOWER COST - DOLLARS PER THOUSAND BTU/HR
45° RANGE
5096  RH
                                                         APPROACHES
     01234
         TOWER COST - DOLLARS PER THOUSAND BTU/HR,
35° RANGE
25%  RH
         APPROACHES
  BO
    0123
        TOWER COST - DOLLARS PER THOUSAND BTU/HR.
 45° RANGE
 2596 RH
                                                         APPROACHES
                I         2         3
         TOWER COST - DOLLARS PER THOUSAND BTU/HR
               HYPERBOLIC NATURAL  DRAFT CROSSFLOW WATERCCOOLING  TOWERS
                TYPICAL  COST-PERFORMANCE CURVES FOR BUDGET ESTIMATES
                                    (From  Reference 74)

                                      Figure B-VII-52
                                             366

-------
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 reclrculo-
tton.             C
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.
             PAN-ASSISTED  NATURAL  DRAFT  COOLING  TOWER

                                FIGURE B-VII-53

                              (From Reference  358)
                                    367

-------
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 usiag
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-VII-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  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 Hg) .  Dry bulb temperatures range from 5.50
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 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 pressures 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°FJ ,  which yields a  condensing  temperature
of 53.5°C  (128°F) with a corresponding pressure of 14.5 kN/m2  (4.3 in 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 condensing temperature  of
61.1°C   (142°F)  with  a corresponding pressure of 20.4 kN/m2  (6.2 in Hg
abs) .  This is almost 50SS 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-
                                  368

-------
U)

-------
U)
^J
o
                                                              STEAM
                                                              TURBINE
                                        NATURAL-
                                        DRAFT TOWER
                                        COOLING COILS
EXHAUST
STEAM
                    DIRECT-CONTACT
                      CONDENSER
                                           WATER RECOVERY
                                             TURBINE
                                                                                      STEAM SUPPLY
                     CIRCULATING PUMP
                         MOTOR
                                                                          CIRCULATING
                                                                          WATER PUMP
                                                    CONDENSATE POLISHERS
                         CONDENSATE TO
                         REACTOR FEEDWATER
                         CIRCUIT
                                            Figure  B-VII-55
                               INDIRECT, DRY-TYPE  COOLING TOWER
                       CONDENSING  SYSTEM  WITH NATURAL-DRAFT TOWER  241

-------
t
UJ
oe
tt
UJ
0.
*
UJ
I-
   DIRECT-CONTACT
   CONDENSER
    TURBINE EXHAUST
    STEAM
                        COOLING COILS
                     r
 •TRANSFER OF HOT CIRCULATING
 WATER FROM CONDENSER
 TO TOWER
-TRANSFER OF COLD CIRCULATING WATER
 FROM TOWER TO CONDENSER
   (I)
               (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°
                            371

-------
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  locationsr  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-VTI-58.   The
lower  condenser  costs  particularly  make up for the greatly increased
cost of the cooling tower.

There are a number of other benefits  from the dry-type cooling 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.

On the other side of the ledger, there is a significant  loss  in  plant
efficiency due to the higher turbine  exhaust pressures.  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 maxiirum plant  capacity is also reduced.


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   (18%)   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  f cr  over  50% of the total capacity of units to be
installed 1974 through 1980.  See  Table E-VII-4.

Site visits were made to a number  of  steam electric  generating  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,  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-5 presents a list of plants  visited 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.
                                  372

-------
s
*
o
H
4J

§
•H
04
5
      10,000  .
        9,000
        8,000
        7,000
        6,000
        5,000
        4,000
        3,000
       2,000
       1,000
                         Natural Draft
                             Towers
    Average Design
   Dry Bulb Temperature
               is-
                                18
                                   ITD (°C)
                                           30
35
40
"45
         REPRESENTATIVE COST  OF  HEAT REMOVAL WITH DRY TOWER SYSTEMS
                    (from Ref.  240)  FOR NUCLEAR PLANTS
                           FIGURE B-VII-57
                                 373

-------
OJ
         WATER INLET


         AIR VAPOR
         OFFTAKE
         CASCADE
         PLATES
         CONDENSATE
         OUTLETS
                        STEAM INLET
                       EXPANSION  JOINT
                                                STEAM INLET FROM
                                                 TURBINE EXHAUST

                                                        WATER DISTRIBUTION
                                                            PLATE
PERFORATED
  TRAYS
                                         Figure B-VII-58
                                       STREAM TYPE
                             DIRECT CONTACT CONDENSER240

-------
      w
      "3
      *l

      8
                       PERCENT INCREASE IN FUEL CONSUMPTION (ABOVE
                      O           ui           o
      S
      13
  *i n so
  H O M
  O 3 en
  S   CO
  Jo 50 G
to M (0 1«
^j   Hi M
in td fl>
   I H O
  < g S3
  H y
  H O >rj
   i o> q
  01   H
  \O M F
    CT»
    VO O
      H


      §
                                                     TFRCENTOECREASE IN TURBINE OUTPUT
                                                                              . ABS.)

-------
                                    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 of Plants,
% total
1969
49.8
18.9
5.4
17.2
8.7
1970
49.4
18.5
5.7
17.5
8.9
Installed Capacity,
% of total
1969
50.5
23.5
5.9
10.9
9.2
1970
50.1
22.8
6.7
11.2
9.2
-o
en

-------
                                     Table B-VII-4
                       EXTENT TO WHICH STEAM ELECTRIC POWERPIANTS ARE
                        ALREADY COMMITTED TO THE APPLICATION OF
                           THERMAL CONTROL TECHNOLOGIES
              CONTROL TECHNOLOGY
                                       ASSOCIATED GENERATING CAPACITY, THOUS.  MW
                                            IN ACTUAL USE
                                               IN 1973
                                                     COMMITTED FOR UNITS  INSTALLED
                                                          1974 THROUGH  1980
00
No Control (Once-Through)
Controlled
   • Cooling Towers
   • Cooling Ponds
   • Combinations
Unknown
                                                  230
                                                  110
                                                      50
                                                      30
                                                      30
 60
130
    80
    40
    10
                                                                            30

-------
        Table B-VII-5




COOLING WATER SYSTEMS DATA



      PLANTS VISITED
Plant
Plant ID Type of Capacity
Code No, Fuel MW

0640
1201
1201

5105

0801
1209

1209

2612

4217

4846

, 3713
•vj
00 3626
1723

2512
3115

3117
2527

0610

2119

NUCLEAR
OIL & GAS
OIL & GAS

OIL
OIL

COAL.S GAS
:OftL & GAS

NUCLEAR

NUCLEAR

COAL

COAL

COAL

COAL
NUCLEAR

OIL
OIL & GAS

NUCLEAR
OIL

OIL & GAS

COAL

916
139.8
792

1386
1165

300
820

1456

700

1640

1150

2137

290
1618

542.5
644.7

457
28

750

2534
Coolinq Tower
Type
Natural
Draft









Mechanics.
Draft
Natural
Draft















latural
Draft
Heiqht Diameter
Ft. Meters Ft. M

425









1
62

323
















437

129.5










18.89

98.45
















133.2

325










48

247
















311
Water
Range
°F
!
99.6










14.63

75.28
















94.8
28

Coolinq Pond or Lake
Type
of Pond
Surface Area Volume
Acres M^(103) Acre Ft. M^llO*)^



Artifical 1100 4460
Spray







30

28


Canal 7.35
Spray
Canal x^

29.8
57.17
Natural
Lakes 536.63 2176

Artifical
Canal 3860




Artifical
Lake 2353
Artifical
Reservoir 32510












27.7
Natural
Lake







Spray
Pond





28


15652





9541

131830










113.54




9350

132

11234.3


20,000





50600

1093600










171





11556

163.15

13885


24719





62541

135167










211.35


Average
Time
%



:oo






100





















Once-Throuqh Svstem
Lenqth of Pipe Diameter of Pipe
Ft. M Ft. M
Discharge
Type Comments


850


800






3300







356
3619
>50 (Inlet
>35(Outle

10 (Inlet)
.5 (OUT)
80




250
4


243.84






1005







JOS. 5
1103
76.2
fc> 71.62

12.19
4.57
24.38





o (Inlet)
10 (Outlet






11







0.75
16
5.5(IN)
7. 5 (OUT)

5.5(IN)
7. 5 (OUT)
4.5





1.22


1.828
3.048






3.352







0.228
4.876
1.676
2.28

1.676
2.28
1.51




Gravity


Gravity

Gravity



L
Gravity







Gravity
lultiple
Jiffuser
Systems





•3 mos . one
3 mos . spr

Dnce thro
units Is
canal wi
Jsed by a
units
sngth of
650 ft
two towe
are us











2 thr
,canal

ugh
2
LI be
11 4
tower

rs
2d






spr. canal will
51 installed
to replace dif
Gravity j SYS •
Outfall

Gravity
Type







Concre.te
Tunnel



3 such t
:or 3 Uni







wers
:s

-------
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 artificially
constructed lakes,  or  may  be  canal  shaped.   If  available  land  is
limited,  a  smaller pond may be constructed by utilizing spray modules.
Among the plants visited  with  conventional  cooling  ponds,  operation
generally  appeared  satisfactory,  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.
                                 379

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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 required 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  may 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 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 KWH?  Since generation costs are  normally  expressed
in mills  per  kilowatt hour, this was chosen as the cost basis for the
                                 381

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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.

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  existing 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 158
for the investor-owned  utility*

Of  the  four  items  included in the fixed charge rate, interest 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.   Depreciation 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 4%, 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 dcwn 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.

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
                                  382

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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   ccst.   The  circulating  pumps  would  normally  be
overhauled once a year,  which is a two week job on 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 decreased 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/m2(5.0
to 5.5 in Hg abs).   The limiting factor is the design of the last stages
in  the  turbine.  Once the amount of replacement capacity is determined,
its cost can be calculated.  If new capacity is installed, 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 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-lais 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.
                                  383

-------
                          100%
      OPTIMUM COOLING
      TOWER FAN
      CAPACITY IN
      SERVICE
to
oo
                           50%
                            0
                                            WET BULB TEMPERATURE
                                       Figure B-VIII-la
               EXAMPLE OF OPTIMIZATION OF NET UNIT POWER OUTPUT BY REDUCTION OF
                                  COOLING TOWER FANS362

-------
Once the  annual  costs for the above items have been determined, 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

Cost  data   were  obtained  from  the steam electric generating stations
which were visited during  the  course  of  this  study.  The  utilities
involved  were  very  helpful,  with  seventeen  providing the requested
information  in time for inclusion  in  this  report.   In  general,  the
plants  chosen  for the visits were those considered by the Regional EPA
offices as being  exemplary  stations,  or  those  having  an  exemplary
treatment system.

Nuclear   plants  and all three types of fossil-fueled plants (coal, oil,
and gas)  were  visited.  The size of the stations visited ranged from  28
MW  to the largest in the country at approximately 2500 MW.  One station
had a unit constructed in 1924.  In the remaining  stations,  all  units
were  constructed  after  1952, with 12 stations being constructed after
1960.  Of the  total number of plants visited, 5 were nuclear.  Seven  af
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  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  1157 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  station is plant No. 2527 at
$155/KW,  for a 28 MW station.  Larger stations tend to have  lower  unit
costs.    Plant No. 2525 at 1,165 MW and a unit cost of S142/KW, seems to
be an exception.
                                 385

-------
          TABLE B-VIII-1
COOLING  WATER SYSTEMS - COST DATA
          PLANTS VISITED
Plant
ID
0640
1201

1201

5105
2525

0801

1209

1209

2612

4217

3713
3626

1723

2512
3115
3117
2527
0610

2119




Type of | Capacity
Fuel I MH
] ' " ~
Plant Cost Data
Date of
Cons t .
NUCLEAR 916 ; 1969-74
OIL s GAS

OIL & GAS

OIL
OIL

COM, S GAS

COAL S GAS

NUCLEAR

NUCLEAR

COAL

COAL
COAL

NUCLEAR

OIL
OIL S GAS
NUCLEAR
OIL
OIL S GAS

COAL





139.8 1956-59
1
792 1969-72

1157 ! 1958-69
1165

300

820
1961-69

1924-64

1964-67

1486

1967-73

700 1966-70

1640

1965-68

2137 ' 1962-70
290

1952-55

1618 1966-72
I
542.5
644.7
457
28
750

2534


1963-68
1954
1967-73
1964-66
1968-72

1969



Land
$
(1000)
Structure
$
(1000)
-
.

1958

172
605

408
_
]
( 2213
)

2393

3692

781
69.58

1062

236
844
213
45
3335

"



1960

26000

8638
20915

5858





37735

19502

30163
4609

34833

7994
13806
165480
1072
4036

~






Equip.
S
(1000)
-
12130

85000

L16255
L38127

29288





106856

158783

174913
18511

110542

55283
71233

3283
97681

-
(1) fo
(2) On
to

(3) No
Total Cap-
ital Cost
S (1000)
355,000
14,090

112,958

125,065
159,648

35,554

59,175

252,381

146,984

181,977

205,857
23,190

146,437

63,513
85,883
165,693
4,400
105,052
(1)
125,000
I Unit 3
ly fracti
station

t given i

Unit 	
Cost
$/KM
387
88.06

134.8

110.29
142

118.5

68.5

170.0

210

105

102.9
153.12

118

117
143
344
r
Cooling Sys
Date of
Cons t .
1969-71
1956-59

1969-72

1970-71
1971-74

1924-64

1964-67

1971-74

1972-74

1965-68


1952-55



1963-68


155
143

109
jnly
on of thi
3713, bre

ncluded i
1971-72

1969

; cost al
ikdown no

i plant c
Land Structure
5 ?
(1000) (1000)
111 13,021
_
316

1544

6,350

109 1,082


(3) 1,820

(3) 1,762






(2)
11524




20



2496

"

Locatable
: given i

3St


(2)
25,517
258



268





"


1 data
tern Cost
Equip.
?
(1000)
205
825

4,045

1,349


261

2,146






(2)
16,243
585



568



6975

"



1
[

Total Caj
ital Cost
$(1000)
13,337
1,141

11,939

2,540
8,000

2,081

3,908

37,858

19,600

15,750
(2)
53,284
844

6804

856
4818


9471

8036






-% of
Plant
Cost
3.76
8.1

10.6

-




4.5








3.67

4.6

1.35
8.03


9

~





Energy Cost
Ope ratine
s Main."
Cost
S(IOOO)
-
11

Cooling
System
Snergy
Require-
ments
—
-

13 '

-


7.04
-
4MW

-

10



14Mrt

36


48.5




4.632




—










28.5







12





Increasec
Heat
Rate
BTU/KrfH
-
-

89

-
31

-

_



100






267







156






Los s of
Capacity
MW
~
_

6-8


4

-

_



9






41.4







42





Type of
Syst
Natural I
Tower
Once Thrc

Cooling

elper Sp
lelper Sp
Ilosed Sp
Cooling
(three

Dnce Thro

Pooling C
echanica
rfet Towe

Cooling
em
raft Wet
ugh Flow

Pond

tray Canal
ray Canal
ray Canal
*onds


ugh Flow

anal
. Draft

natural Draft Wet
Tower

Cooling
Once Thr
Spray C,
(in proc
3nce Thro
(seawate
Dnce Thro
)nce Thro
3nce Thro
Spray Can
Nat . Drf i
Hlpr&Cloj







Ake
5ugh Flow
inal
;ss)
igh Flow

igh Flow
igh Flow
igh Flow
il
Wet Twr
ied Modes






When Ins
in Stat
Origina.
Origina!
1 un,
Origina
2 uni
Backfitt
neet stre
3 uni

tailed
ion
Design
Design
t
L Design
;s
sd to
un stds
:s
Bckf€td to meet
Str StdsfSunits)
Ong.Des. (lunitj

Original
Original
(to Be ad
cooling
Backfitt
lose sys
Bckfttd t
cooling

Original

Original
Original
Bckfttd t
cooling

Original
Original
Original
Original
Change, f r
inrough c
constr.
3ckfttd o
3rig.Des.






Design
Design
del td
canal)
ed to
:em
o close
system

Design

Design
Design
o close
system

Design
Design
Design
Design
3m once
or ing
i 2 units
1 unit






-------
Land costs for cooling  ponds  or spray canals are higher than  those  for
other  systems due to larger  land requirements.   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.

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 0.4SS to 2.5%.

Of the five stations reporting increases in heat  rate,  three  reported
increases  of  105  kJ/KWH  (100 Btu/KWH) (roughly 1% of gross plant heat
rate) or greater.  When a  specific station is considered for  a  cooling
system  other  than  once-through,  the station cooling system design is
normally  optimized.    This  means  some  increase  in  turbine  exhaust
pressure,  and consequently 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 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
                                 387

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relatively  new, and  some  ancilliary problems remain to be solved before
this technology becomes  sufficiently reliable for extensive utility use.

A preliminary study 232  has  been  completed to assess the feasibility of
backfitting  closed-cycle  cooling  system  with  national draft cooling
towers at two TVA powerplants.  Plant No.  4704 has  four  units  with  a
total capacity of 823 MW,  has 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 tower including foundations is about 4.0X of
the total cost, civil work (dikes, pump station, earthwork, etc.)   about
40-50%, electrical work  less than 3%r and mechanical work (pump, piping,
etc.) about 10-15%.

Based  on  the  FPC Form 67  data  for the year 1970 233^ the capial costs
reported for once-through  (fresh)  ccoling 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.


Costs Analysis

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
                                  388

-------
considered  for  backfitting  with  closed  cooling  systems.  A turbine
exhaust pressure of  8.45  kN/m*  (2.5 in 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 Pensaoola, Florida (hot and  humid).   The wet bulb temperatures  used
were those  listed  as being  egualed or exceeded only 5% of the time, on
the average during the four months of June through September.  52   This
amounts to 110 hours for  this period.

The  necessary   information was  submitted  to  three  cooling  tower
manufacturers and  twc 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.

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-2.  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  gtream   standards.    As such, they are available
technology.  At one  major plant  the  powered  spray  modules  are  being
installed in a closed system.

Table B-VTII-2 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  in-
dicate.    For   mechanical   draft  towers,  it  appears  that  concrete
construction is more expensive than wood by a factor of 1.4.   The  cost
of  all  the  systems, exclusive of the natural draft tower is about the
same. Thus if mechanical towers 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.
                                 389

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         TABLE B-VIII-2




COST OF COOLING SYSTEM EQUIPMENT
Unit
Size
(MW)

100







300







600







1000






L
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
Cost For System (.$ x 10b).
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

Mech.
Concrete
Mfr. A
,550
.648
.857

.798

1.019

1.442
1.665
2.478

2.300

2.835

2.491
3.014
4.332

3.705

4.897

5.867
6.780
10.191

9.465

11.677

Draft
Contr .
Mfr. B

.650
.825

0.800

0.955


1.490
2.232

2.010

2.530


2.640
3.825

3.525

4.470


6.000
9.050

8.250

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
2.20Q
3.118
7.22
2.965
5.700
3.57

4.180
4.940
7.380
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



               390

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This optical  is  available  for  use  and  considered  as  a  lower  cost
available technology for those plants where suitable land is available.

Operating Costs

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.  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-3.
Based  on these figures, the figures shewn in Table B-VIII-4 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   KWH1s 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.  Note 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   24°C (75°F), and the lowest summer wet bulb at the IX level
was 14°C  (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
                                  391

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            TABLE B-VIII-3
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
Mils/KWH
6.24
8.35
12.50
            TABLE B-VIII-4
   REVISED PLANT OPERATION PARAMETERS
Type
of Unit
Base
Cyclic
Peaking
Hours Up
per Year
7690
4500
1200
Heat Rate
kJ/KWH [ BTU/KWH
11,088
12,144
13,200
10,500
11,500
12,500
Capacity
Factor
0.77
0.44
0.09
Bus Bar Cost
Mils/KWH
6.34
8.35
12.50
               392

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ages  of the three age  categories,  6,  18, and 30 years, were used.  This
gives a total of  27  cases,  3 types  of  units multiplied  by  3  wet  bulb
temperatures 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  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/m* (2.5 in 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
back fitting.   Due   tc   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  cf 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-5.

A  number  of  additicnal  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   (SO1)* of this 24 meters  (80«) , 18 meters
 (60*) was required  in the tower, and the remaining 6 meters  (20'Vas  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
                               393

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                 TABLE B-VIII-5
          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
                    394

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of 80% was assumed.   The  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  S14.1/KW, and average value pf $15/KW was
assumed for the purposes  of this analysis.  For  a  300  MW  unit,  this
amounts  to  $4,500,000  for  the complete installation.  The cost of the
tower and pumps alone  for this  installation  would  be  approximately
$1,121,600.   Therefore,   the total installed cost is approximately H00%
of the cost of  the   major equipment  involved.   The  basis  for  this
estimate  was  a   base 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 S25/KW.

For the  purposes of the economic analysis a markup of 300°C above the
the base cost of the  najor 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   B-VIII-2  was used to develop a linear relationship
between the tower  parameters  (approach, range, flow, and wet  bulb)  and
cost.   The  variation  in cost was less than 5% at the 28°C  (75°F) wet
bulb temperatures, and averaged less than 15% for the  14°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  10X variation.  The operating cost of the towers was assumed
to be primarily the ccst  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 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 - 19%, and 30 years  - 15%.
                                 395

-------
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 15S6.  If  base  load  capacity
were  used  in  place  cf   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-6.

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-7.

Several additional assumptions were made about each type of unit,  base,
cyclic,  and  peaking.   These   were mainly concerned 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 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  norirally  be   scheduled  to  coincide  with the annual
maintenance period  when  the  unit  is  down  in  anycase.   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.
                                  396

-------
                                 Table B-VIII-6
             ASSUMED INCREASE IN HEAT RATE COMPARED TO BASE HEAT RATE AS A FUNCTION
                              OF THE TURBINE EXHAUST PRESSURE
          Turbine Exhaust Pressure, in Hg
OJ
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

-------
LJ
10
00
                                     Table B-VIII-7

                                   COST ASSUMPTIONS
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
and 10 mills/KWH

15%
                                                                            90$/KW
                                                  Assessed at cost of generation for type
                                                  of unit considered except for peaking
                                                  units, where cost is 10 mills/KWH

-------
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.

A  sample  calculation   for  a  peaking unit with a 24°C (75°F) wet bulb
design temperature,  is  shown in Table B-VIII-8.  The  procedure  was  to
assume  8.45  kN/m2   (2.5"  Hg  abs)  turbine  exhaust pressure with its
corresponding 99°F hot  water temperature.  With a  minimum  approach  of
6.7°C  (12°F) ,  the   iraximum  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
40X were determined. The turbine exhaust pressure was then increased to
10.1 kN/m*   (3.0  in Hg abs), the maximum heat removal determined  (6055)
and conditions for removal of from 40% to 60% removal  determined.   The
same procedure was used at 11.8, 13.5, and 15.2 kN/m2  (3.5, 4.0, and 4.5
in Hg abs) until 100% removal was obtained.  The analysis then proceeded
in  an  orderly  fashion as shown in Table B-VIII-8.  The other 26 cases
were treated  in a similar manner, and the  result  was  a  set  of  nine
graphs  showing  the range  of  additional generation 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
-osts may increase in the smaller size units.

The  first three graphs. Figures B-VIII-1, B-VIII-2, and B-VIII-3, cover
aase-load units.  Additional generation costs ranged from a low of  0.60
nills/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
 fear remaining  life.    These  are  for  100%  (actually about 98%) heat
 removal.  As  indicated  en the  graphs,  it  was  necessary  to  increase
 turbine  exhaust  pressure  in  every  case to achieve 100% heat removal
                                 399

-------
                      TABLE B-VIII-8
             COOLING TOWER ECONOMIC  ANALYSIS
(300 MHe  Unit,  Peaking Service, Wet  Bulb Itemperatu:
Turbine
Exhaust Percent Percent Tower Tower Tower Pump Tota
Pressure of Heat of Water Range Approach Cost Cdst plus
in. Ha abs. Removal thru Tower l°F) (°F) $ $ 2S*
2 5
30 90 10 14 531,200 318,800 1,062
20 60 10 14 354,400 212,500 708
10 30 10 14 176,800 106,300 353
; 3.0 60 100 18 12 1,067,300 354,200 1,776
50 100 15 15 ! 749,400 354,200 1,379
40 95 13 , 17 | 561, 200! 336,500 1,122
3.5 . 77 100 i 23 ,12 i,2l4,90Q 354,200 1,961

4.0 93 100 28 12 1,351,100 354,200 2,131
80 100 24 16 931,000 354,200 1,606
70 100 22 18 , 772,100 354,200.1,707
4.5 100 100 30 15 j.,112,700 354, 200 [l, 833
90 100 27 18 874,300 354,200 ;1 , 535


6 Year 18 Year 30 Year
Life Life Ltft

500 318,800 201,900 159, 40C
Annual
Fan Oper-
ing Cos $
8,500
6,000
600 212 , 600 134 , 600 106 ,300 4 , 000
80q 106,100 67,200 53,100 2,000
900 533,100 337,600 266,500 12,000
Annual Total
Pump Dper-plus 10% Fan Pump
ing Cost for Main. Power Power
— tfl {*) Mfe Mfe
31..20.0.-
28 , 600
19,000
9,500
31,7J10
50CJ 413,800 262,100 207,000 8,400 j 31,700
10Q 336,600 213,200 166,300 6,200
40Q 588,400 372,700 294,200 13,700
q
60CJ 639,500 405,000 319, 70C
8,500
15,100
500 482,000 305,200 241,000 10,400
900 422,400 267, 50Q 211,200 8,600
600 5 50 , 1 00 348, 400 2 75 , OOC
600 460,700 291,800 230, 30C
1
1

12,500
9,800

31,700
31,700
31,700
31,700
31,700
. 44_,_200 .
38,100
25,300 ,
12,600
.7 \ ?._6__
.5 2.4
.3 1.6
.2 .8
48,000 1.0 2.6
44,100
41,700
49,900
44,200 ,
51,500
46,400 ,
31, TOO" j 44,400
31,700
31,700

48,600
45,700

.7 2.6
.5 2.5
1.2 2.6
.7 2.6
1.3 2.6
.9 2.6
.7 2.6
1.0 2,6
.8 2.6

Capital Annual
Capacity Total Cost of Cost Operating
Penalty Penalty Gas Turbine 15% Cost

0
3.3 __,. 101^500. 45,200 . 40_-2QQ
2.9 259,200J 38,900 34,600
0 1.9 171,900
0 1.0 85,500
1.4 ' 5.0 435,600
1 .4
1.4
2.7
2.7
4.7
4.7
4.7
6.8
6.8
q.7 i 408,600
4.4 ' 380,700
6.5 556,200
6.0 517,500
8.6 729,000
8.2 693,900
25,800 22,900
12,800
11,400
65,300 58,000
61,300
57,100
83,400
80,200
77,600
109, 40C
107, 60C
104, 10(
54,500
50,800
74,200
71,300
69,000
97,200
95,600
92,500
8.0 680,400 102,100 90,700
10.4 871,200 130,700 116,200






Fuel
Additional Generatinq Cost (mills/KWH)
Penalty 6 Year 18 Year 30 Year
Cost KeMining Remaining Remaining
0
0
0
0
18,000
18,000
18,000
35,800
35,800
35,800
65,100
65,100
65,100
65,100
88,200


2.9S i 2.14 1.84 -j 	 - i
2.34 1.70 1.47 j
1.56 1.13 .98
.77
.56 .49
3.93 I 2.86 j 2.48
3.22
2.74
4.80
3.96
3.50
5.23
4.90
4.29
3.94
5.08

2.39
2.07
3.62
2.98
2.67
3.96
3.74
3.33
3.10
3.98


2.09
1.83
3.20
2.62
2.37
3.49
3.32
2.98




2.79
3.58













-------
                                                    8.3°X:  (B3°F)
                                                    3.9°C  (75°F)


                                                  •13.9°C  I57°P)

                                                  Wet  Bulb
                                                  Temperatures
                                              5.5-Hg
                                                                             18 YEAR REMAINING LIP)
                                                                                             30°F Temperature Rise
                                                                                                                                 2B.3"C (B3->>
                                                                                                                                 23.9 C (75°P)

                                                                                                                                 13.9°C (57°F)
                                                                                                                                 Wet Bulb
                                                                                                                                 Temperatures
                                                                   !!"
                                                                           -  30 YEAR REMAINING LIFE
10   20   30   40    50    60    70    80    90   100
             Percent Heat Removed
10   20   30    40    50   60   70   80   90   100
                Percent Heat Removed
10   20   30   40    SO    60    70   80   90  100
                  Percent Beat Renoved
             Figures B-VTII-1,2,3,4,5

         ADDITIONAL GENERATING COSTS FOR

         MECHANICAL DRAFT COOLING TOWERS



             Base-Load Unit,  300HW
                                                    16.7°C  (30°F)  5
                              Condenser Pressures shown
                                      as "Hg abs.
                                                                               10   20   30   40   50   60   70    80   90  100
                                                                                                 Percent Heat Rejected
                                                                                                                                                                                                            . 6.7°C
                                                                                                                                 Temperature
                                                                                                                                   Rise
                                                                                                                                  16.7°C (30°F)
                                                                                                                                                                           75 °F Wet Bulb Teraperatu
                                                                               10   20   30   40   50   60    70    80    90   100
                                                                                                 Percent Beat Removed

-------
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-4 and B-VIII-5.  At heat removal fractions
above 50%, costs  are   significantly  higher.   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/m2 (3.5
in 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 re-
duced, 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-6,  B-VIII-7,
and B-VIII-8. 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 44%   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-VIII>9, B-VIII-
10, and B-VI11-11. 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
                                  402

-------
     2.4


     2.2


     2.0
§
    1-6
1.2


1.0


0.8


0.6
                            30°F Temperature Rise
            10   20   30   40    SO    60    70   80    90   1
                              Percent Beat Removed
                          ADDITIONAL GENERATING COSTS FOR
                                 300  HH CYCLIC UNIT
                              MECHANICAL DRAFT TOWERS
                                 6 YEAR REMAINING LIFE
                                  Figure B-VII1-6
    2.4

    2.2

    2.0

    i.a

    i.,
    0.6


    0.4


    0.2


    0.0
                                                                                                             •• "Hg aba.
                                                                                                                                                       !6.3°C (83°P)
                                                                                                                                                       3.9°C (75°F)

                                                                                                                                                      13.9°C (57°f)

                                                                                                                                                      Wet Bulb
                                                                                                                                                      Tamper at lire
                                                                                                               30  P Temperature Rise
                              Percent Heat Removal
                        ADDITIONAL GENERATING COSTS FOR
                                300 HIT CYCLIC UNIT
                              MECHANICAL DRAFT TOWERS
                               18  YEAR REMAINING LIFE
                                   Figure B-VIII-7
                                                                                                                                                      C2B.3°C (83
                                                                                                                                                      l23.90C (75°F)

                                                                                                                                                       13.9°C (57°P)
                                                                                                                                                      Het Bulb
                                                                                                                                                      Temperature
                                                                                                                                                                                                                           90
                                                                                                                                                                                               Percent Beat Removal
                                                                                                                                                                                                ADDITIONAL GEHERAHSG COSTS FOR
                                                                                                                                                                                                       300 MT CYCLIC OHIT
                                                                                                                                                                                                     KECHAVIOU. DRAFT TOWERS
                                                                                                                                                                                                       30 YEAR REMAINING LIFE
                                                                                                                                                                                                          Figure B-VHI-B
                        Percent Heat Removed
                     ADDITIONAL GENERATING COSTS FO1
                           300 HH PEAKING UNIT
                         MECHANICAL DRAFT TOWERS
                           6 YEAR REMAINING LIFE
                               Figure B-VIII-9
                                                                 23.9°C <7S°F)


                                                                  8.3°C (83°F)

                                                                  *3.9°C (57°F)

                                                                 Het Bulb
                                                                 Temperature
   12.0

   11.0

   10.0



i   '°

3_ "•"
4JB
Si 7.0

S
-------
additonal  generation   cost   with  change  in capacity factor,  all other
factors remaining the  same,  can be determined from Figure B-VIII-12.

The cost of backfitting mechanical draft towers  on  nuclear  units  was
also  determined,  using  the  same  techniques  employed 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 6,864 kJ/KWH (6,500
BTU/KWH) being rejected through the condenser.    Two  circulating  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 base-loaded, 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 70%.

The  costs  resulting   from  this analysis are shown in Figures  B-VIII-13
and B-VIII-14.  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.

Reference  368 presents nomgraphs which permit the estimation of cooling
system performance anc costs.

Energy  (Fuel) Requirements

Energy  significantly   in excess  of  that  normally  required  by   the
circulating  water system is required to operate all cooling systems ex-
cept 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  conditions
                                  404

-------
                                         CF

                                         -=— , comparison of capacity factors
                                           2
                                                  0.7    0.8   0.4    1.0
a
 0
 tj
 id
 -P
 •rl
 U
 (0
 P! W
 nj 2
 o S

 .p D)
 (0 H
  H
 -P -H
 W fi
 0
 O *
  B
 h co
 0) C
 C 0
 (U-H
 O -P
  n>
 H H

 S3
 0 H
 •H n>
 •P O
,-H
 •0 C
 •0 -H
      00
        QO   O.I   O.I   03   0.4-  0.5   06   07   OB  0.9   1.0   l.l    \

             Additional Generation Cost  at Capacity Factor  (CF  )  in
               Question,   mills/KWH
                               Figure B-VIII-12

           VARIATION OF ADDITIONAL GENERATING COST WITH CAPACITY FACTOR
                                  405

-------
o
o

§
•H ^~
•P 33
Id 3
C 01
0) H
O H


1~
O
i
     1.6
     1.4
     1.2
     1.0
     0.8
     0.6
     0.4
     0.2
     0.0
              Condenser  Pressures Shown
                       as "Kg abs.
         _ 23.9°C  (75°F)  Wet Bulb Temperature
                           2.5"Hg
                                                                Temperature
                                                                  Rise
                                                              16.7°C (30°F)
                                                           4.5"Hg
                     —^j—AJ—^o—E^J	/o—8^3—gV
                         Percent Heat Removed
                      ADDITIONAL GENERATING COSTS FOR
                           800 MW NUCLEAR UNIT
                         MECHANICAL DRAFT TOWERS
                          18 YEAR REMAINING LIFE
                          Figure  B-VIII-13
                                                                                            1.4  -
                                                                                            1.2  -
                                                                                            1.0
o
u
c
o
•H --^
C M
0) iH
O H
  •H
H e
1TJ v

0
-H
4J
•r-1
TJ
                                                                                             0.6
                                                                                             0.4
                                                                                             0.2
                                                                                            ,0.0
                       Condenser Pressures  Shown
                               as  "Hg  abs.
                                                                                                                   2.5"Hg
                                                                                                                                                       Temperature

                                                                                                                                                          Rise
                                                                                                                                                        16.7°C  (30°F)
                                                                                                               _L
                                                                                                                              _L
                                                                                                                                    _L
                                                                                                                                              _L
                                                                                                     10   20   30   40    50    60   70   80   90
                                                                                                                Percent  Heat Rejected
                                                                                                            ADDITIONAL GENERATING COSTS FOR
                                                                                                                 BOO MW  NUCLEAR UNIT
                                                                                                               MECHANICAL DRAFT TOWERS
                                                                                                                30 YEAR  REMAINING LIFE
                                                                                                                Figure  B-VIII-14
                                                                                                                                                    100

-------
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 coding 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 most of  the  years.   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-15)  is shown in fable B-VIII-9.  The
maximum penalty during any month is 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
5X of the time during June,  July, August and September.  For  the  plant
shown  the  maximum   penalty  is  2.1X.  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  cf  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 cf generating capacity imposed by a  closed-cycle
cooling system would  be  the  sum of the fan power and pump power require-
ments   (0.7X) and the maximum backpressure penalty  (2.IX), or a total of
2.8X 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
                                  407

-------
                                   Figure B-VIII-15


                  TURBINE EXHAUST PRESSURE CORRECTION FACTORS  (EXAMPLE/ PLANT NO0  3713)
o
00
                                                                    Throttle Flow
                                                                    1.5 x  10  lb/hr
                                                                    2.5 x  10 IbAr
                                                                    3.2 x  10
                                                                    4.2 x  10 lb/hr

                                                                    4.4 x  10
9  -P a»
*• G fO W
  •H 05 (0
      
-------
                                Table  B-VIII-9
      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
103
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
0.1**
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
  ** 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,

   * Notes  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.

*** Note: 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 duringQthe three months of summer. For plant no. 3713,
          this wet bulb temperature is 80 F and the maximum backpressure penalty is 2.1%.

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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.


The economic 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.  Seme  of  the  more  important  factors  are  the
following:

1.  Cost of needed land

2.  Layout of existing structures in plant

3.  Design pressure of existing circulating water system

U.  Soil conditions at the site

5.  Site geology and topography

6.  Replacement generating capacity cost

7.  Power requirements of system

8.  Cost of connecting unit, including loss of unit's capacity

9.  Related changes required within the station

10.  Reduction of non-water quality environmental impacts

Non-Water   Quality   Environmental  Impact  of  Control  and Treatment
Technology

General

The  potential  non- water  quality  environmental   impacts  which  could
influence  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.

4.  Height, creating aviation hazards.

5.  Water consumption by evaporative systems.

6.  Aesthetic considerations, visual impact of cooling  device.
                                  410

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The influence of  the  majority of these factors on the selection and cost
of the  installation of these cooling systems is summarized in  Table  B-
VIII-10, with a detailed discussion below of each factor included in the
table.

Size of Plant

The  use of  natural draft towers is normally limited to new units of 500
MW or greater.  While towers have been  built  for  smaller  units,  the
mechanical   draft  tower  would  probably  be more economical for older,
smaller units.  The size and number of towers would be  related  to  the
size and number of units served.


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-VIII-10.  Obviously, cooling ponds will need large
areas,  and  can  only  te  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  struc-
tures 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  (400 to 600 feet) to
avoid interference between towers.  Total area required for  two  towers
would be 4  to  7 times the tower plan area.

Reference   52   presents  the  following  discussion of recirculation 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 adjacent tower or other heat source.  These problems are
                                 411

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  Factor

Size of Plant
Relative Humidity
                                                                    TABLE B-VIII-10
                                                                 EFFLUENT  HEAT
                                                  APPLICABILITY OF CONTROL AND TREATMENT TECHNOLOGY
Mechanical Draft
Wet Cooling Tower

No limitation
No limitation
Natural Draft
Wet Cooling Tower

Greater than 500 MW

Generally  limited to  areas
of  the  country having an
average relative humidity of
greater than 47%.
Surface Cooling
(Ponds, Canals, etc.)

 No limitation
 No limitation
 Mechanical Draft
 Dry Cooling Tower

 No limitation
 No limitation
Land Area
Drift
 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.
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.
                                                                                         1-3 acres per Kw of capacity
                                                                                         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 immediate
                                                                                         area of pond, canal, etc.
                                    Higher than land require-
                                    ments of mechanical draft
                                    wet cooling tower.
                                                                                                                                 None
Fogging
Noise
Potential local problem depend-
ing on location s 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.
Little anticipated at ground
level.
                                 Less serious than mechanical
                                 draft towers, but still poten-
                                 tial problem if very close to
                                 sensitive area; noise can be
                                 attenuated.
 Potential local problem depending
 on location s climatic conditions.
                                                                                                                                 None
                                                                                         None
                                                                     Potential problem only if
                                                                     adjacent to sensitive area; can
                                                                     be reduced by attenuation devices.
Height
Water Consumption
                      No limitation
Up to 0.7 gallons per Kw hour
produced.
350-600 ft.; potential aviation
problem in specific locations;
comply with FAA restrictions.
Up to 0.7 gallons per Kw hour
produced.
                                                                   No limitation                      No limitation
 Up to 1.1 gallons per Kw hour           None
 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 MW per million
GPM  of circulating water; pump-
ing power - 7-12 MW per million
GPM of circulating water.
No limitation
Pumping power - 10-15  MW per
million GPM of circulating water;
no fan power required.
 Pumping requirements vary with
 plant conditions; spray modules
 generally 75 HP per unit.
                                                       Current design -120mph @ 30ft. elev.   No limitation
                                                                     No limitation
Greater than 3000 psf soil bear- Greater than 6000 psf bearing
ing value or equivalent with piles, value or equivalent with piles.

Applicable to all plants;penalty Generally applicable 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 ancl height.
                                                                     No limitation
Total power requirement -  .02-.08 MW
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 recpaire turbine re-design.
                                                                    No limitation

-------
nonexistent  on  hyperbolic  towers  because  of  the  height  of  vapor
discharge.S2

The  magnitude  of   recirculatioa  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 recirculaticn becomes increasingly severe along the length  of
the  tower.   Therefore,  as tower length increases, the more damaging a
longitudinal wind  can become.sz

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 td  the
ratio of  this  free  space  area  to  the  lee side louver area of the
tower.52

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.52

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
mulitple  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) number of cells
per tower,  (3) cell  length and height,  (4)  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.52 See
Figures B-VIII-16, 17 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
                                  413

-------
                                     X
             Prevailing wind-rose for
             high wet-bulb hours
                   Figure B-VIII-16
       BROADSIDE MULTIPLE TOWER ORIENTATION

Tower No. 2 placed typically in location a,b, or c
         relative to Tower No. 1 and the wind-rose
                       414

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in
          Figure B-VIII-17

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

-------
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 Comirission,  National Power Survey (1964)  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  400
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.

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 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  requirements  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
                                  416

-------
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  cf  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
gas-fired  100  to   200  acres, assuming en-site storage of coal and oil,
pipeline delivery of gas with same on-site storage, and on-site coal-ash
disposal.


Inspite 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 15X  of  the  total  (see Table IV-2) .  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 in 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
$250 per  hm2   ($10,000  per  acre)  in  small towns to $25,000 per hmz
($1,000,000 per acre) in the center of a large metropolitan area.

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
                                 417

-------
cooling  system   installation    unless   topographic   conditions  are
unfavorable.   However,  when   a  nuclear plant goes from open to closed
system cooling, the lew-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 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.


Additional Installation  Costs

The  cost  of installation of cooling towers can be significantly higher
at sites with adverse local  conditions.  Land with insufficient  bearing
strength    (see  Table   B-VIII-10)   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 require  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
condensers  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.

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 downtiire  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.  Some costs for the few plants  currently
involved in installing cooling  systems are given in Table B-VIII-1.

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
                                   418

-------
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.

some  data on estimated solids in  drift from cooling towers are shown in
Table B-VIII-11.  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-11.

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 0.2% were  guaranteed.
MO NOW  cooling  tower  manufacturers are guaranteeing much lower drift
losses.  Losses of 0.02%  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  0.0053J,  while  that  from
natural-draft  towers  might   average   half of that, or 0.0.025%.  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 determine  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 intermittently.

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  implied  by  the  term
"isokinetic11.   One  device uses a  sampling tube filled with warmed glass
                                 419

-------
                                        TABLE B-VIII-11

                             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
Solids in Drift
Ibs . /yr .

3.8 x 107
6 x 105
1.1 x 10^
4.0 x 105
9.0 x 104
10.5 x 105
4.7 x 104
Ibs/KWH 3
(installed)xl°

3.3
.042
.14
.054
.012
.070
.0065
ro
o

-------
beads.  A vacuum system pulls the  sample into the tube where  the  drift
impinges  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  devices  considerably  more  cumbersome,  and pf
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
85X  of  the  mass of the drift  have diameters greater than 100 microns,
with  less than 1% over  500  microns.

The  drift  from  cooling   towers,  mechanical  draft   in   particular,
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  and  in  use  or  planned  for  steam  electric
powerplants.   Numerous   factors affect the dispersion and deposition of
drift from these towers  (See Table B-VIII-12)-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-18) .   This  is  particularly  true for mechanical draft towers which
discharge at relatively low levels.   Tests . at  one  installation  have
shown that  up  to two-thirds  of  the drift hits the ground in the first
400 feet from the tower  and substantially all drift droplets will  reach
the  ground in the first  1,000  feet.  In many instances therefore, drift
impact can be reducted  by location of the tower so that the bulk of  the
drift is contained within plant boundaries.

Wistrom  and  Ovand'63   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
                                421

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                                             Table  B-VIII-12

                               FACTORS AFFECTING DISPERSION AND DEPOSITION OF DRIFT
                                 FROM NATURAL-DRAFT AND MECHANICAL-DRAFT TOWERS 385
       Factors associated with the design
       and operation of the cooling tower
                                        Factors related to atmospheric
                                        conditions
                                        Other factors
ro
ro
Volume of water circulating in the
tower per" unit time

Salt concentration in the water

Drift rate

Mass size distribution of drift
droplets

Moist 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
non-point source
geometry

Collection efficiency
of ground for drop-
lets

-------
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                      Figure B-VIII-18

        Ground-Level Salt Deposition Rate From A Natural-Draft Tower

        As A Function Of The Distance_Downwind.  A Comparison Between
              Various Prediction Methods
                                      385
                                423

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salt  load,  particularly   along  ocean coasts exposed to continual wave
action, can be fairly  high.   If  the tower drift results in  a   salt  load
of  only  a few percent  of this  natural salt deposition rate,  the effect
would probably be minimal.

A summary of the state-cf-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 enviornmental effects  are aparse.  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  availab-le 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-VTII-19  shows  representative  con-
ditions 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  100%  saturation.   In this condition condensation
producing fog can  occur,   although  normally  some  supersaturation  is
necessary.   As more mixing occurs, the air condition eventually returns
to point B.
                                  424

-------
                                                            Saturation
                                                            (100% RH)
4J H
•H
1° £
  (0
•H M
•H tJ
U
S -0
ftH
to\
                                                           80% RH
                                                             120
                       Dry Bulb Temperature  (  F)
                           MODIFIED PSYCHROMETRIC CHART
                               (From Reference  128)
                                 FIGURE B-VIII- 19
                                   425

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The development of fog by cooling devices is  primarily dependent 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, 2i«, defines three  levels of potential for
fogging, as listed below.

    a«  High Potential;  Regions where heavy  fog   is  observed  over  45
    days per year, where 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 20-3035.

    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,  EGSG  has
developed  the  map  shown  in  Figure E-VIII-20,  indicating  the fogging
potential of locations within the United States.

The length of the expected fog plume  can be estimated from
the following equation: 9S
    Xp = 5.7(Vg)i«2  (438Vm)»»2   (Tge-Tgi) t«z   (Tp-Tgi)-»«z


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 m^/hr  (gas evaluated at 20°C)

       i = tower inlet

       e = tower exit

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-20,  most  of  the major U.S.  residential, commerical and
industrial centers do not lie in the  area of  high fogging potential.
                                  426

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ro
             J SLIGHT POTENTIAL
               HIGH POTENTIAL
              MODERATE  POTENTIAL
                                                          Figure  B-VIII-20

                                   GEOGRAPHICAL DISTRIBUTION  OF POTENTIAL  ADVERSE EFFECTS FROM COOLING TOWERS,
                                      BASED ON  FOG. LOW-LEVEL  INVERSION AND LOW MIXING  DEPTH FREQUENCY.

                                           (From Reference 219)

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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 could 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-19) 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 A1,   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  construction  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.  Other possible techniques
of plume  abatement  includes  increasing  the  mechanical  draft  stack
height,  heating  tower exhaust air with natural gas burners, installing
electrostatic precipitatcrs 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
500 •)  above  the tower ground level, and there is little possibility of
local fog hazards, as 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-21 2«3, which shows 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   condition  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
                                   428

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                 Figure  B-VITX-21
LOCATION OF NATURAL DRAFT COOLING TOWERS THROUGH  1977
                 (From Reference 283)

-------
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   283, for EPA on the field tests at Plant no.
4217 in Pennsylvania  determined that the  effects  were  minimal.   This
plant  released approximately 0.63 m3/s (10,000 gpm)  and 126 KG/min (120
x 106 BTU/min) to the atmosphere when operating at 1440  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 "a 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  lew   stratus clouds when they were at an appropriate
elevation.

The current "state-of-the-art" in meteorology has not progressed to the
point  where the effects  of  large thermal  releases to the atmosphere can
be quantitatively evaluated.  Improvements in meteorological  techniques
currently in progress 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-13.  367    It is  obvious that some of our arti-
ficially 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   triggering  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
                                   430

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                                         TABLE B-VIII-13
         ENERGY PRODUCTION OP SOME NATURAL AND ARTIFICIAL PROCESSES AT VARIOUS  SCALES (367)
          Area
            (m2)
                          Natural Production
       Event
 Rate
(W/m2)
                                           Artificial Production
    Type of Use
 Rate
(W/m2)
CO
        5 x 1014


        1012
        10
          8
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
  25
                                                   200
                                                  5000
Man's ultimate energy
production

Northeast U.S. ultimate
production  (10** people,
20 KW each)

Super energy center or
city
                                                             Dry cooling tower for
                                                             1000-MW  (e) powerplant
  0.8
                                     2.0
                                     1000
                                     105

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stack   gases   and  the  cooling   tower  fog  plume  became  intimately
intermixed, the fog will interact chemically with the S02, forming  sul-
furic  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 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   quantitites  of  air  moving  through
restricted spaces, and large volumes  of   falling  water  contacting the
tower  fill and cold water basin.   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 cf 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.
                                  432

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Only if  the tower noise level exceeds the acceptable  noise  level  need
corrective  action be taken
     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 wet tower
there is  the added fan noise.  In the mechanical draft dry  tower  there
is the fan noise and 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 samerorder of magnitude as
that in the rest of the station, and thus noise  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.

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
accoustically 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  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  tower  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.
                                433

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Consumptive Water Use

All evaporative heat rejection systems  result in the consumptive 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.

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" a*,   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-22, taken from a  paper by Woodson, 3iar  gives
a graphic representation  of the percentages  of heat  transferred by   each
process.   In  a  report  prepared  for  EPA,   104,   some representative
consumptive use rates for a 1000 MW unit  are shown  (see  Table  B-VIII-
14) .   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-VII1-15.  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-23.  133 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 of 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 increase  averages  about  25% as
shown  in  the  referenced  tables  and  graphs,  and  only presents the
absolute difference in water  consumed.
                                 434

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OHCE-THROUGH
     OR LAKE
COOLING
BASIN COOLING
WITH SPRAYS
WET COOLING
TOWER
 WET/DRY
 COOLING TOrfER
 DRY COOLING
 TOWER







RADIATION. AND CONDUCTION
EVAPORATION
i




RADIATION AND" CONDUCTION

EVAPORATION
j
I



RADIATION & CONDUCTJ,



EVAPORATION j




CONDUCTION



EVAPORATION j






CONDUCTION j
EVAPORATIO

I
1






1
CONDUCTION










                  0%    10%   20%   30%   40%   50%  60%   70%   80%   90%   100%
                                  Figure  B-VIII-22
                           HEAT TRANSFER MECHANISMS
                       WITH ALTERNATIVE COOLING SYSTEMS

                              (From  Reference  318)
                                     435

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                             TABLE B-VIII- 14
      EVAPORATION RATES FOR VARIOUS COOLING SYSTEMS  (Reference  104)
Cooling System

Cooling Pond (2 acres/MW)

Cooling Pond (1 acre/MW)
Mechanical Draft Tower
Spray Pond
Natural Draft Tower
Natural Lake or River
Evaporat
m-Vsec
.566

.453
.368
.360
.340
.266
. ion1
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).
                                     436

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                                                          TABLE  B-VIII-  15
                                           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
BTU/KWH

Fuel
Input
Billions of
BTU/ yr . -

Coal
Consumption
10,000 btu/lb
tons/yr

Water
Consumption
( Evapor at ion)
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
1,1?3
59

79
429
321
358
4,682
246

3,950
?1,450
16,050
17,900
?34,100
12,300

5,400
6,300
6,300
2,800
*(2,800)
6,300
1,000
500
15
15
6
15
OJ
               *Denotes  Decreased Requirements
(From Reference 318)

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                                 2 ACKF.S/MW
                                  1 ACfit/MW
                        MECHANICAL DRAFT C.7,
                     SPRAY PONDS
               NATURAL DRAFT C.T.
                            NA1URAL LAKE OR RIVER
           50        60
            WET BULB TEMPERATURE <
   WATER  CONSUMPTION VERSUS
   WET BULB TEMPERATURE
                                                                 NAJUSAL LAKE 03
                                                              MECHANICAL DRAFT C.T.
                                                           SPRAY PONDS
                                                        NATURAL DRAFT C.T.
                                                          EO        60
                                                    RELATIVE HUMIDITY • %
                                           WATER  CONSUMPTION VERSUS
                                           RELATIVE HUMIDITY
              1  8   9  JO  11
               WIND SPEED • MPH
                    12  13  14  1$
  WATER  CONSUMPTION VERSUS
  WIND SPEED
                                              GAL.Net KWH
                                               1.2
                                               1.0
                                                                     2 ACRES MW
                                                                    NATURAL LAKE OR RIVER
                                          10   20
                           30   40  50  60   70
                              CLOUD COVER• %
                                                                     60  90  100
                                         WATER CONSUMPTION VERSUS
                                         CLOUD COVER
CAL/Net KWH
I.I
t.O
.9
.6
.7
.6
.5
.4
.3
.2
.1
0
\
                10       15
               COOLING RANGE -°f
                      2 ACRES MW
1 ACRE MW
                      20
                             25
                                    CAl/Net KWH
                                    .60
                                           1* 16 IB  20 ?? 71  76 J8 30 32 3< 36 38 40
                                                   COOLING HAI.Ct -°f
    WATER CONSUMPTION VERSUS TEMPERA-
    TURE  RANGE FOR BODIES OF WATER
                                      WATER CONSUMPTION VERSUS TEMPERATURE
                                      RANGE FOR COOLING TOWERS

                         (From  Reference  133)
                          FIGURE B-VIII-  23
WATER  CONSUMPTION VERSUS METEOROLOGY AND COOLING  RANGE
                          438

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present powerplants 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  where water uses 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.

Pollutants in 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 and drift 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 CaCO.3 and CaS04.  The CaCO3  can  be  controlled  by  pH
adjustment, with sulfuric acid normally being used to lower the pH.  The
CaS04  scale  formation   is   avoided  by maintaining the concentration of
CaS04 below saturation.   The CaSOjf 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  cooling 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
                                 439

-------
previously used to a  large  extent,  their use  has  decreased  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 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 thermal discharge could
be  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 ether 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
                                  440

-------
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  have  suggested.   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  architectural  plan
have not been finalized,  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 angles 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 surrounding area.
Plant no. 2612 is using the low hills surrounding 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 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
                                 441

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the  landscape.   Landscaping   of   cuts  and fill areas will normally be
required.

Spray canals can be very  pleasing   to  the  eye  if  properly  designed.
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 irinimize 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  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    as  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  hct   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  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  irore 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.
                                   442

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 comparison of Control  Technologies


The available control and  treatment technologies for effluent  heat  are
compared  in  Table  B-VIII-16   based  on incremental costs (production,
capital, fuel, and capacity), effluent reduction benefits, and  nonwater
quality environmental impacts.

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-17-  A similar costs
breakdown for new units  is given  in  Table  B-VIII-18.   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 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 benefi-ts
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 (a)

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
                                  443

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                                                                 TABLE  B-VIII-16
                                                     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)
Unaugment ed
Augmented
Evaporative (Wet) Tower
Mechanical Draft ( 250 )
Natural Draft (60)
Dry Tower (1)

Wet/Dry Tower ( 1 )
Alternative Processes
Hydroelectric (100 ' s)
Internal Combustion (100 ' s)
Combined Cycle (approx. 50) c
INCREMENTAL COST FOR MAX. EFFL. RED.
% Base
Production
0
100
10-20
10-20
10-20
10-20
20-40

14-28

0
100
PP 50
Capital
0
100
9-14
9-14
9-14
9-14
11-16

10-15

0
100
PP 50
Fuel
0
15gai
1-2
1-2
1-2
1-2
4-5

2-3

lOOgai
0
app SOgai
Capacity
0
n ISgair
3-4
3-4
3-4
3-4
7-10

4-5

n 0
0
n 0
EFEL. 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
o

0
Drift
0
0
0
*
*
0
0

*
I
0 0
0 0
0 0
Noise
0
0
0
0
*
0
*

*

0
*
*
Aesthetics
0
0
0
*
*
*
0

0

0
0
0
Land
0
0
2000
1000
30
30
30

30

2000
0
0
Water Consumption
0
0
100
2QO
200
200
30gain

35

SOgain
lOOgain
SOgain
* Note: Some highly site-specific  incremental  impacts,  but not generally anticipated to be limiting.

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                                                                  TABLE B-VIII-17
                                  INCREMENBXL COST OF APPLICATION OF MECHANICAL DRAFT  S7KPO8&TIVE COOLING TOWERS TO
                                                       NONNEW UNITS  (BASIS 1970 DOLLARS)
TYPE UNIT REMAINING tIFE
Years

X. 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

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                                                                           TABLE B-Vin-18
                                            INCREMENEftL 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
$/[MWH]
xlO
3

3
4
13
INCREMENTAL CAPITAL COSTS
% of Base Cost

9

9
10
11
Sost/Benefit
$/[MWH]
xlO
1

2
4
18
ADDITION*!, FUEL CONSUMPTION
% of Base Fuel
Consumpt ion
1

1
1
1
Cost/Benefit
[MWH] /[MWH]
xlOO
r
2

2
2
2
GENERATION CAPACITY REDUCTION
% of Base Gen-
erating Capac.
3

4
4
4
Cost/Benefit
MW/[MWH]
xlO' 1
1

1
1
4
Assumptions :
> TYPE UNIT
r*
I. Nuclear
-I. 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
$/KW
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/KWH
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.. $/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]/Btu.

-------
environmental need.  Correspondingly,  the timing for  cases  leading  to
significant  thermal   controls  could extend in many cases beyond July 1,
1977.  See Table B-VIII-19.   The Act does not  authorize  extentions  of
the  implementation   dates   for  best  practicable  control  technology
currently available at individual sources to dates after July  1,  1977,
even in consideration  of  Section 316(a).

EPA estimates of  the  number of various, types of units that will require
some thermal  controls based  on  environmental  need  (Section  316(a)
determination) are shown  in  Table B-VIII-20.

The incremental   U.S. fuel  consumption  of  thermal controls based on
environmental need (Section  316(a)  determination)  can be estimated based
on the following assumptions:

    1) One-haJ-f of the plants with once-through cooling systems have  no
    thermal effluent limitations.

    2)  "No discharge" thermal controls are required for one-half of the
    capacity of remaining once-through plants during 3-4 months  of  the
    year, scattered, in the  aggregate, year round.

    3)  Thermal  effluent limitations will be met using mechanical draft
    evaporative cooling towers.  (This is highly conservative since  all
    other technologies, except dry cooling towers, use less energy).

    4) Equal controls  regardless of fuel types.

    5) No net changes  from distribution shown in Figure III-l.

The estimated  incremental   consumption  of  fuels,  based on the above
assumptions, is 0.12%  increase in nuclear fuel, 0.06% increase in  coal,
0.02%  increase  in  natural  gas, and a 0.01% increase in oil, by 1980.
This result is shown in graph form in Figure B-VIII-24.  Further,  based
in  a  similar analysis, the  annual incremental oil consumption assuming,
conservatively that all thermal controls needed are  added  by  July  1,
1977,  is shown in Table  B-VIII-21.  Incremental oil consumption is zero
unitl  July 1, 1977, with  the 1980 level estimated at 41,000 barrels  per
day,   compared to  a projected total U.S-. oil usage of 21,500,000 barrels
per day by 1980.
                                   447

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                                    Table B-VIII-19




                TIMING FOR CASES LEADING TO SIGNIFICANT  THERMAL CONTROLS



                                  BY JULY  1,  1977
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
Jul 1974
Jul 1974
May 1974
May 1974
Aug 1974

Feb 1976
Jul 1977
Jul 1977
LIKELIEST
Mar 1974
Mar 1974
Mar 1974
Jul 1974
Jul 1974
Jun 1975
Jul 1975
Oct 1975

Jul 1977
(Dec 1978)
Jul 1977
LATEST
Mar 1974
Mar 1974
Mar 1974
Jul 1974
Jul 1974
Nov 1975
Feb 1976
May 1976

(May 1978)
(Oct 1979)
Jul 1977
00
             )  indicates noncompliance with 1977 date

-------
                                    Table B-VIII-20
vo
                 ESTIMATED NUMBER OF UNITS REQUIRING THERMAL CONTROLS
                            BASED ON ENVIRONMENTAL NEED
             Type of  Unit
Base-Load

  Completing construction
    after July 1, 1977

  Completing construction
    prior to July 1, 1977

  • Capacity 500 MW and
      greater

  • Capacity 300 to 500 MW

  • Capacity less than
      300 MW*

All Other Units
                            Total Number
                             of Units
                                            40
                                           260


                                           200

                                          1000


                                          1500
Number Already Com-
mitted to Controls
        20
        80


        50

       250


       300
Number Requiring Some
  Controls Based on
 Environmental Need
        10
        90


        50

       350


       600
            * Note: Excludes units in plants under 25 MW or in systems  less  than 150  MW

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  w
J
ji EH
°§
                                                  Figure B-VIII-24
                     ESTIMATED  U.S.  ENERGY SITUATION (1980) RELEVANT TO ENVIRONMENTALLY-BASED CONTROL
                            OF  THERMAL DISCHARGES FROM STEAM ELECTRIC POWERPLANTS
                                             POWER
AT PLANTS
NEEDING
NO CONTROL
                            AT PLANTS
                            NEEDING
                            SOME CONTROL
                    CONTR
                     OLLED
                     ALREADY CONTROLLED
                                               NATURAL GAS
                                                   OIL
                                           FRACTION TOTAL ENERGY

                                             — BY FUEL SOURCE —

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                                   Table  B-VIII-21
                 INCREMENTAL OIL CONSUMPTION  IP ALL ENVIRONMENTALLY-BASED
                        THERMAL CONTROLS ARE  ADDED  BY JULY 1,  1977
en
YEAR



1974
1975
1976
1977
1978
1979
1980
TOTAL PROJECTED OIL CONSUMPTION
BY PCWERPLANTS

thousand barrels per day
2,200
2,400
2,600
2,800
3,000
3,200
3,400
MAXIMUM* INCREMENTAL
OIL
CONSUMPTION DUE TO
THERMAL CONTROLS
thousand barrels per
0
0
0
17
36
38
41

day







         * Note: Based on the application of mechanical draft cooling towers, which
                 consume more incremental energy than do alternative technologies

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                                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
Cat e gor ization
Steam electric powerplants utilize  heat released from suitable fuels  to
produce  steam  which,   in turn,  drives turbine generators which produce
electrical energy.  The  used, expanded steam is condensed into water  by
rejecting  unusable  waste   heat  into  a  cooling  water  circuit.  The
condensed  steam,  now   high-purity  water,  is  then  returned  to  the
powerplant boiler ready  for  re-use.   The rejected heat must be discarded
to the environment.

Steam  electric  powerplants  (stations)   are  comprised  of one or more
generating units.  A generating unit typically consists  of  a  discrete
boiler,  turbine-gen era tor   and   condenser  system;   however, some units
employ  multiple  boilers  with   common  headers  to  multiple  turbine-
generators.   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.

While  there  are  no  formal subcategories,  differences in age, size,
processes employed, etc., were considered in development of  limitations
and are  reflected  in  the limitations  and in the dates by which the
limitations must be achieved.  Because technology for  the  control  and
treatment  of heat is specific to that parameter and higher in cost than
technology required to control other parameters, the guidelines for heat
were developed  separately.  Guidelines  for  other  parameters  apply
(generally)  to  all generating units because factors such as age, size,
etc., are not correlated with waste load or practicability of  employing
control technology.

The characteristics  of waste   water heat discharges and the degree of
practicability of control and treatment technology for heat are  closely
associated  with  characteristics  of  the  individual  generating units
employed.  The most significant factors governing the quantity of  waste
heat generated relative to  the electrical energy produced  (a measure of
                                 453

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the process  efficiency)   are  the  characteristics   of   the  generating
process  employed.    The   significant  process  factors   include the raw
materials  (fuel)  employed, the boiler design pressure and  temperature
cycle  characteristics such as reheat and regeneration,  and the turbine
characteristics.  Generally the newer, larger, more-efficient units  are
assigned  base-load  service and the older, smaller, less-efficient units
are used for meeting peak demands.   The  type  of  service   (base-load,
etc.) and remaining  service life characteristics are  significant factors
affecting  the  degree of  practicability of attaining  effluent reductions
relative to the quantities of heat generated inasmuch as  they determine,
in combination, the  airount of corresponding electrical energy production
to which the control and  treatment costs are compared.

The  1970 National Power Survey, a report 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  must be  able to respond readily to swings in systems
demand, or  cycling.   Units  used  for  base-load  service   produce 60
percent,  or  more,   cf  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   average boiler
capacity factors  for  each  boiler.   The  boiler  capacity  factor is
indicative  of  the   gross generation of the associated generating unit.
The  net generation is less than the gross generation  to the  extent  that
electricity is  used  by the plant itself.

The  operations  and economics of nuclear power generation dictate base-
load service  for these   units  inspite  of  the  significantly larger
quantities of waste  heat  rejected to cooling water compared  to otherwise
similar  fossil-fueled base-load  units.   Similarly,  all  of the large
high-pressure,  high-temperature, fossil-fueled units  have been  designed
for  base-load service.

The  base-load  units  placed  in  service  in the 1960«s had as of 1970
approximately  15  or  mere   years  of  base-load  service   remaining,  but
eventually  the installation of more economic base-load generating units
may  make it desirable to  convert certain  units  to   cyclic   or  peaking
service.   However,   some  fossil-fueled units have been  initially built
for  cyclic or peaking service, beginning in 1960 and  extending  to  the
present.   Features   of  units  designed  for  cyclic or  peaking service
include the absence  of the use of coal as a fuel,  high-pressure,  high-
temperature   steam   conditions, reheat stages, and some additional feed-
water heaters which  are normally used with most base-load units.
                                  454

-------
Base-load units represent approximately 70. percent  of  the  total  U.S.
installed  capacity   of   steam-electric  powerplants,  cycling  units 25
percent, and peaking  units 5 percent.   However base-load  units  account
for   approximately  90   percent  of the total U.S. steam electric energy
generation, and therefore, approximately 90 percent  of  total  effluent
heat.   Cycling  units account for approximately 10 percent of the total
effluent heat, and peaking units less  than 1 percent.

Waste Characteristics

Steam electric powerplants discharge about 50 trillion gallons of  waste
water per year, which is roughly 15 X of the total flow of waters in U.S.
rivers and streams.   Almost all of this water contains heat added by the
powerplants.

Control and Treatment Technology

Thermal  (waste  heat)   control  arid  treatment  technologies are of two
general types; those  which are designed  to  reduce  the  quantities  of
waste  heat  rejected  from the process in relation to the quantities of
electrical energy  generated and those which are designed to eliminate to
some degree the reliance upon a navigable water body as  an  intervening
step leading to the ultimate transfer of the rejected heat to and beyond
the  atmosphere.   The former type of thermal control is confined to in-
process means, while  the latter takes  the  form  of  external  devices,
other  than  navigable   water  bodies,  which  extract  heat  from  the
circulating cooling water after it obtains  the  rejected  heat  at  the
condenser.   For   the  purpose  of effluent heat reduction the latter is
clearly the most cost effective over the range of  significant  effluent
reductions.

External thermal control means take the form, on one extreme, of surface
water  bodies  confined   to  the property of the powerplant; and, on the
other, of configured   engineering  structures.   Other  methods  between
.these  extremes  combine engineering equipment with the confined surface
water bodies.  The configured engineering structures (towers)  are  more
universally  applicable   than  means  involving  to  any degree confined
surface water bodies  due to the significantly larger land  areas  needed
for the latter*

Cooling towers  are  available utilizing any one, and in some cases more
than one, of the following combinations of engineering  characteristics:
evaporative or nonevaporative, mechanical draft or natural draft, forced
mechanical draft or induced mechanical draft, fan-assisted natural draft
or unassisted natural draft, and crossflow or counterflow.  The specific
type  of  cooling  tower  most  widely  used at powerplants today is the
crossflow, induced mechanical draft, evaporative tower.   Theoretically,
a cooling tower of any type could be designed to remove a part of or all
of  the waste  heat   rejected by any powerplant.  In practice, however,
site-dependent factors prevail which can preclude the application of any
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particular means for any particular  powerplant and which further lead to
•the  selection  of  the  rrost  appropriate  means  from  the   remaining
candidates due to cost and other  considerations.

Mechanical   draft  evaporative   cooling   towers   are  in  operation  in
conjuntion with approximately  200-300  or  more steam electric  generating
units  in  the  U.S. cut of a  total  of about 3000 units at approximately
1000  plants.   Natural  draft evaporative   cooling  towers  have  been
constructed, or are on order,  for approximately 60 additional generating
units.  Between 50 and  100 more units  employ unaugmented or mechanically
augmented  cooling  lakes,  ponds and  canals.   One dry (non-evaporative)
cooling tower is in use in. the U.S.  In most cases,  the external thermal
control means are employed to  completely  recirculate the cooling  water,
except  for  the  relatively   small  amounts discharged in the bleed*  or
blowdown, necessary for control of cooling water  chemistry to achieve  a
practical  degree  of  corrosion  and scaling protection.   In this manner
essentially  100% of the waste  heat rejected   to  the  cooling  water  is
removed and  tranferred directly to the atmosphere.

In  establishing  effluent  limitations  reflecting  levels of technology
corresponding to to best practicable control technology currently avail-
able  (to be  achieved  no  later   than   July   1,  1977) ,  best  available
technology economically achievable (to be achieved no later than July  1,
1983),  standards  of  performance  for  new  sources,   and pretreatment
standards, it  must  te  concluded  that   there  is   only  one  suitable
technology   available  and demonstrated, • evaporative external cooling  to
achieve essentially nc discharge  of  heat, except  for cold-side blowdown,
in a  closed, recirculating cooling system.   The judgments  involved are
therefore  reduced  tc  the determination of the  types of units to which
the technology should be applied  and when it should  be applied,  in the
light of  incremental  national-scale costs  versus effluent reduction
benefits  as well  as  unit-by-unit  costs   versus   effluent  reduction
benefits and other factors.


In  consideration of the total costs of the  application of technology  in
relation to  the effluent reduction benefits  for heat, and other  factors
including  energy and other non-water  quality environmental impacts, the
effluent limitations  corresponding  to  the  best  practicable  control
technology currently available are no  discharge of heat except for cold-
side  blowdown,  for all large base-load  units the construction of which
is completed after July  1,  1977,  as  is reflected  by  the  application  of
closed-cycle  evaporative   cooling   systems.   The  mechanical  draft
evaporative  cooling tcwer provides the basis for  the  analysis  used  to
evaluate  the  costs, effluent reduction  benefits and other factors.   No
limitation   on  heat  is  reflected  by  the  best  practicable  control
technology   for  cyclic  and   peaking   units.    No limitation on heat  is
reflected by the best practicable control  technology  for  units  with
insufficient land  available  for  mechanical  draft  towers, including
spacing, or  where salt water drift from mechanical  draft  towers  could
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adversely  impact  neighboring  land  uses,  provided   no   alternative
technologies  would  be  practicable.   In  addition,  for all units the
construction of which has been or will be completed by July 1, 1977,  no
limitation  on  heat  is  reflected  by  the  best  practicable  control
technology, since, as more fully explained below, the limitation  of  no
discharge  of  heat  except  for  cold-side  blowdown is not practically
achievable by July 1, 1977, the date mandated by the Act for achievement
of best practicable control technology currently available.

In consideration of the relevant factors including those required in the
Act, such as the cost  of  achieving  effluent  reductions,  energy  and
non-water   quality  environmental  impacts,  the  effluent  limitations
corresponding to the best available technology  economically  achievable
are no discharge of heat, except for cold-side blowdown, for all but the
very  oldest  base-load  units  not  covered by best practicable control
technology currently available and for all cyclic and peaking units,  as
is  reflected  by  the  application  of closed-cycle evaporative cooling
systems.  The mechanical draft evaporative cooling  tower  provides  the
basis  for  the  analyses  of costs and other factors.  No limitation on
heat  is  reflected  by  the  best  available  technology   economically
achievable  for units where sufficient land cannot be made available for
mechanical draft towers, including spacing.

The time required  for  owners  and  operators  of  base-load  units  to
complete   the   procedures   for  the  consideration  by  the  Regional
Administrator of exemptions to the  effluent  limitations  on  heat,  as
provided  by section 316(a) of the Act renders an effluent limitation of
no discharge of heat except for cold-side blowdown outside the scope  of
best  practicable  control  technology  currently available for any unit
which must achieve such limitation before July 1,  1977.   An  owner  or
operator  following  the  procedure  but failing to demonstrate that the
effluent limitation proposed is excessively stringent could  achieve  an
effluent  limitation  of  no  discharge  by  July 1, 1977, under only an
optimistic set of conditions, if construction of the control  means  was
not  begun  until  after  completion  of  the section 316(a) procedures.
Hence, universal achievement of no discharge of effluent limitations  by
existing  base-load  sources, by July 1, 1977, would not be realistic in
the light of the time required for section 316(a) procedures.   The  Act
contains  no  provisions which would allow for the delay of the required
date  for  the  application  of  section  301  effluent  limitations  in
individual  cases.   However,  since  the  Act  requires  that  effluent
limitations reflecting the application of the best available  technology
economically achievable by "no later than" July 1, 1983, it is concluded
that  these  regulations  can  require  that the effluent limitations be
achieved by certain dates prior to July  1,  1983,  if  such  dates  are
realistically achievable.  Correspondingly, the realistic achievement of
the   goals   of   the  Act  would  be  served  if  dates  for  complete
implementation of best available technologyzeconomically achievable were
established that were realistic but not far past the 1977 horizon.  This
can be accomplished by limiting the coverage  of  the  best  practicable
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control technology currently available  to  the relatively small number of
sources that would not be completed  until  after July 1,  1977.  Since the
scheduled  dates  for completion of  construction for these sources would
be distributed over the years 1977 to 1982,  a  no  discharge  limitation
would be realistically achievable by the time the affected sources would
become  operational.   Realistically achievable dates for the base-load
units constructed before July 1, 1977,  would be as follows:

1.capacity of 500 MW and greater: July  1,  1978

2.capacity 300 to 499 MW: July  1, 1979

3.capacity 299 MW and less, except for  small units:  July 1, 1980

4.small units, i.e., unit in a  plant with  a  capacity less than 25 MW or
in a system with a capacity less than 150  MW:  July 1,  1983.

The proposed best practicable control technology currently available and
best  available technology economically achievable for heat are based on
the above rationale.

In consideration of the relevant factors including those required in the
Act, such as the cost of achieving effluent  reductions,  energy and  non-
water   quality   environmental  impacts,    the   effluent  limitations
corresponding to standards of performance  for new sources for  heat  are
no  discharge  of  heat,  except  for   cold- side blowdown, from all new
sources, without variation.

Cost of Technology

The unit costs of the application  of   available  external  control  and
treatment  technology  for  heat to  generating units of  various sizes is
essentially invariant with size, over the  range  of  present  processes,
due   to  the  general  availability of   small  modules  applicable to
incremental loads.

Factors affecting the incremental costs of effluent heat reductions  for
any particular generating unit  are dependent upon the characteristics of
the   plant   site,   as   follows:   available  land,  generating  unit
configuration   (accessibility   of  existing   condenser  cooling  system,
ability  of  space  to  accomodate   a   new  circulating  cooling system),
requirements imposed by nearby  land  uses   (drift,  fogging  and  icing,
noise,  structure  height and appearance), climatic considerations (wind
direction and velocity, wet bulb  temperature,  relative  humidity, dry
bulb  temperature, equilibrium  temperature of natural (surface)  cooling,
soil bearing characteristics, significance of regional  consumptive use
of  water,  significance  of  impact on regional demand availability of
power to consumers, and characterisitics of  intake  water  (temperature,
concentrations of dissolved materials).
                                   458

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The  significant  costs  of  external  cooling  systems  themselves  are
determined   characteristically   by   three  major  engineering  design
parameters:   the cooling water flow  rate,  the  rate  of  heat  removal
required, and the difference between the desired temperature of the cold
water  returned  to  the  condenser  and  the  lowest  cold water return
temperature  theoretically  achievable.   Other  major  costs  generally
associated  with  applying  external  cooling  in  the  place of systems
employing no external  cooling  means  are  attributable  to  additional
piping  and  pumps and to the physical alterations in the cooling system
that are required by the  conversion.   The  incremental  energy  (fuel)
consumption  costs  of external cooling system are determined largely by
the additional pumping energy required, the power required to drive  the
circulating  air  fans,  and  in  most  cases  where  the  cooling water
discharged from the  external  cooling  means  is  recirculated  to  the
condensers,  the  increase  in  waste  heat  rejected due to the process
energy  conversion  inefficiency  imposed  by  the  resulting  increased
turbine  exhaust pressure.  A further cost of external cooling means can
be the reduced  margin  of  reserve  generating  capacity  of  a  system
employing  the  generating  unit  to  meet  peak demands for power.   The
reduced capacity of a unit corresponds to  the  energy  losses  incurred
during  full  capacity  operation.   A  further  reduction  in margin of
reserve generating capacity of a system will occur during  the  time  in
which  a  unit  must be shut down in order to complete the changeover to
the closed-cycle cooling system.  Many changeovers can  be  made  during
normal  periodic shutdowns for maintenance.  Incremental downtime due to
changeovers may be from 30 to 90 days for each unit.


In general, the monetary and energy consumption costs of  effluent  heat
reductions  of less than 100 percent would be approximately proportional
to the corresponding percentage reduction.  It must be noted that, while
fractional heat  removals  are  theoretically  achievable,  no  external
cooling  means  have teen employed to date to meet requirements based on
fractional  heat  removals  for   individual   units.    Moreover,   the
application  of  open  cooling systems to achieve significant fractional
heat removals would cause more damage  to  organisms  brought  into  the
cooling  water  system  than would a closed-cycle system for essentially
100 percent heat removal due  to  the  higher  volume  of  intake  water
required by the former.

The  following analysis of the monetary, energy consumption and capacity
loss costs of external cooling systems are based on the  requirement  of
the guidelines that blowdown is permitted only from the cold side of the
external  cooling  means.   On  the  conservative  assumption  that  all
external cooling means already employed on existing  units  provide  for
blowdown  from  the hot side, then the incremental costs associated with
requiring blowdown from the cold side of the external cooling  means  of
these  units  would  be  a  fraction  of  the total cost of the required
external cooling means, said fraction being approximately the  ratio  of
the  present  blowdown  flow  rate  to  the  total flow rate through the
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condensers, neglecting drift loss effects.  This fraction   is   typically
less than 2 percent.

The  average  incremental  costs  of the application of  mechanical  draft
evaporative cooling towers to base-load units to achieve no discharge of
heat except for blowdcwn are estimated to be as follows:

1.production costs:   14 percent of base

2.capital costs:   12 precent of base

3.fuel consumption:  2 percent of base

4.capacity reduction:  3 percent of base

Incremental dollar costs for cyclic units are higher by  about  20S5,  while
fuel consumption and capacity reductions are the same as  for   base-load
units.   Incremental  production costs for peaking  units are about  three
times the costs for base-load  units.   Incremental  capital  costs are
about  40%  higher than  for  base-load units, and fuel consumption and
capacity reductions are the same.

The  average  incremental  costs  versus  effluent  reduction    benefits
 (dollars/unit  heat removed) for cyclic units are about  double those for
base-load units, except for fuel consumption which  is invariant with the
degree  of  utilization.   Average  incremental  costs   versus  effluent
reduction benefits for peaking units are about three to  four times  those
for cyclic units.

For  new  sources  for base-load, cyclic and peaking units  respectively/
the average incremental production costs are 10, 11 and  28 percent  of
base  costs;  the  incremental capital costs are 9,  10, and  11  percent of
base costs, the fuel consumption costs are all  1 percent of  base  fuel
consumption,  and  the generating capacity reduction is 0 to 2  percent of
base capacity depending on  whether  the  capability  to overdesign  is
considered.

The  above  costs  for non-new sources do not reflect the exemptions from
the no discharge limitation for units for  which  insufficient  land  is
available  for  the construction of mechanical  draft evaporative cooling
towers or for which salt water drift precludes  their use.   The  analyses
on  which  the cost estimates are based assume the  application of state-
of-the-art technology for drift elimination, but do not  assume  purchase
of  land.  The factors of adverse climate, fogging  and icing,  and noise,
while  possibly  adding  marginal  costs  where  additional levels  of
technology  are  required  for  control, are not national-scale factors.
Since the overall  costs and the land availability   and   saltwater  drift
factors  are  based on mechanical draft evaporative cooling towers, with
incremental costs  for plume abatement, etc. if required,  the   potential
aesthetic  factors associated  with the tall structure  of  natural  draft
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towers, with spray ponds, with cooling  ponds,  or  with  cooling  tower
plumes have been indirectly taken into account.

While  the  mechanical draft evaporative cooling tower was selected as a
model for the cost analyses because  of  its  widespread  use  and  more
universal  applicability,  this  in  nc  way precludes the actual use of
other technologies to achieve the effluent limitations.

The costs of  other  external  evaporative  systems  for  effluent  heat
reduction  are  generally  comparable  to  the costs of mechanical draft
evaporative cooling tcwers.  Site-dependent factors, however, could tend
to increase some costs and lower others significantly depending  on  the
location  involved.   Costs  that  would  be  incurred and corresponding
effluent reduction benefits for  units  already  planning  or  employing
closed-cycle  cooling  systems would be zero or relatively insignificant
depending upon whether the  blowdown  is  from  the  cold-side  or  not.
However,  in  the  case  of hot-side blowdown, the costs versus effluent
reduction benefits related to  achieving  cold-side  blowdown  would  be
approximately  in  the   same  proportion  as  the  costs versus effluent
reduction benefits for achieving closed-cycle cooling for  an  otherwise
similar unit with an open cooling system.

Energy and Other Nonwater Quality Environmental Impacts Impacts.

Energy

The  incremental  energy  (fuel)  consumption  costs of mechanical draft
evaporative cooling tcwers applied to existing units are typically about
1 to 2 percent of the energy generated or fuel consumed.   Corresponding
costs of unassisted natural draft cooling towers and of spray canals and
ponds  are  lower  by an increment of approximately 1/2 percent or less.
Fuel consumption costs for unaugmented cooling lakes are lower by  about
1/2  percent.  The energy costs of mechanical draft dry  (nonevaporative)
cooling towers are higher by  an  increment  of  more  than  2  percent.
Energy   (fuel)  consumption costs of applying these closed-cycle cooling
systems to new units would be less due to the opportunity  provided  for
overall optimization cf  the process as well as the cooling system.

A typical existing generating unit to which mechanical draft evaporative
cooling towers would te  applied for essentially 100 percent reduction of
effluent  heat  would  be reduced in generating capacity by about 3 to 4
percent of its  former   capacity  during  part  of  the  year.   Reduced
capacity  corresponding  to  other types of cooling employed at existing
units would be approximately proportional to the fuel  consumption  cost
percentages  cited  above.   For  new units no capacity loss would occur
since the unit would be  oversized to make up for this  factor.

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.
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Reduced margins of reserve capacity  due  to  lost   generating  capacity
could  be  significantly  offset by delayed retirements,  but not without
some added generating costs due to  the  relative  inefficiency  of   the
older  units.   The  installation of combustion turbines  to  replace  lost
capacity can be accomplished relatively quickly.   Eventually  the   lost
capacity  could  be replaced by the construction of  new highly-efficient
base-load units.

Potentially, the construction of additional transmission  lines and other
efforts to achieve higher degrees of regional and  national   reliability
coordination  could  completely  offset  the  reduced margins of reserve
capacity due to lost  generating  capacity.   Furthermore,   citizen   and
other  user  efforts  to  reduce consumption during  the brief periods of
peak demand could significantly lessen the  impact   of  reduced  reserve
margins.   The  above  factors are especially significant in the case of
the numerous units in small plants and  systems  where  the   engineering
design manpower requirements would be high relative  to the heat removals
achieved, the availability of capital would be somewhat lower due to the
smaller  amounts  and  higher risks involved, and the possible impact of
reduced reserve capacity would be larger due to the  relatively  limited
extent of the systems.

Other Non-Water Quality Environmental Impacts

Non-water  quality  environmental  impacts  of  external  thermal control
technology  include  possible  effects  of  salt  water   drift  (droplet
carryover  from evaporative towers and spray systems) , increased fogging
or water consumption with evaporative systems, noise if mechanical draft
towers are adjacent tc populated areas, and increased aesthetic  impacts
due  to  the  size  of  natural draft towers and visible  plumes from all
evaporative towers.  The potential effects of salt water  drift have  been
taken into account by the exemption provided in the  guidelines from  the
no  discharge requirements in instances in which it  is likely to present
a significant problem.

However, in the limited number of cases  where  it   would be  required,
technology  is  available to reduce or eliminate drift, fogging, visible
plumes and noise effects, and water  consumption  rights  are  available
where  required,  each  at  incremental costs above  standard evaporative
cooling systems for closed-cycle cooling.

Economic Impact Including Impact on U.S. Fuel Consumption

The  proposed  effluent  limitations  are  based  on the technological
capabilities  of  steam electric powerplants.  Section 316(a)  of the Act
allows for  exemptions  to  the  proposed  limitations  on   heat, in  a
case-by-case basis, based on the consideration of environmental need.

It  has  been  estimated,  based  on  an analytical  model of the cooling
capacity of U.S. rivers and from a survey  of  EPA   regional  personnel,
                                 462

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that   approximately  one-half  to  two-thirds  of  the  steam  electric
powerplants (by capacity) not already achieving "no  thermal  discharge"
are  not  now in violation of present or projected thermal environmental
criteria.   Of  the   remainder,   "no   discharge"   thermal   controls
corresponding  to generally one-half of the capacity at each plant would
be warranted during certain parts of the year,  based  on  environmental
considerations.  It is further estimated that generally thermal controls
would  be  needed during 3-4 months of the year, or approximately 3055 of
the time, scattered, in the aggregate, year round.

Approximately 20% of existing steam electric powerplants already achieve
"no thermal discharge." A significantly larger percentage (over 50%)  of
plants  that  are  not considered "new sources" under the definitions of
the Act but will begin initial operation in the period 1974 -  1982  are
already committed to closed cooling systems.

By  1980 approximately 30% of all U.S. energy uses has been projected to
be through electrical generation.  The electrical  generation  processes
have  been  projected by one source tc be comprised of approximately 40%
coal-fueled, 25% nuclear, 15% oil-fueled, 15% gas-fueled  and  5%  hydro
and geothermal plants.  Approximately 50% of all coal is projected to go
to powerplants, 15% of all natural gas, and 10% of all oil.

Incremental  fuel  consumption  due  to  closed cooling water systems at
steam electric powerplants is due to the power  required  to  drive  the
pumps  and  fans   (if they are employed) in the closed system and to the
reduced energy conversion efficiency brought about by changes  in  steam
condensing pressures.  Generally the increased fuel consumption relative
to  base  fuel  consumption would be approximately 1% for pumps and fans
 (if they are employed) and 1% for changing steam  pressures.   Mechnical
draft  evaporative  ccoling  towers  are  the most widely used means for
achieving closed-cycle cooling.  They employ both pumps and fans.  Other
means commonly employed  use no fans  (natural draft towers, spray canals,
cooling   ponds)   or    no   additional   pumping     (cooling    ponds) .
Environmentally-based    thermal  effluent  limitations  may  be  met  by
open-cycle systems, that cause no loss in energy  conversion  efficiency
due  to  changing steam  pressures and which use the preceeding means and
others.

Assuming equal  environmentally-based  thermal  controls  regardless  of
fuel, no net changes in  generating distribution among the fuels used and
use  of  mechanical  draft cooling towers  (highest fuel consumption) the
above numbers translate  into a  0.12%  increase  in  nuclear  fuel  con-
sumption  to  meet theriral controls, a 0.06% increase in total U.S. coal
consumption, a 0.02% increase in total U.S. natural gas consumption  and
a 0.01% increase in tctal U.S. oil consumption, by 1980.

The  estimated  economic  impact  by  1983,  of  the  proposed  effluent
limitations guidelines,  considering the estimated effect  of  exemptions
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to  be  allowed  through  appeals under section  316(a)  of the Act are as
follows:

1.Total capital required is $12.0 billion which   is   3.3%   of   the  base
capital required.

2.Cost  to consumers vould reach $4.1 billion per year, which is  3.6% of
the base cost to consumers.

3.Price increase by 0.9 mills per kwh, or 1.2% of base  production costs.

4.Fuel consumed would reach a level equivalent to 9 million tons  of  coal
per year, or 0.2% of U.S. consumption for all purposes.

5.Capacity loss of 3,300 MW, or 0.4% of U.S.  generating capacity.

Similarily for new sources, between 1985  and  1990,  the   above   costs,
respectively, are $11.8 billion (2.0% base), $1.7 billion per year (Q.1%
base),  0.05  mills per KWH (1.4% base production costs), 8 million  tons
per year  (0.12% base), and 3,100 MW (0.25% base).
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                               SECTON XII

                            ACKNOWLEDGEMENTS

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 follwing individuals:

    Sharon As he. Effluent Guidelines Division
    Chris Miller, Effluent Guidelines Division
    Marilyn Moran, Burns and Roe, Inci
    Kaye Starr, Effluent Guidelines Division
    Nancy Zrubek, Effluent Guidelines Division
    Edwin L. Stenius,  Burns and Roe, Inc.

The  contribution of Ernst P. Hall, Deputy Director,  Effluent Guidelines
Division, were vital to the timely 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 Development Branch, EGD
    Dr. Clark Allen, Region VI
    Alden Christiansen, National Environmental Research
      Center, Corvailis
    Swepe Davis, Office of Planning and Management
    Don Goodwin, Office of Air Quality Planning and Standards
    William Jordan, Office of Enforcement and General Counsel
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    Charles Kaplan, Region IV
    Steve Levy,  Office cf 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 Management
    Howard Zar,  Region V

Also acknowledged are the contributions of Dennis Cannon,
Michael LaGraff, Ronald McSwiney, and Lillian Stone, all
formerly with the Effluent Guidelines Division.

Other EPA and State personnel contributing to this effort were:

    Allan Abramson, Region IX
    Ken Bigos, Region IX
    Carl W. Blomgren, Region VII
    Danforth G.  Bodien, Region X
    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
    Joseph Hudek, Region II
    William R. Lahs, Office of Radiation Programs
    John Lum, Region II
    Dr. Guy R. Nelson, National Enviornmental Research Center,
      Corvallis
    Courtney Riordan, Office of Technical Analysis
    William H. Schremp, Region III
    Edward Stigall, Region VII
    Dr. Bruce A. Tichener, National Environmental Research
      Center, Corvallis
    Srini Vasan, Regicn V

Other Federal agencies cooperating were:

    Atomic Energy Comnrission
    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
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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 and  regional  systems  for  their  cooperation  and
assistance   in   arranging   plant   visits  and  furnishing  data  and
information.

    Alabama Power Company
    Canal Electric Conrpany
    Central Hudson Gas and Electric Corporation
    Commonwealth Ediscn Company
    Consolidated Ediscn Company of New York, Inc.
    Consumers Power Company
    Duke Power Company
    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 Pocl
    New York State Electric and Gas Corporation
    Niagara Mohawk Power Corporation
    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
    Public  Service Company of Colorado
    Public  Service Electric and Gas Company
    Sacramento Municipal Utility District
    Southern California Edison Company
    Taunton, Massachusetts Municipal Light Plant
    Texas Electric Service Company
    Virginia Electric and Power Company

 Acknowledgement is also made to the following  manufacturers  for  their
 willing  cooperation  in  providing  information needed  in the  course of
 this  effort.

    Allen-Sherman-Hoff
    Butterworth Systeir  Inc.
    Ceramic Cooling  Tower Company
    Ecodyne Corporation
    General Electric Company
    Inland  Environmental
    Research-Cottrell,  Inc., Hamon Cooling Tower,  Division
    Resources Conservation Company
    .Richards of Rockfcrd, Inc.
    Ste phen s- Adamson
    The Marley Company
                                 467

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                                  470

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                                  471

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38. "Canals Cool Hot Water for Reuse", Environmental  Science
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41. Christopher, P. J. and Forster, V. T., "Rugeley Dry  Cooling
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42. Christiansen, A. G. and Tichenor,  B. A.,  "Economic Aspects
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44. "Clean-Air Route Has Made-In Mexico Label", Chemical
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48. Collins, W. D.,  "Temperature of Water  Available for
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                                  472

-------
50. Control of Air Pollution from Fossil Fuel-Fired Steam
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52. Cooling Tower Fundamentals apd Application Principles,
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53. "Cooling Towers - Part II, Are Hyperbolics a Waste of
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54. "Cooling Towers - Part III, Drying Up the Cooling Cycle",
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55. "Cooling Towers", Power Engineering, pp. 30-37,
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56. "Cooling Towers", Power Special Report, Power,  (March 1973).

57. "Cooling Towers - Special Report", Industrial Water
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58. Cost of Wastewater Treatment Processes, Robert A. Taft
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59. Cox, R. A.,  "Predictions of Fog Formation Due to A Warm
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60. Culp,  R. L.,  "The Operation of Wastewater Treatment  Plants",
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61. Cumulative  Research  Index to FPC Recorts, Vol.  19-35,
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63. Cywin, A.,  "Engineering  Water Resources of  the Future",
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64. Cywin, A.,  "Engineering  Water Resources  for 2070",
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                                  473

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65.  Dallarie, E. E., "Thermal Pollution Threat Draws  Nearer",
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66.  Davis, J. C., "Scrubber-Design Spinoffs  from Power  Plant
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67.  Dean, J. G., et al, "Removing Heavy Metals from Wastewater",
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68.  Decker, F. W., "Report on Cooling Towers  and Weather"
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69.  De Filippi, J. A. , "Designing Filtration  Plant Waste
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70.  De Flon, J. G., "Design of Cooling Towers Circulating
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71.  DeMonbrun, J. R., "Factors to Consider in Selecting a
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72.  Derrick, A. E., "Cooling Pond Proves to be the Economic
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73.  Development and Demonstration of Low-Level Drift
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74.  Dickey, J. B., Jr., "Managing Waste Heat  with the Water
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75.  "Directory", Public Power, Vol. 31, No.  1, (January -
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76.  "Dive Into Those Intakes", Electric Light &  Power,
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77.  Donohue, J. M. and Woods, G. A., "Onstream Desludging
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78.  Doran, J. J., Jr,, "Electric Power - Impact  on the
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79.  Drew, H. R. and Tilton, J.,  "Statement of the Electric
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                                  474

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80. Drew, H. R. and Hilton, J.f "Review of Surface Water
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81. Drew, H. R. and Tilton, J. E.,  "Thermal Requirements
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82. Eckenfelder, W. W., Jr. and Barnard, J. L., "Treatment -
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83. Eckenfelder, W. W., Jr. and Ford, D. L.,  "Economics of
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81. Edinger, J. E. and Geyer, J. C., Heat Exchange in the
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85. Edinger, J. E., et al, "The Variation of  Water Temper-
    atures Due to  Steam Electric Cooling Operations",
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86. Electric Power Statistics, Federal Power  Commission,
     (January 1972) .

87. Electric Utility  Depreciation  Practices,  Federal Power
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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.

89. Electrical Power  Supply and Demand Forecasts  for the
    United  States  Through 2050, Hittman Associates, Inc.,
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90. Electrical WorlcU Directory of Electric Utilities,
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91. Eller,  J., et  al, "Water  Reuse and Recycling  in
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92. Elliott, T. C.,  "Options  for Cooling Large  Plants  in
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                                   475

-------
93.  "Energy Crisis", Consulting Engineer, pp. 97-192,
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94.  Engineering Aspects of Heat Disposal from Power
    Generation, Summer Seminar Program, MIT,  (June 26-30, 1972).

95.  Engineering for Resolution of the Energy - Environment
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96.  Environmental Effects of Producing Electric Power:
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    (October, November 1969 and January and February 1970).

97..  Environmental Protection Research Catalog, EPA, Office
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98.  Estimating Costs and Manpower Requirements for Con-
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99.  Evans, D. R. and Wilson, J. C., "Capital and Operating
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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
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      Vol. 2,  (November 1967) .

102.  Fairbanks, R. B., et al, "An Assessment of the Effects of
      Electrical Power Generation on Marine Resources in the
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103.  Farrell, J. B., et al, "Natural Freezing for Dewatering
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104.  Feasibility of Alternative Means of Cooling for Thermal
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       (September 1970).""
                                  476

-------
105.  Feige, N. c.. Titanium Tubing  for Surface Condenser
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106.  Feige, N. C., "Titanium Tubing Proves  Value  in  Estuary
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107.  Ferrel, J. F.,  "Sludge Incineration",  Pollution
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108.  Final Environmental  Statement, USAEC.  Directorate  of
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    a)  Arkansas Nuclear One Unit  1
        Arkansas Power 6 Light  Co.,  (February 1973).

    b)  Arkansas Nuclear One Unit  2
        Arkansas Power & Light  Co.,  (September 1972).

    c)  Davis-Bessee  Nuclear Power Station
        Toledo Edison Company  & Cleveland Electric
        Illuminating  Company,  (March 1973).

    d)  Duane  Arnold  Energy Center
        Iowa  Electric Light &  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) .

    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).
                                  477

-------
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 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).

x)  Three Mile Island Nuclear Station Units 1 and  2
    Metropolitan Edison Company, Pennsylvania Electric
    and Company, Jersey Central Power and Light  Co.,
    (December 1972) .

y)  Turkey Point Plant
    Florida Power and Light Co. ,  (July 1972) .
                               478

-------
   zj   Vermont Yankee Nuclear Power Station
        Vermont Yankee Nuclear Power Corporation, (July 1972).

  aa)   Virgil C.  Summer Nuclear Station Unit 1
       South Carolina Electric £ 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)   Monticello Nuclear Generating Plant
        Northern States Power Company,   (November 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.r "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. 40,
      No. 5, Part 1, pp. 779-788,  (May  1968).

114.   Gambs, G. C. and Rauth, A. A., "The Energy Crisis",
      Chemical Engineering, pp. 56-68,  (May  31, 1971) .

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.   Garton, R. R. and Christiansen, A.  G.,  "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) .
                                  479

-------
117.  Garton, R. G. and Harkins, R. D., Guidelines:
      Biological Surveys at Proposed Heat Discharge Sites
      EPA Water Quality Office, Northwest Region.  (April 1970)

118.  Gartrell, F. E. and Barber, J. C., "Environmental
      Protection - TVA Experience", Journal of the Sanitary
      Eng. 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, (May 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 Kelleher, P. J., "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 K., "Control Cooling Water Deposition",
      13th Annual International Water Conference,
      (October 28-30, 1969) .

126.  Hall, W. A., Coding Tower Plume Abatement, Chem. Enq.
          [. , Vol.  67, No.  7,  (July 1971)..
127.  Handbook for Analytical Quality Control in Water and
      Wastewater Laboratories, Analytical Quality Control
      Laboratory, National Environmental Research Center,
      Cincinnati, Ohic.   (June 1972) .

128. Hansen, E. P. and Gates, R. E., "The Parallel Path
      Wet-Dry Cooling Tower", The Marley Company,  (1972).

129.  Hansen, R. G., Knoll, C. R., and Mar, B. W., "Municipal
      Water Systems - A Solution for Thermal Power Plant
      Cooling?", Journal AWWA, pp. 174-181,  (March 1973).
                                  480

-------
Uo.   Hansen, s. p.. Gulp, G. L., and  Stukenberg, J. R. ,
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      Control Federation- Vol. 41, No. 8, pp. 1421- 1144,  (1969)
131.  Harris, P. J. ,  "A Case for Air-Cooling in Electric
      Power Generation", Gas S Oil Power f pp.  16-18,
      (January 1969) .           ~~      ~

132.  Hauser, L. G. ,  et al, "An Advanced Optimization
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      Combinations",  American Power Conference,  (1971).

133.  Hauser, L. G.  and Oleson, K. A., "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
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135.  Hauser, L. G. ,  "Cooling Water Sources for Power
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136.  Hauser, L. G. ,  "Evaulate Your Cost of Cooling Steam
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137.  Hill, R. D., "Mine Drainage Treatment, State of the Art
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138.  Hirayama, K. ,  and Hirano, R., "Influences of High
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139.  Hollinden, G.  A., and Kaplan, N.,  "Status of Application
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140.  Holmberg, J. D. and Kinney, O. L. , Drift Technology
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141.  Horlacher, W.  R., et al, "Four SO2 Removal  Systems",
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                                  481

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142.   Industrial Waste Guide on Thermal Pollutionf FWPCA,
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143.   Inorganic Chemicals Industry Profile, EPA, Water
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144.   "Reviewing Environmental Impact Statements: Power Plant
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145.   Jaske, R. T. and Reardon, W. A., "A Nuclear Future in
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146.   Jaske, R. T., "Heat as a Pollutant, Session 7, presented
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147.   Jaske, R. T., et al, "Heat Rejection Requirements of the
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148.   Jaske, R. T., "Is there a Future for Once-Through Cooling
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149.   Jaske, R. T., et al, "Multiple Purpose Use of Thermal
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150.   Jaske, R. T., et al, "Methods for Evaluating Effects of
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151.   Jaske, R. T., "Technical and Economic Alternatives in
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152.   Jaske, R. T., "Thermal Pollution and Its Treatment",
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                                  482

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153.   Jaske, R. T., "Use of Simulation in the Development of
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154.   Jaske, R. T., "Water Resoureces Problems in Meeting
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155.   Jaske, R. T., "Water Reuse in Power Production an
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156.   Jenson, L. D. and Brady, D. K., "Aquatic Ecosystems
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157.   Jimeson, R. M. and Chilton, C. H., "A Model for
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158.  Jimeson, R. M., and Adkins, G. G., "Factors in Waste
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159.  Jimeson, R. M. ,  "The  Demand for Sulfur  Control Methods
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160.  Jimeson, R. M.,  and Adkins, G. G., "Waste Heat Disposal
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161.  Jones, J.  W., Stern,  R. D., and Princiotta, F. T.,
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162.  Kaup, E.,  "Design Factors in  Reverse Osmosis", Chemical
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                                  483

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163.  Kelley, R. B., "Large-Scale Spray Cooling", Industrial
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164.  Kibbel, Jr., w. H., "Hydrogen Peroxide for Industrial
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165.  Kleinberg, B., "Introduction to Metric or Si", Civil
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166.  Kolflat, T. D., Cooling Towers - State of the Art,
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167.  "Kool-Flow Thermal Pollution Control", Richards of
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168.  Krieger, J. H. , "Energy:  "The Squeeze Begins", Chemical
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169.  Kumar, J., "Selecting and Installing Synthetic Pond
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170.  Lake Norman Hydro-thermal Model Study for Duke Power
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171.  LaMantia, C. R., "Emission Control for Small Scale
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172.  LaQue, F. L. and Cordovi, M. A., "Experiences with
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173.  Leung, Paul, "Cost Separation of Steam and Electricity
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174.  Leung, P., and Moore, R. E., "Thermal Cycle Arrangements
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175.  Li, K. W., Combined Cooling  Systems for Power Plants.
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                                  484

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176.   Lot, G. and Ward, J. c., "Economics of Thermal
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177.   Long, N. A., "Recent Operating Experience with Stainless
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178.   Long, N. A., "Service Conditions Influencing the Pitting
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179.   Loucks, C. M.,  "Boosting Capacities with Chemicals",
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180.   Lunenfeld, H.,  "Electric Power & Water Pollution Control".

181.   Lusby, W. S. and Somers, E. V., "Power Plant Effluent -
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182.   McCabe, W. L. and Smith, J. C., Unit Operations of
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183.   McKee, J. E. and Wolf, H. W., Water Quality Criteria,
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184.   McNeil, W. J.,  "Beneficial Uses of Heated Sea Water in
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185.   McNeil, W., "Selecting and Sizing Cooling Towers",
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186.   "Typical LWR Nuclear Plant Project Schedule,"
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187.   Kolflat, T., "Conventional Steam Cycle Unit Meets Need,"
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188.   Meeting the Electrical Energy Requirements for California,
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189.   Methods for Chemical Analysis of Water & Wastes. Clean
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                                  485

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190.  Metric Practice Guide,  (A Guide to the Use of Si - The
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191.  Mis so uri_ River Temperature Survey Near United Power
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192.  Moore, F. K. and Jaluria, Y., "Thermal Effects of Power
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193.  Moores, C. W. , "Wastewater Bi ©treatment:  What It Can
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194.  Morgenweck, F. E. , "Performance Testing of Large
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195.  Morse, F. T., Power Plant Engineering - The Theory  and
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196.  Motz, L. H., Benedict, B. A., Heated Surface Jet
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197.  "Nations Bulk Pcwer Systems Evaluated", National Electric
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198.  Nelson, B. D. , The Cherne Fixed Thermal Rotor System
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199.  Nester, D. M. , "Salt Water Cooling Tower", Chemical
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200.  "New Generating Capacity:  Who*s Doing What?", Power
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201.  Olds, F. C., "Capital Cost Calculations for Future
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202.  Oleson, K. A., et al, "Dry Cooling Affects More than Cost",
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                                  486

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203.   Olesonr K. A. and Budenholzer, R. J., "Economics of
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204.   Oleson, K. A. and Boyle, R. R., "How to Cool Steam
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205.   Papamarcos, J.,  "Spinning Disco, A Better Way to Cool
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206.   Park, J. E. and  Vance, J. M.,  "Computer Model of Cross-
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207.   Parsons, W. A. and Azad, H. S., "The Rationale of Zero
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208.   Patterson,  J. W. and Minear, R. A., Wastewater Treatment
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209.  Patterson,  W. D., et al, "The  Capacity of Cooling Ponds
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210.  Peterson,   D. E. and Jaske, R. T., "Potential Thermal
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211.  Peterson,  D. E.  and Jaske, R.  T., "Simulation Modeling
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212.  Peterson,  D. E.  and schrotke,  P-  M.,  "Thermal Effects
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213.  Peterson,  D. E., Sonnichsen, Jr., A.  M., et al,  "Thermal
      Capacity  of Our  Nation's Waterways",  ASCE Annual &
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214.  "Pilot Plant to  Upgrade Coal", Chemical  Engineering,
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215.  Pita,  E.  G. and  John, James E.A.,  "The  Use  of  Sprays and
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      Pollution", unpublished  report.
                                   487

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216.  Pita,  E. G., "Thermal Pollution - The Effectiveness of
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217.  Policastro,  A. J., "Thermal Discharges into Lakes and
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218.  Possible Impact of Costs of Selected Pollution Control
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219.  Potential Environmental Modifications Produced by Large
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220.  Potter, B. and Craig, T. L., "Commercial Experience with
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221.  "Power Gas and Combined Cycles: Clean Power from Fossil
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222.  "Power Plant Dry Cooling Tower Cost, Indirect Type",
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223.  "Predictions of Fog Formation Due to a Warm Water Lagoon
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224.  Prolected Wastewater Treatment Costs in the Organic
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225.  Rabb, A., "For Steam Turbine Drives... Are Dry Cooling
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226.  Rainwater, F. H., "Research in Thermal Pollution
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227.  Remirez, P., "Thermal Pollution: Hot Issue for Industry",
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228.  Sisson, William, "Langelier Index Predicts Water1s
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                                 488

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229.   Resort on Equipment Availability for the Twelve-Year
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230.   Review of Surface Water Temperatures and Associated
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231.   Key, G., Lacy, Vi. J. and Cywin, A., "Industrial Water
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232.   "Preliminary Cooling Tower Feasibility Study for John Sevier
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233.   "Steam Electric Plant Air and Water Quality Control Data
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234.   "Understanding the  'National Energy Dilemma1" Print
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235.   Rickles, R. N., "Waste Recovery and Pollution Abatement",
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236.  "Draft Development Document for Proposed Effluent
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237.  Roe, K. A., "Soire Environmental Considerations in Power
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238.  Rohrman, F. A., "Power Plant Ash as a Potential
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239.  Rossie, J. P.,  "Dry-Type Cooling Systems", Chemical
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                                489

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240.  Rossie, J. P., et al. Cost Comparison of Dry Type
      andjronyentionaj^Cooling Systems for Representative
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241.  Rossie, J. P- and Cecil, E. A., Researeh_on Dry-
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242.  Rossie, J. P. and Williams, W. A., "The Cost of
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243.  Rowe, W. H. and Laurino, R. R., "Design of Liquid
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244.  Ruckelshaus, W. D. and Quarles, J. R., "The First
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245.  Ryan, F. P-, "Condenser Retubed in 24 Days", Power
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246.  Ryan, P. J.  and Harleman, D. R. F., An Analytical
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247.  Ryan, W.  F., "Cost of Power".

248.  Schieber, J. R., "Control of Cooling Water Treatment  -
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249.  Schoenwetter, H., Cooling Tower, Condenser and Turbine
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250.  Schoenwetter, H. D.,  Indian Point Nuclear Station
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251.  Schoenwetter, H. D., Lgyett^Station Space Utilization
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                                  490

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252.   Schoenwetter, H.f Updated Site Selection Report
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253.   Schreiber, D. L., "Missouri River Hydrology  (Streamflow
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254.   Kettner, J.E.,  et al, "Sherburne County Generating
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255.   Schurr, S. H.,  Energy Research Needs,  Resources fo
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256.  Schuster, R., "The Year of the Gas Turbine", Power
      Engineering,  pp.  28-33,  (November 1970) .         "

257.  Seels, F. H., "Industrial Water Pretreatment",
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258.  Shafir,  S.,  "Industrial Microbiocides for Open
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259.  Shah, K. L. and Reid, G. W.,  "Techniques  for Estimating
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260.  Shirazi, M. A., "Dry Cooling  Towers  for Steam Electric
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261.  Shirazi, M. A. , Thermoelectric Generators Powered  by
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262.  Silverstein,  R. M. and Crutis, S.  D.,  "Controlling
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263.  Silvestri, Jr., G. J.  and Davids,  J.,  "Effects of  High
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264.  Simpson, R.  W.  and Garlow,  W.,  "Design of Settling Units
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                                   491

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265.   Site Selection Report for Nuclear Prelect No. 2
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266.   Skrotzki, B. G. A. and Vopat, W. A., Power Station
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267.   Slack,  A. V., "Removing S02 from Stack Gases,"
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268.   Smith,  R., "Cost of Conventional and Advanced
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269.   Smith,  E. C. and Larinoff, M. W., "Power Plant Siting,
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270.   Some Considerations in the Use of Cooling Water for
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271.   "Effects and Methods of Control of Thermal Discharges:
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272.   Sonnichsen, Jr. J. C., et al. Cooling Ponds - A Survey
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273.   Southwest Energy Study Water Pollution Aspects,
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274.   Standard Methods - Water and Wastewater, American Public
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275.   Standard of Performance for New & Substantially
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                                492

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276.  Statistics of Privately Owned Electric Utilities
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277.  Statistics of Publicly Owned Electric Utilities
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278.  Steam. Its Generation and Use,  The Babcock & Wilcox
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279.  Steam Electric  Plant Factors. National Coal Assoc.,
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280.  Steam Electric  Plant, Air and Water Quality Control,
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281.  Steam Electric  Plant Construction Cost and
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282.  Stille, M. M.,  "Tampa Electric  Goes Stainless",
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283.  Stockham, J., Cooling Tower Study , Report for EPA,
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284.  Stott, W. J.,  "Chemicals  for  Water Treatment",
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285.  Stumm, W. and Morgan, J.  J., Aguatic Chemistry,
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286.  Summary of Recent  Technical Information Concerning
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      Report 72-1,  (August 1972).

287.  Swengel, F. M. , "Quick-Start  and Cyclic Capacity  for
      the 70«s", Power Engineering, pp.  34-36,  (June 1971).

288.  Technical & Economic Feasibility of Non-Coastal Power
      Plant Siting in California, Summary, Assembly Science
      & Technology Advisory Council,  (June 1971).

289.  The Cherne Thermal Rotor  System, Cherne Industrial, Inc.
                               493

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290.   The Electricity Supply Industry. 22nd Inquiry, The
      Organization for Economic Co-operation and Development
      (1972).

291.   The Industrial Wastes Studies Program, Summary Report
      on the Steam Generation S Steam - Electric Power
      Generation, EPA, Office of Water Programs, Division of
      Applied Technology,  (January 31, 1972) .

292.   The 1970 National Power Survey, Parts I, II,III, and IV
      Federal Power Commission.

293.   "The Energy Crisis", Mechanical Engineering, pp. 29-36,
      (January 1973) .      ~~

294.   The Water Use and Management Aspects of Steam Electric
      Power Generation by the Consulting Panel on Waste Heat,
      report to the National Water Commission,  (May 1972).

295.   Thermal Effects and U. S, Nuclear Power Stations
      WASH-1169, Division of Reactor Development & Technology
      AEC, (August 1971) .

296.   Thermal Pollutien - 1968, Part 3 - Hearings before the
      Subcommittee on Air 6 Water Pollution of the Committee
      on Public Works United States Senate, 19th Congress,
      Second Session, Appendix 1,  (1968).

297.   Thermal Pollution - .1968, Part 4 - Hearings before
      the Subcommittee on Air and Water Pollution of the
      Committee on Putlic Works, United States Senate, 19th
      Congress, Second Session, Appendix 2, Index (1968).

298.   Thompson, A. R., "Cooling Towers, A Water Pollution
      Control Device", Chemical Engineering,  (October 14, 1968)

299.   Tichenor, B. A. and Christiansen, A. G., "Cooling Pond
      Temperature versus Size and Water Loss", Journal of the
      Power Division  (July 1971) .

300.   Toone, D. E., "Spray Pond Cooling Water Requires Careful
      Treatment", Plant Engineering,  (October 15, 1970).

301.   Twenty Fourth Survey of Electric Power Equipment,
      Organization for Economic Co-operation and Development,
      (1971).

302.   Uniform System cf Accounts Prescribed for Public
      Utilities and Licensees, Federal Power Commission  (1970).
                                494

-------
303.   Walko, j. F., "Controlling Biological Fouling in Cooling
      Systems", Chemical Engineering. Vol. 79, Part I, No. 24,
      pp. 128-132 and Part II, No.  26, pp. 104-108,  (October
      30, 1972/November 27,  1972) .

304.   Walters, M. L. , "Cooling Tower Maintenance Problems
      Caused by Water", N. Y. State Institutional Engineering
      Conference  (October 1970).

305.   Waste_Heat_from Steam-Electric Generating Plants using
      Fossil Fuels and Its Control. Technical Advisory and
      Investigations Branch, FWPCA, Dept. of the Interior
      (May 1968) .

306.   Waste Heat  Utilization, proceedings of the National
      Conference, sponsored  by Electric Power Council on
      the Environment and ORNL.  (October 1971).

307.   "Water Pollution Control", Chemical Engineering,
      Deskbook Issue, pp. 65-75,  (June 21, 1971) .

308.   Water Quality and Treatment.  McGraw-Hill Co., N. Y.
      Third Edition.

309.   Water Quality Standards Criteria Digest - A Compilation
      of Federal/State Criteria  on  Mixing Zones, EPA,
      (August 1972) ."

310.   Water Quality Standards Criteria Digest - A Compilation
      of Federal/State Criteria  on  Temperature. EPA,  (August 1972)

311.  "Water, Water Everywhere,  But not a Drop... For Cooling",
      Electric Light and Power,  pp. 31-35  (August 1972) .

312.  Weight, R.  H., "Ocean  Cooling Water System for 800 MW
      Power Station", Journal of the Power Division, proceedings
      of the American Society of Civil Engineers, pp. 1888-1
      thru 1888-17,  (December 1958) .

313.  Wilmoth, R. C. and Hill, "Neutralization of High  Ferric
      Iron Acid  Mine Drainage",  Robert A. Taft Water Research
      Center, Cincinnati, Ohio  (August 1970).

314.   Winkelman,  F. W., Modern Practices in  Handling the
      Pr-orh^j-g of rombustion from Coal Fired Steam  Generators
      Allen Sherman Hcff Company.

315.   Winkelman,  F. W., "Systems Available for Removing Oil
      Soot from  Precipitator Hoppers", Power.  (June 1972).
                                   495

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316.   Winiarski, L. D. and Byram, K. V., "Reflective Cooling
      Ponds", ASME Paper 70 WA/PWR-4.

317.   Winiarski, L. D. and Tichenor, B. A., "Model of Natural
      Draft Cooling Tower Performance", Journal of the  Sanitary
      Eng. Div.. ASCE, pp. 927-943,  (August 1970) .

318.   Woodson, R. D., "Cooling Alternatives for Power Plants",
      paper presented to Minnesota Pollution Control Agency
      (November 30, 1972) .

319.   Woodson, R. D., "Cooling Towers"

320.   World Power Data 1969, Federal Power Commission
      "(March 1972) .

321.   Wrinkle, R. B., "Performance of Counterflow Cooling
      Tower Cel1s", Chemical Engineering Progress
      Vol. 67, No. 7, (July 1971).       ~~

322.   Yarosh, M. M., et al. Agricultural & Aquacultural
      Uses of Waste Heat, Oak Ridge National Laboratory,
      ORNL 4997,  (July 1972) .

323.  Young, R. A., "Combined Treatment Answers - Two Problems
      Sewage Treatment and Cooling System", Pollution
      Engineering, pp. 28-29, (July 1972).

324.  Zanker, A., "Estimating Cooling Tower Costs from  Operating
      Data"-

325.  An  Evaluation of the Feasibility of Salt Water Cooling
      Towers for Turkey Point, Southern Nuclear Engineering,
      Inc.,  (February 1970).

326.  An  Evaluation of the Powered Spray Module for Salt
      Water Service for Turkey Point, Southern Nuclear
      Engineering, Inc.,  (May 1970)7

327.  Control of Thernral Pollution - A Preliminary Report,
      Struthers Research & Development Corp.,  (September  25,
      1968) .

328.  Perry, J. H., Editor, Chemical Engineers Handbook,
      McGraw Hill, 4th Edition, New York,  (1963).

329.  Lund, H. F., Industrial Pollution Control Handbook,
      McGraw-Hill Book Co., N. Y.  (1971).

330.  Iranzen, A. E., et al, "Tertiary Treatment  of Process
      Water", Chem. Eng. Prog., Vol. 68, No. 8,  (August 1972).
                                  496

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331.   Unit_Process Operating and Maintenance Costs for
      Conventional Waste^Treatment^Plants, u. S. Dept. of
      the Interior, FWQA, Cincinnati, Ohio  (June 1968).

332.   Smith, A. P. and Eacon, S. W., "Economic Boiler Makeup
      with Four-Bed Deionizer in Two Vessels", Power Engineering,
      (April 1973) .

333.   Sawyer, J. A.,  "New Trends in Wastewater Treatment and
      Recycle", Chem. Eng..  (July  24, 1972).

334.   "Pollution Control Cost", Chemical Week.  (June 1970).

335.   DeLorenzi, O.,  Editor, Combustion Engineering,
      Combustion Engineering Co.,  Inc.,  (1948).

336.  Freedman, A. J. and Shannon  J. E., "Modern Alkaline
      Cooling Water Treatment", Industrial Water Engineering,
      p. 31,  (January/February  1^73) .

337.  Disposal of Wastes from Water  Treatment Plants, AWWA
      Research Foundation Report,  Part  1 Journal AWWA,
      Vol.  61, No. 10,  p. 541,  Part  2,  Vol.  61, No. 11, p.  619,
      Part  3, Vol. 61,  No.  12,  p.  681,  Part  4, Vol. 62, No. 1,
      p. 63,  (October/November/December 1969 and January 1970) .

338.  Beychok, M. R.,  "Kastewater  Treatment", Hydrocarbon
      Processing,  (December 1971) .

339.  Oil-Water  Separator Process  Design,  Disposal  of Refinery
      Waste, Volume  on Liquid Wastes, API,  pp.  5-3  to  5-13,
       (1969) .

340.  Morrison,  J.,  "lilted-Plate  Separators for Refinery
      Waste  Water",  Oil  & Gas Journal,  (December  14,  1970).

341.  Pollution  Control,  "Methods  for Cleaning  Seas", Marine
      Enaineering/Log,  (July 1971).

342.  Wurtz, C.  B. and Renn,  C. E.,  Water  Temperatures  and
      Aquatic Life,  Report  No.  1,  The John Hopkins  University,
      Cooling Water  Studies for Edison  Electric  Institute,
       (June  1,  1965).

343.  Jensen, L.  D.,  et al, The Effects of Elevated Temperature
      Upon  Aquatic Invertebrates,  Report No. 4,  The John
      Hopkins University, Cooling  Water Studies for Edison
      Electric  Institute,   (September 1969).
                               497

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344.  Marks, D. H. and Borenstein, R. A., An Optimal Siting
      Model for Thermal Plants with Temperature Constraints,
      Report No. 6, The Johns Hopkins University, Cooling
      Water Studies fcr Edison Electric Institute,
      (August 1970) .

345.  Brady, D. K. and Geyer, J. C., Development of a General
      Commuter^Model £or Simulating Thermal Pishearges  in
      Three Dimensions, Report No. 7, The Johns Hopkins
      University, Cooling Water Studies for Edison Electric
      Institute,  (February 1972).

350.  Somers, E. V., et al, "Beneficial Uses of Waste Heat
      from Electric Pcwerplants for New Town Heating and
      Cooling", Scientific Paper 71-1E8-TECOL-P1, Westing-
      house Research Lafcrcatories, Pittsburgh, Pennsylvania,
      (May 19, 1971) .

351.  Beal, S. E. and Samuels, G., "The Use of Warm Water
      for Heating and Cooling Plant and Animal Enclosures",
      Oak Ridge National Laboratory  (June 1971).

352.  Use of Waste Heat for Greenhouse Heating and Cooling,
      Progress Report, Agricultural Resource Development
      Branch.

353.  Bond, B. J., et al, "Beneficial Uses of Waste Heat",
      TVA Projects Paper presented at the National Conference
      on Complete Water Reuse, Washington, D. C.  (April 23-27,
      1973) .

354.  Yar.osh, M. M., "Waste Heat Utilization", proceedings of
      the National Conference, Gatlinburg, Tennessee  (May 1972)

355.  Miller, A. J., et al, "Use of Steam-Electric Powerplants
      to Provide Thermal Energy to Urban Areas", Oak Ridge
      National Laboratory, Oak Ridge, Tennessee  (January 1971).

356.  Austin, G., et al, "Multilevel Outlet Works at Four
      Existing Reservoirs", Journal of Hydraulics Division,
      Proceedings of the ASCE,  (November 1969) .    ~"

357.  Preparation of Environmental Reports for Nuclear  Plants,
      Regulatory  Guide 4.2, U.  S. Atomic Energy Commission,
      Directorate of Regulatory Standards,  (March 1973) .

358.  The Fan-Assisted Natural^Draft Cooling Tower, Res earch-
      Cottrell, Inc., Hamon Cooling Tower Division, N.  J.
                                  498

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359.   Ford, G.  L. ,  "Combined Condenser Cooling System Ups
      Plant Availability",  Power Engineering.

360.   The Cherne Fixed Thermal Rotor System Demonstration,
      Interim Test Report,  Allen S. King Plant (August/
      October 1972).

361.   "Projected Steam Units 300 MW and Larger" Reported
      to FPC April 1, 1973  by Regional Reliability Councils
      in Response to Appendix A of Order 383-3.

362.   Kolflat, T.D.,  "Cooling Tower Practices" Power
      Engineering  (January, 1974).

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 Kearney, D. W., Plume Behavior
      and Potential Environmental Effects of Large Dry
      Cooling Towers, Final Report - Gulf General Atomic,
      (February 1973).

368.   Jedlicka, C.L., "Nomographs for Thermal Pollution
      Control Systems" U. 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 Selection,
      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 2-4, 1972.
                                   499

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372.   Jones,  D.B.  and W.E.  Wienie, "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 Blowdown "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).

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"zU.S. Environmental Protection
      Agency  (August, 1973).

380.   "Processes, Procedures and Methods to  Control Pollution
    z 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).
                                    500

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382.   "Processes, Procedures, and Methods to Control Pollution
      Resulting from All Construction Activity," U.S.  Environmental
      Protection Agency (October, 1973).

383.   Mercer, B.W. and R.T. Jaske, "Methods for Reducing
      Demineralizer Waste Discharges from Thermo-Electric
      Power Plants" Paper presented at National Conference
      on Complete Watereuse, sponsored by the America
      Institute of Chemical Engineers and the U.S.
      Environmental Protection Agency (April, 1973).

384.  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).
                                    501

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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 M/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 * 459).

Acid

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 havi-ng a pH of less  than
7.

Agglomeration

The  coalescence  of  dispersed   suspended  matter  into larger floes  or
particles which settle more rapidly.
 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.

 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 CaCO3_.
                                  503

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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.

Biocide

An agent used to control biological growth.

Bituminous

A  coal of intermediate hardness containing between  50  and  92  percent
carbon.
                                  504

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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 cf 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.
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.

 Brackish Water

 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.
                                   505

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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.
The charged particles in solution of an electrolyte which  are  positively
charged.

Carbonate Hardness

Hardness  of water caused by the presence of  carbonates  and  bicarbonates
of calcium and magnesiurr.

Chemical Oxygen Demand  (COD)

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.

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  vvater  flows at a low  velocity to allow settling of
suspended matter.
                                   506

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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.
Cgndensate 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    j
A device for converting a vapor into its liquid phase.
Construction
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.
A device for converting a vapor into its liquid phase.
Convection
The heat transfer mechanism arising from the motion of a fluid.
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 Lake
See Cooling Pond
Cooling Pond
A body of water in which warm water is cooled by contact with  air,   and
is either discharged cr returned for reuse.
Cooling Tower
A  configured  heat  exchange  device  which  transfers reject heat from
circulating water to the atmosphere.
                                   507

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Cooling Tower Basin

A basin located at the bottom of a  cooling  tower   for   collecting   the
falling water.


              Sstem
See Circulating Water System

Corrosion Inhibitor

A chemical agent which slows down or prohibits a  corrosion  reaction.

CQunterf low

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.   In this report, a facility operating between  2000  and 6000
hours per year.

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 tan gent ially,  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.

Deae ration

A process by which dissolved air and  oxygen  are stripped  from  water
either by physical or chemical methods.

De aerator

A  device for the  removal of oxygen, carbon dioxide  and  other gases from
water.
                                    508

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neqasification
The removal of a gas from a liquid.
Deionizer
A process for treating water by removal  of  cations  and anions.
Demineralizer
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.
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.
    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.
                                   509

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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. Well

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 Precipitator

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.

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  horizontal  layers  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  cr colloidal matter.

Fireside Cleaning

Cleaning of the outside surface of boiler tubes  and  combustion chamber
refractories to remove deposits formed during the combustion*
                                    510

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FlOC
Small  gelatinous  masses  formed  in  a  liquid  by  the  reaction  of  a
coagulant   added   thereto,   thru   biochemical   processes,   or   by
agg lome r ati on.
Flue Gas
The gaseous products resulting from the combustion  process after passage
through the boiler.
Fly. Ash
A  portion  of  the nen-combustible residue from a  fuel which is carried
out of the boiler by the flue gas